Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
222-138
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 23, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC L-112A PRUDHOE BAY UN BORE L-112A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/23/2025 L-112A 50-029-23129-01-00 222-138-0 N SPT 6468 2221380 2500 1575 2751 2696 2675 9 22 20 21 OTHER P Josh Hunt 3/25/2025 Required by Conservation Order 736 This is the MIT- TxIA combo 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN BORE L- 112A Inspection Date: Tubing OA Packer Depth 1559 2727 2671 2651IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH250325131935 BBL Pumped:2.3 BBL Returned:2.2 Wednesday, April 23, 2025 Page 1 of 1 9 9 9 9 9 9 999 999 99 9 9 9 9 ,$UHPHGLDOFHPHQW 2LOSURGXFHU James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 12:53:07 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 23, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC L-112A PRUDHOE BAY UN BORE L-112A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/23/2025 L-112A 50-029-23129-01-00 222-138-0 N SPT 6468 2221380 2500 1571 2769 2675 2651 6 9 7 9 OTHER P Josh Hunt 3/25/2025 Required by Conservation order 736 This is the MIT-T 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN BORE L- 112A Inspection Date: Tubing OA Packer Depth 1603 1620 1615 1614IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH250325131354 BBL Pumped:0.5 BBL Returned:0.5 Wednesday, April 23, 2025 Page 1 of 1 9 9 9 9 9 9 999 9 9 99 9 ,$UHPHGLDOFHPHQW 2LOSURGXFHU 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 12:50:15 -08'00' 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Wednesday, February 14, 2024 9:12 AM To:Regg, James B (OGC) Subject:FW: [EXTERNAL] RE: L-112A (PTD# 222138) CO736 PTing post packer squeeze Attachments:MIT PBU L-112 09-03-23.xlsx Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Wednesday, February 14, 2024 9:06 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: [EXTERNAL] RE: L‐112A (PTD# 222138) CO736 PTing post packer squeeze 10‐426 for L‐112A MIT‐T as requested. Thanks, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Supervisor Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, February 14, 2024 3:15 AM To: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: [EXTERNAL] RE: L‐112A (PTD# 222138) CO736 PTing post packer squeeze You don't often get email from oliver.sternicki@hilcorp.com. Learn why this is important CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. PBU L-112APTD 2221380 2 Oliver, Please submit a 10‐426 and reference that AOGCC. It seems implied that the line below would compel a witnessed MIT‐T. I will comment each line. 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: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Tuesday, February 13, 2024 2:32 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Tyson Shriver <Tyson.Shriver@hilcorp.com> Subject: L‐112A (PTD# 222138) CO736 PTing post packer squeeze Mel, I was reviewing the pressure test history on L‐112A (PTD#222138) post packer squeeze and found that an AOGCC witnessed MIT‐T wasn’t completed as they are typically done on CO736 cement jobs. There wasn’t one specified in the sundry request or approval though there was a passing non‐witnessed MIT‐T done on 9/3/23 to 4395 psi. Do you want us to submit a 10‐426 for the non‐witnessed test or do you want us to go set another plug and get an AOGCC witnessed test? Thanks, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Supervisor Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com 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. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2221380 Type Inj N Tubing 333 4520 4435 4395 Type Test P Packer TVD 6073 BBL Pump 1.2 IA 583 738 740 740 Interval O Test psi 1518 BBL Return 1.2 OA 0 0 0 0 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Hilcorp North Slope LLC Prudhoe Bay / PBU / L Pad Brenton Nicholson 09/03/23 Notes:MIT-T to comply with CO736 requirements Notes: Notes: Notes: L-112A Form 10-426 (Revised 01/2017)MIT PBU L-112 09-03-23 J. Regg; 2/14/2024 1-Oil producer 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 L-112A Set LTP, Acidize Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 222-138 50-029-23129-01-00 12138 Conductor Surface Intermediate Production Liner 6676 80 3074 9358 2996 11749 20" 9-5/8" 7" 2-3/8" 6683 36 - 116 35 - 3109 32 - 9390 8757 - 11753 36 - 116 35 - 2670 32 - 6723 6139 - 6682 11738 470 3090 5410 11780 None 1490 5750 7240 11200 10901 - 11749 3-1/2" 9.2# L-80 29 - 9176 6679 - 6683 Structural 3-1/2" Baker S-3 Packer 9118, 6468 9118 6468 Torin Roschinger Operations Manager Tyson Shriver tyson.shriver@hilcorp.com 907-564-4542 PRUDHOE BAY, Borealis 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 0028239, 0047449 29 - 6522 See Attached Fracture Treatment reports See Attached Fracture Treatment reports New Well 501 110 950 360 323-255, 323-508 13b. Pools active after work:Borealis Oil No SSSV Installed 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 7:45 am, Dec 20, 2023 Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643) Date: 2023.12.19 13:34:53 -09'00' Aras Worthington (4643) RBDMS JSB 122623 WCB 1-21-2025 CDW 01/16/2024 DSR-1/4/24 ACTIVITY DATE SUMMARY 8/30/2023 ***WELL S/I ON ARRIVAL*** MADE MULTIPLE BAILER & GAUGE RUNS TO RESTRICTION @ 3058'SLM, UNABLE TO WORK PAST(see log) ***WELL LEFT S/I ON DEPARTURE*** 8/30/2023 T/I/O= 886/1505/35 (FRACTURING) Assist SL / TBG Thaw - Pumped 0.95 bbls of 60/40 while trying to assist SL RIH. TBG Locked up. SL reached a depth of 3,100' MD. Pumped 3 bbls of 60/40 and 197 bbls of 190* Crude down IA. Pumped .75 bbls 60/40 meth down Tbg and Tbg pressured up. ***Job Cont to 08-30-2023 WSR*** 8/31/2023 ***Job Cont from 8-30-2023 WSR** Tbg Thaw (FRACTURING) Pumped 225 bbls 180*f crude down IA, attempted to pump down TBG with 60/40 methanol. Locked up after .15 bbls. Swapped to 2 % KCL- Pumped 205 bbls 2% KCL down IA. Pumped 5 bbls 60/40 methanol down TBG, followed by 77 bbls 180*f crude. Pumped 60 bbls crude down IA to FP. Pumped 13 bbls 60/40 methanol down FL to FP. Notified DSO of well status, RDMO SV, WV SSV = closed, MV = open, IA and OA = OTG, GLV = closed. FWHP's = 1929/1883/6 9/2/2023 T/I/O=600/400/0 (Assist Slickline) TFS U3. Pumped 74BBLS 2% KCL down TBG to load followed by 25 BBLS Crude for FP. Pumped 2.3 BBLS of crude down the TBG to pressure up post gas lift valve changeout to 4500 psi and monitor pressure. *Job continues to 9-3-23* 9/2/2023 ***WELL S/I ON ARRIVAL*** SET 3-1/2'' CAT STANDING VALVE IN DEPLOYMENT SLV @ 8757'MD PULLED RK-LGLV'S FROM ST#2(7710'MD), ST#3(6462'MD), & ST#4(4599'MD) SET RK-DGLV'S IN ST#4(4599'MD), ST#3(6462'MD), & ST#2(7710'MD) T-BIRD PERFORMED FAILING MIT-T (see log) ***WSR CONT ON 9-3-23*** 9/3/2023 *Job continues from 9-2-23* (Assist Slickline/ MIT-IA) TFS U3. Pumped 4.5 BBLS of crude down the TBG to pressure up for an MIT-IA MAP @ 4500 psi ****PASSED****. Reached test pressures at 2064 psi TBG, and 4497 psi IA. First 15 minutes TBG lost 0 psi, IA lost 93 psi. Second 15 minutes TBG lost 2 psi, IA lost 39 psi. ****PASSED**** Bled back 4.5 BBLS of crude to take the TBG and IA to starting pressures of 500/500 psi Pumped 1 bbls of Crude down TBG to reach test pressure of 3500 psi max applied for MIT T Initial pressure 1415/630/0 Starting pressure 3533/708/0 1st 15 min 3478/713/0 2nd 15 min 3456/713/0 *****PASSED***** Pumped 1.2 bbls of Crude down TBG to reach test pressure of 4500 psi max applied for MIT T Initial pressures 333/583/0 Starting pressures 4520/738/0 First 15 minutes 4435/740/0 Second 15 minutes 4395/740/0 ****PASSED**** WHP's=300/550/0 Well left in SL control upon departure Daily Report of Well Operations PBU L-112A Pumped 4.5 BBLS of() crude down the TBG to pressure up for an MIT-IA MAP @ 4500 psi ****PASSED****. Pumped 1 bbls of Crude down TBG to reach test pressure of 3500 psi max applied for MIT T Initial pressure 1415/630/0 Starting pressure 3533/708/0 1st 15 min 3478/713/0 2nd 15 min 3456/713/0 *****PASSED***** Daily Report of Well Operations PBU L-112A 9/3/2023 ***WSE CONT FROM 9-2-23*** T-BIRD PERFORMED PASSING MIT-IA (see log) PULLED 3-1/2'' CAT STANDING VLV FROM DEPLOY SLV @ 8757'' MD DRIFT 3-1/2'' GR, 272'' MONO PAK LTP w/ 2.25" PTSA STINGER DRIFT TO DEPLOY SLV @ 8746' SLM / 8757' MD SET NS 350-272 MONO-PAK LTP w/2.25'' PTSA, w/ 1.781'' RETREVABLE SEAL GUIDE INSTALLED(10.92' OAL) IN DEPLOYMENT SLV @ 8751' MD T-BIRD PERFORMED PASSING MIT-T TO 3500PSI(see t-bird log) EQ & PULLED 1.781'' RR PLUG/RSG FROM @ 8757'MD SET 2.70'' CAT STANDING VALVE ON LTP @ 8757'MD T-BIRD PERFORMED PASSING MIT-T TO 4500PSI (see t-bird log) PULLED 2.70'' CAT STANDING VALVE FROM LTP @ 8757'MD ***WELL LEFT S/I ON DEPARTURE*** 9/16/2023 Job Scope: L-112 Fracture Stimuilation: Complete Rig down & clean up on V-02. Mobilize All Frac Equipment from V-Pad to L-Pad. Spot (9) Frac Tanks in place. Spot two Sand Chiefs. Lynden Loading Frac sand From Super sacks on Z-pad to Bulk trucks, hauling to L-Pad & Filling SLB sand chiefs. Loaded total 32 sacks. Start loading Frac water. Job in Progress. 9/17/2023 Job Scope: L-112 Post CTD Fracture Stimuilation: Continue Loading 16/20 Proppant & Water. Make up Oil States Tree Saver.; Drift largest 1.65" Frac sleeve ball. SLB Rigging up Frac equipment and treating Iron. Running Lab tests on water. Job in Progress. 9/18/2023 Job Scope: L-112 Post CTD Fracture Stimuilation: Warm up Frac equipment & function test. RU LRS to IA & Test PRV to 4200 psi. Spot dirty Vacs, Test water on last two tanks. Prime Pumps & PT Treating lines to 9120 psi. PJSM with all involved in Frac, Hazards.Roles & responsibilities. Start Injection: Bring on pumps & drop 1.375" disolvable ball to close the toe and Treat out thru bottom sleeve #1 at 11,747' md. SD with 168 bbls away. ISIP-1883 psi no Inflection observed. Complete Inj with 296 bbls. Start Pad/Scour -Total 325 bbls Frac treatment per Pumping schedule for first stage. Pump 1-4 ppa of schedule. At the tail end of ppa 4 , Treating pressure and rate started jumping around, Attempts to bring on another pump were unsuccessful.Cut sand & Moved to Flush to avoid screen out, drop 1.50" ball pump down just above frac sleeve at 11,405' md. (Stage1 48,620 lbs pumped vs 93,000 lbs planned, just over 50%). Trouble shoot pumps, found rocks on the hopper screen. Discuss Plan forward. Line up Cement pump to seat ball & FP well. Unable to shift sleeve #2 . Made two attempts. Decision made to allow ball to dissolve and FP tomorrow. Clean up equipment. Secure well. Plan to screen sand tomorrow. Job in Progress. 9/18/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Frac FCO, Mill ball seats Unit Standing by for frac support. Released due to issues with frac, will return once Frac proceeds. ...Job Incomplete.... 9/18/2023 Assist Frac Maintain ~3900 psi on IA during frac operations Job Scope: L-112 Post CTD Fracture Stimuilation g Start Injection: Bring on pumps & dropjg 1.375" disolvable ball to close the toe and Treat out thru bottom sleeve #1 at 11,747' md. SD with 168 bbls away. ISIP-1883 psi no Inflection observed. Complete Inj with 296 bbls Warm up Frac equipment & function tes (g) PULLED 3-1/2'' CAT STANDING VLV FROM DEPLOY SLV @ 8757'' MD @ SET NS 350-272 MONO-PAK LTP w/2.25'' PTSA, w/ 1.781'' RETREVABLE SEAL g g Cut sand & Moved to Flush to avoid screen out, drop 1.50" ball pump down just above frac sleeve at 11,405' md.(Stage1 48,620 lbs pumped vs 93,000j lbs planned, just over 50%). Daily Report of Well Operations PBU L-112A 9/19/2023 Job Scope: L-112 Post CTD Fracture Stimuilation: Clean out & inspect all 4 frac pumps. Replace Valves and seats as necessary on 3 out of 4 pumps. One pump clear of rocks or debris. Clean out all 4 suction headers, minimum debris found. Rig up SLB hopper with 8 mesh screens. Sieve sand from the sand chiefs to to bulk truck through the screens. Continue sand screening through the night. Job in Progress. 9/20/2023 Job Scope: L-112 Post CTD Fracture Stimuilation: Continue sand screening. Moving sand from the sand chiefs to bulk trucks. The vibrator broke on the sand hopper. Discuss Plan forward with SLB. Spot Vac truck with 3% KCL. Pressure up the IA to 3500. Pump KCL to Sleeve #2, FP to 2500' Job in Progress. 9/21/2023 Job Scope: L-112 Post CTD Fracture Stimuilation: Cont Pumping 70 bbls 3% KCL to frac sleeve #2 at 11,405' md. Followed by 21 bbls diesel FP to 2500' .. Moving sand from the sand chiefs to bulk trucks. Job in Progress. 9/21/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Assist with Frac Standby for Frac assist ***Continued on 09/22/23*** 9/22/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Assist with Frac Standby for Frac assist ***End Standby*** 9/25/2023 T/I/O=443/576/8 Injectivity Test Pump 1.5 bbls diesel down tbg to 3500 psi. SD, monitored pressure falloff-- 400-500 psi per min. Pressuured up OA to 1800 psi with 2 bbls diesel. Pumped 2 bbls diesel down tbg from 446 psi to 4200 psi. Monitored pressure falloff-- ~ 300 psi per min 9/28/2023 T/I/O = 429/1005/6 (FRACTURING) Injectivity Test - Pumped 1.7 bbls down TBG to 3500 psi. SD. Monitor pressure fall off (370 psi per min). Pressured up IA to 2000 psi with 1.1 bbls of DSL. Pumped 2.9 bbls down TBG to 4200 psi. SD. Monitor pressure fall off (418 per min). Pumped 1.8 bbls down TBG to 4100 psi. Reduced rate to .20 BPM for 15 bbls to establish injection rate. SD. Bled TBG down FL. Pump 3 bbls down TBG to 4100 psi. Monitor pressure fall off (362 psi per min). Pumped 13 bbls of 60/40 down FL for FP. FWHP = 478/981/5 9/30/2023 T/I/O = 531/1132/5 (POST FRACTURING) Injectivity Test - Pump 2 bbls down TBG to pressure to 3500 psi, Established LLR of 0.2 BPM @ 3500 psi,Monitor pressure fall off 357 psi per min. Pressured IA to 2000 psi. Pump 2 bbls down TBG to 4200 psi, SD. Monitor pressure fall off, 422 psi per min. similar results to 09-28-2023 tests. FWHP = 654/1108/6 10/1/2023 T/I/O = 583/1167/3 - (POST FRACTURING) Injectivity Test. Pump 1.8 bbls of DSL down TBG to reach 3500 psi. Confirmed LLR of 0.2 BPM @ 3500 psi. SD. Monitor pressure fall off for 5 min, lost 1540 psi total, 308 psi lost per min. Pressure IA to 2000 psi. Pump 4.1 bbls fo DSL down TBG to pressure TBG to 4200 psi. Confirmed LLR of 0.2 BPM @ 4200 psi. SD. Monitor pressure fall off for 5 min, lost 1893 psi total, 379 psi lost per min. FWHP = 604/1173/5 Daily Report of Well Operations PBU L-112A 10/2/2023 ***WELL S/I ON ARRIVAL*** DRIFTED 3' x 1.25" STEM, AND 1.75" SAMPLE BAILER, TAG @ 9486' SLM (no sample) SET 3 1/2" WHIDDON CATCHER (62" OAL) ON LTP @ 8743' SLM PULLED ST#3 RK-DGLV FROM 6462' MD PULLED ST#4 RK-DGLV FROM 4599' MD SET ST#4 RK-LGLV (16/64'' ports, tro1450#psi) @ 4599' MD ***WSR CONT ON 10-3-23*** 10/3/2023 LRS Test Separator 6 Begin WSR 10/3/23, Spot in, Rig Up, PT, POP Well. Continue WSR 10/4/23 10/3/2023 ***WSR CONT FROM 10-2-23*** SET ST#3 RK-OGLV (20/64'' ports) @ 6462' MD PULLED 3-1/2'' WHIDDON CATCHER FROM 8739' SL (empty) ***JOB COMPLETE, WELL LEFT S/I*** 10/4/2023 LRS Test Separator 6 Continue WSR from 10/3/23, Spot in, Rig Up, PT, POP Well. SLBU Procedure. Continue WSR on 10/5/23 10/5/2023 LRS Test Separator 6 Continue WSR from 10/4/23, Spot in, Rig Up, PT, POP Well. SLBU Procedure. Continue WSR on 10/6/23 10/6/2023 T/I/O = 1139/1264/0 (INJECTIVITY/STEP RATE TEST) - Pump 22 bbls crude down TBG to 3000 psi. Reduced rate to find injectivity. Injection rate was between 0.12 - 0.2 bpm @ 3000 psi. Pad op notified upon departure. FWHP = 2146/1270/0 10/6/2023 LRS Test Separator 6 Continue WSR from 10/5/23, Spot in, Rig Up, PT, POP Well. SLBU Procedure. Continue WSR on 10/7/23 10/7/2023 LRS Test Separator 6 Continue WSR from 10/6/23, Spot in, Rig Up, PT, POP Well. SLBU Procedure. Continue WSR on 10/8/23 10/8/2023 T/I/O = 1165/1216/0 LRS 72 Injectivity Test (FRACTURING) ***Job Continued to 10- 09-2023*** 10/8/2023 LRS Test Separator 6 Continue WSR from 10/7/23, Spot in, Rig Up, PT, POP Well. SLBU Procedure. Continue WSR on 10/9/23 10/9/2023 LRS Test Separator 6 Continue WSR from 10/8/23, Spot in, Rig Up, PT, POP Well. SLBU Procedure. Continue WSR on 10/10/23 10/9/2023 ***Continue Job from 10-08-2023*** Injectivity Test (FRACTURING) Pumped 29 bbls Crude into TBG to reach 3000 psi. Performed Fall Off test and established a LLR of 0.14 bpm (rate taken from tank strap(titan)). Well Testing in control of well and pad op notified upon LRS departure. 10/9/2023 T/I/O TFS unit 3 to FP L-250 FL for Well Testers Pumped a total of 9 bbls of 60/40 to FP FL, pressured FL to 1500 psi per PO 10/10/2023 LRS Test Separator 6 Continue WSR from 10/9/23, Weather STBY, Begin STBY for CTU. Continue WSR on 10/12/23 10/10/2023 L-112 (stand by for weather) TFS unit3 10/10/2023 T/I/O = 1389/1759/0 LRS 72. Assist Coil (FRACTURING) Pumped 49 bbls Crude into IA to load. ***Job Continued to 10-11-2023*** 10/11/2023 LRS Test Separator 6 Continue WSR from 10/10/23, STBY for CTU. Continue WSR on 10/12/23 10/11/2023 T/I/O = SSV/790/0+. Temp = SI. Bleed IAP (assist CTU). ALP = 1860 psi, SI @ CV. IA FL @ 260' (3 bbls). Bled IAP to L-206 production from 790 psi to 600 psi in 1.5 hr (FTS). Monitored for 30 mins. IA FL @ surface. IAP increased 90 psi. OAP unchanged. Test unit in control of well upon departure. Final WHPs = SSV/690/0+. SV, SSV, WV = C. MV = O. IA & OA = OTG. 17:30 Daily Report of Well Operations PBU L-112A 10/11/2023 ***Continue Job from 10-10-2023*** Assist Coil (FRACTURING) Pumped 180 bbls Crude into IA to load. Pumped 9 bbls Crude into TBG to top off. Pumped 2 bbls 60/40 and 12 bbls Crude into FL for Freeze Protect. WT in control of well and Pad op notified upon LRS departure. 10/12/2023 LRS Test Separator 6. Continue WSR from 10/11/23, Assist CTU. IL Well L-112, OL L-250. Assist CTU 10 BBL Acid ontop of frac ball, Continue WSR on 10/13/23 10/12/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective - FCO, Acidize Frac ball/seat, contingent mill seats, set CBP, Add Perf. MIRU CTU. Make up 1.50" DJN BHA. RIH and pump a bottoms up with gel from above the liner top at 8700'. Continue RIH and tag frac sand at 9712'. Cleanout down to 10030', and then drift freely to ~ 10030'. Establish a LLR of ~ 13.5 psi/min & 0.0125 BPM at 3500 psi. Swap the well over to diesel. Pump 9 bbls of 15% HCl and circulate down to the nozzle. Circulate 2 bbls around and then begin squeezing acid down to ball seat. Very tight injectivity with 0.1 bbl/hr losses. ...Continued on WSR 10-13-23... 10/13/2023 LRS Test Separator 6. Continue WSR from 10/12/23, Assist CTU. IL Well L-112, OL L-250. Assist CTU 10 BBL Acid ontop of frac ball, Continue WSR on 10/14/23 10/13/2023 LRS CTU #2- 1.50" Blue Coil ***Cont. from WSR 10-12-23*** Job Objective - FCO, Acidize Frac ball/seat, contingent mill seats, set CBP, Add Perf. Continue attempting to squeeze away acid. Sqeeze acid down to ball seat and let soak, no change in injectivity and loss rate of only ~0.1 bbl/ 2 hours. Circulate acid from coil and POOH. ...Continued on WSR 10-14-23... 10/14/2023 LRS Test Separator 6. Continue WSR from 10/13/23, Assist CTU. IL Well L-112, OL L-250. Assist CTU 10 BBL Acid ontop of frac ball, RDMO, Continue WSR on 10/15/23 10/14/2023 LRS CTU #1 - 1.50" Blue Coil ***Cont. from WSR 10-13-23*** Job Objective: FCO, Acidize Frac ball/seat, contingent mill seats, set CBP, Add Perf. POOH with FCO BHA. Make up milling BHA with 1.77" diamond parabolic mill. Tag sleeve #3 at 10909 CTMD and mill through. Dry drift down and tag at 11393' CTM. Mill down to 11403' CTM. POOH to above the liner top and pressure up the tubing to ~ 3000 psi in one last attempt to shift the sleeve (no luck). RBIH and mill through sleeve #2 at 11403' CTM / 11405' MD. Dry drift down and tag at 11714' CTM. Mill easily to 11728' and begin taking ~ 30% losses. Hard milling from 11729'-11730 CTM and potentially milling float collar. Pump gel sweep off bottom and circulate out of well. POOH. Make up GR/CCL logging tool BHA and RIH. Attempt to pump at rate to sweep liner and injectivity falling off, 1950 psi at 0.5 bpm and 1090 psi at 0.22 bpm (pipe displacement). ...Continued on WSR 10-15-23... 10/15/2023 LRS Test Separator 6. Continue WSR from 10/14/23, Assist CTU. IL Well L-112, OL L-250, Continue RD, Job Complete, End WSR on 10/15/23 jg POOH with FCO BHA. Make up milling BHA with 1.77" diamond parabolic mill. Taggg sleeve #3 at 10909 CTMD and mill through. Dry drift down and tag at 11393' CTM.g yg Mill down to 11403' CTM. POOH to above the liner top and pressure up the tubing to ~ 3000 psi in one last attempt to shift the sleeve (no luck). RBIH and mill through () g sleeve #2 at 11403' CTM / 11405' MD. Dry drift down and tag at 11714' CTM. Mill ryg easily to 11728' and begin taking ~ 30% losses. Hard milling from 11729'-11730 CTMygg g and potentially milling float collar. Pump gel sweep off bottom and circulate out of well. POOH. Job Objective - FCO, Acidize Frac ball/seat, contingent mill seats, set CBP, Add Perf.j g Continue attempting to squeeze away acid. Sqeeze acid down to ball seat and let gy soak, no change in injectivity and loss rate of only ~0.1 bbl/ 2 hours. Circulate acid g from coil and POOH. g Continue RIH and tag frac sand at 9712'. Cleanout downg to 10030', and then drift freely to ~ 10030'. Establish a LLR of ~ 13.5 psi/min & 0.0125 y BPM at 3500 psi. Swap the well over to diesel. Pump 9 bbls of 15% HCl and circulate down to the nozzle. Circulate 2 bbls around and then begin squeezing acid down to ball seat. Very tight injectivity with 0.1 bbl/hr losses Job Objective - FCO, Acidize Frac Daily Report of Well Operations PBU L-112A 10/15/2023 LRS CTU #1 - 1.50" Blue Coil ***Cont. from WSR 10-14-23*** Job Objective: FCO, Acidize Frac ball/seat, contingent mill seats, set CBP, Add Perf. RIH with logging BHA and tag in sleeve #2 at 11410 CTMD. Unable to work past. Injectivity still very low, 0.3 bpm at 3150 psi. Pull heavy and become detained in sleeve #3 at 10910' CTMD. Work pipe and able to circulate free. Log from 10843' to7600' painting a green tie-in flag at 10750'. POOH maintaining losses to prevent additional fill/propant from entering the liner. Make up 1.50" slim FCO BHA with JSN and RIH. Tie-in to the green flag at 10750', and drift cleanly to 11747' CTMD. Pump two 10 bbl gel pills off bottom and start chasing OOH. Attempt to drift down through sleeve #3 at 10919' MD and tag every time. Paint a yellow flag at 10850'. Continue chasing gel OOH. Perform weekly BOP test. MU 1-11/16" BOT milling BHA with 1.77" diamond parabolic mill. RIH and tag sleeve #3 10919'. Pick up mobile debris and work pipe uphole with multiple overpulls and set downs. POOH to pick up venturi BHA. ...Continued on WSR 10-16-23... 10/16/2023 LRS CTU #1 - 1.50" Blue Coil ***Cont. from WSR 10-15-23*** Job Objective: FCO, Acidize Frac ball/seat, contingent mill seats, set CBP, Add Perf Make up Ventrui BHA with 1.74" mule shoe and RIH. Tag top of LTP at 8744' CTMD. Able to enter liner pumping at max rate. Ventruri through heel and across sleeves #2 and #3 down to 11488'. Dry drift from 9400' - 11480 (clean). POOH and MU NS setting tool & 2-3/8" CBP. RIH work pipe through doglegs and need to be pumped down to depth. Tie-in at flag and set CBP at 11415'. PT CBP to 2000 psi, pass. POOH. Make up 20' of 1.56" perf guns with Titan big hole charges. RIH and unable to get deeper than 11,180' due to lockup. Try swapping fluids and work pipe. ...Continued on WSR 10-17-23... 10/17/2023 LRS CTU #1 - 1.50" Blue Coil ***Cont. from WSR 10-15-23*** Job Objective: FCO, Acidize Frac ball/seat, contingent mill seats, set CBP, Add Perf RIH with 20' of 1.56" Titan big hole perf guns, 6 spf. Tie-in to CBP and perforate 11370-11390. Minimal injectivity and a loss rate of ~0.04 bpm at 3000 psi. POOH and confirm all shots fired in scallop. Pressure up the IA to ~ 1600 psi, and able to establish injectivity into the perfs at ~ 2.9 BPM @ 3800 psi (see log for details). RDMO. ***Job Complete*** 10/17/2023 T/I/O = SSV/720/10. Temp = SI. IA FL (SL). ALP = 1790 psi, SI @ CV. IA FL @ 120' (3 bbls). SV, WV, SSV = C. MV = O. IA, OA = OTG. 20:30 10/17/2023 Standby for Coil to RD & Slickline to MIRU--Job Postponed 10/18/2023 ***WELL S/I ON ARRIVAL*** (Fracturing) SET 3-1/2" CAT SV IN LTP @ 8751' MD PULLED RK-LGLV IN ST# 4 @ 4599' MD, REPLACED w/ RK-DGLV PULLED RK-OGLV IN ST# 3 @ 6462' MD, REPLACED w/ RK-DGLV LRS PERFORMED MIT-T TO 3000 PSI **PASS** PULLED 3-1/2" CAT SV FROM LTP @ 8751' MD ****WELL LEFT S/I ON DEPARTURE, PAD-OP NOTIFIED OF STATUS**** 10/18/2023 T/I/O=580/788/0 Assist SL MIT T PASSED to 3000 psi ( MA= 3250 psi ) Pumped 2.7 bbls crude down tbg to 3252 psi. TP lost 195 psi 1st 15 min & 47 psi 2nd 15 min Bled back 2.2 bbls. Bled gas off IAP from 811 psi to 470 psi before turning to fluid. FWHPs=600/470/0 g Make up 1.50" slim FCO BHA with JSNg and RIH. Tie-in to the green flag at 10750', and drift cleanly to 11747' CTMD. Pump g g y two 10 bbl gel pills off bottom and start chasing OOH. Attempt to drift down through g gg sleeve #3 at 10919' MD and tag every time. Paint a yellow flag at 10850'. Continue chasing gel OOH. jg RIH with 20' of 1.56" Titan big hole perf guns, 6 spf. Tie-in to CBP and perforate g g 11370-11390. Minimal injectivity and a loss rate of ~0.04 bpm at 3000 psi. POOH andjy confirm all shots fired in scallop. Daily Report of Well Operations PBU L-112A 10/21/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Frac FCO, Log, Plug, AdPerf Travel to location, rig down frac equipment, rig up well support, MIRU CTU ...Continue to WSR on 10/22/23... 10/21/2023 Job Scope Post CTD frac job, Warming equipment, LRS up to IA. Verify PRV set at 4200 psi. Prime pumps and frac system with heated diesel. Pressure test treating iron to 8700 Good test. Check pump trips and verify N2 PRV set. Pump 2nd stage of 3 stage frac per pump schedule. Pump injection test shutdown. Screened out when 7 ppa hit the perfs. We did extend the 6 ppa stage was taking it good decided to go to 7 ppa as we were getting low on fluid. Left ~ 20K in the pipe. Put 62,360 #'s 16/20 Carbolite and 52,995#'s 16/20 CarboBond behind pipe.Cleaned out surface lines with diesel. got 3 bbls diesel down the Treesaver into well. Rigged down standing iron remove Treesaver. Wells support prep well for CTU to prep for next stage of frac. Stage 2 of frac Complete 10/21/2023 Assit Frac, Heat and transfer 90 bbls 90* dsl to tanker Pump 7.2 bbls diesel down IA to 3900 psi. Maintain pressure during frac ops. 10/22/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Frac FCO, Log, Plug, AdPerf Rig up CTU. M/U LRS slim FCO BHA, RIH dry tag sand at 892'. Start FCO Cleanout down to 11370 when taking 25% losses. Circulate gel from11330 and chase OOH. Cap well with 8bbls Diesel, L/D LRS BHA, Start weekly BOP test ...Continued to WSR on 10/23/23... 10/23/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Frac FCO, Log, Plug, AdPerf Cont Weekly BOP test Make up NS MHA and HES GR/CCL. RIH. Tag early at ~9500, unable to bullhead. Log from 9513 up to 7500. POOH M/U slim BHA, RIH set down at 9500'. Jet through restriction at heel clean out down to 10,908 and tag. Unable to make it past ball seat after multiple attempts, Pump gel sweep from bottom, chase out of hole. L/D slim BHA, M/U YJ 1.69" milling BHA w/ 1.77 diamond parabolic mill. RIH ...Continued to WSR on 10/24/23... 10/24/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Frac FCO, Log, Plug, AdPerf RIH w/ YJ 1.69 milling BHA w/1.77" Diamond parabolic. Tag at 10920'. Mill ball seat and clean out down to 11,120. pump gel sweep from bottom chase up and pump 2 gel sweeps from below the heel ~9,600. Get bottoms up and dry drift down to 11,100. POOH, M/U NS CBP for 2-3/8". RIH and set down at 9,424. Make multiple attempts to work plug down and pulled heavy, 20k over and pop free. POOH w/o plug. M/U YJ milling assembly w/1.77" 5 blade junk mill. RIH, tag plug. Mill plug and push to 11,120. pump 10bbl gel pill and chase to surface ...Continue to WSR on 10/25/23... 10/25/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Frac FCO, Log, Plug, AdPerf Chase gel pill from 11,120. Freeze protect well with 25bbls diesel. RDMO CTU. ...Job incomplete, will return when perf guns available.... g RIH, tag plug. Mill plug and push to g 11,120. Daily Report of Well Operations PBU L-112A 10/29/2023 LRS CTU 1, 1.5" Blue coil, Job Scope: Set CBP and Perf MIRU. Complete weekly BOP test 250/4000. Make up and RIH with 1.69" Memory GR/CCL and 1.75" drift. Tagged 9424 CTM. Logged up from there and flagged pipe at 9350. Log up to 8404. POOH maintaining positive WHP. Make up and RIH with shorter 1.75" JSN BHA tag at 9466. Discuss options with OE. POOH. Make up 1.5" slim reverse FCO BHA. ***Job Continued on 10/30/2023*** 10/30/2023 LRS CTU 1, 1.5" Blue coil, Job Scope: Set CBP and Perf RIH with 1.5" slim reverse FCO BHA. Dry tagged at 9680. PBUH above LTP and begin reverse circulating. Reciprocate across the LTP. Continue in hole reveresing and clean out down to 9700, where the nozzle gets heavily restricted and just stacking weight. POOH to check tools. Found 2 ports in JSN plugged with frac sand. M/U baker MHA/ motor, venturi and mule shoe. RIH tagged throughout the heel and hard tag at 9716. Worked through and recip across heel. Dry drift from liner top to 11,100. POOH chasing a bottoms up from below heel. 2 slips and apx 1 tablespoon of frac sand inside venturi. metal gouges found around outside of mule shoe and venturi. Make up and RIH with NS 2.375" CBP setting BHA with knuckle joint. ***Job Continued on 10/31/2023*** 10/31/2023 LRS CTU 1, 1.5" Blue coil, Job Scope: Set CBP and Perf RIH with NS 2.375" CBP setting BHA with knuckle joint. Tagged lightly at 9552. Picked up clean and begin slowly working pipe through dog leg. Set down at 9842 and the CBP soft set. Shear off. POOH and circulate in freeze protect from 2800MD/2500TVD. Well freeze protected with 25 bbl of diesel. RDMO. ***Job Incomplete*** 11/3/2023 ***WELL S/I ON ARRIVAL*** SET 3-1/2" WHIDDON(wcs 32) @ 8,757' MD PULLED RK-DGLV FROM STA #2 @ 7,710' MD PULLED RK-DGLV FROM STA #3 @ 6,462' MD PULLED RK-DGLV FROM STA #4 @ 4,599' MD SET ST#4 RK-LGLV (16/64" TRO 1450PSI) @ 4599' MD SET ST#3 RK-SO (20/64" ports) @ 6462' MD SET ST#2 RK-DGLV @ 7710' MD PULLED 3-1/2'' WHIDDON CATCHER FROM DEPLY SLV @ 8733' SLM / 8757' MD (empty) ***JOB COMPLETE, WELL LEFT S/I *** 11/20/2023 LRS Test Unit 6, Begin WSR 11/20/23 IL- L-112 / OL- L-122, CTU Assist, Begin SB for OSL, Continue WSR on 11/21/23 11/21/2023 LRS Well Testing Unit 6, Cont WSR from 2-20-23. IL Well L-112 / L-250, Fill Clean Out, STBY, RU, PT, STBY, Cont WSR to 11-22-23 11/22/2023 LRS Well Testing Unit 6, Cont WSR from 11-21-23. IL Well L-112 / L-250, Fill Clean Out, Continue STBY for OSL, Cont WSR to 11-23-23 11/23/2023 LRS Well Testing Unit 6. Cont WSR from 11/22/23. IL Well L-112/ L-250. Fill Clean Out. Cont STBY for OSL. Cont WSR on 11/24/23 11/23/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Mill CBP's Travel to location, stand by for rig to move module/building before CTU can spot in. MIRU CTU. MU BOT 1.75" milling BHA. RIH and mill CBP at 9,795' CTMD, push to second plug at 11,114' CTMD but could not get motor work. POOH and MU venturi burnshoe. RIH tag plug at 11128 ...Continued to WSR on 11/24/23... Daily Report of Well Operations PBU L-112A 11/24/2023 LRS Well Testing Unit 6. Cont WSR from 11/23/23. IL Well L-112/ L-250. Fill Clean Out. Assist CTU. Cont WSR on 11/25/23 11/24/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Mill CBP's Mill plug at 11128 wtih 1.74" venturi/burnshoe. Unable to mill. POOH. Recovered part of a composite plug in burnshoe and rubber pieces inside the venturi screen. M/U new Venturi/burnshoe RIH and tagged plug at 11,132', Milled on plug for 4hrs with minimal motor work, pumped gel sweep and started POOH. Hung up at first ball seat and R nipple in LTP while PUH. POOH and found all the cutting structure worn off burn shoe and plug core lodged in center. MU new burn shoe BHA and RIH. Establish free spin, tagged at 11,132' ctm. Mill on CBP debris for 2 hrs w/minimal motor work. Pumped 5 bbl gel sweep and POOH. FP coil w/diesel and well w/3 bbl MEOH cap. Recovered 1/2 cup of CBP debris, small pieces of rubber, and trace carbolite. ...Job in Progress... 11/25/2023 LRS Well Testing Unit 6. Cont WSR from 11/24/23. IL Well L-112/ L-250. Fill Clean Out. POP L-112. Cont WSR on 11/26/23 11/25/2023 LRS CTU #1 - 1.50" Blue Coil Job Objective: Mill CBP's & Push to TD. M/U milling BHA w/1.74" 3 bladed junk mill and RIH. Work past 11,132' with no issues. Cleanout through perf interval 11,370' - 11,390'. Milled CBP @ 11,416' ctm. Push plug to 11,500' ctm. Pumped 10 bbl gel sweep and make wiper trip to 11,000' ctm. Mill plug at 11,500' and push down to 11,738 CTM. POOH chasing gel sweep. M/U 1.74" venturi/Burnshoe and RIH. Tagged in heel 9,410' CTM, attempt to work past adjusting speeds/rates with multiple stalls. Discuss plan forward w/OE. POOH w/BHA. FP coil w/diesel and 5 bbl cap on well. RDMO CTU #1. ...Job Completed. 11/26/2023 LRS Well Testing Unit 6. Cont WSR from 11/25/23. IL Well L-112/ L-250. Fill Clean Out. POP, Cont Opening CK per program, L-112. Cont WSR on 11/27/23 11/27/2023 LRS Well Testing Unit 6. Cont WSR from 11/26/23. IL Well L-112/ L-250. Fill Clean Out. CK @ Full Open, Divert into WPS. Begin 12 HR PBWT, Cont WSR on 11/28/23 11/28/2023 LRS Well Testing Unit 6. Cont WSR from 11/27/23. IL Well L-112/ L-250. Fill Clean Out. End 12 HR PBWT, BD, RDMO. Job Completed End WSR 12:54:44 13:23:54 13:53:04 14:22:14 14:51:24 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 Pressure - psi0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Rate - bbl/min0 1 2 3 4 5 6 7 8 9 10 Prop Con - PPATreating Pressure Annulus Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Hilcorp L-112A, Stage 1 9-18-2023 FracCAT Treatment Report Well : L-112a Stage 2 Field : Prudhoe Bay Formation : Borealis Well Location : Greater Prudhoe Bay County : North Slope Borough State : Alaska Country : United States Prepared for Client : Hilcorp North Slope, LLC Client Rep : David Wages Date Prepared : October 21, 2023 Prepared by Name : Michael Hyatt Division : Schlumberger Pressures Initial Wellhead Pressure (psi)550 Surface Shut in Pressure(psi)3,770 Maximum Treating Pressure (psi)7,224 Injection Test ISIP (psi)3,100 Average Treating Pressure (psi)5,865 ISIP (psi)Screenout Treatment Totals Total Slurry Pumped (Water+Adds+Proppant) (bbl)1,179.2 Total Carbolite 16/20 Pumped (lbs.); Per Load Tickets 42,360 Total Crosslink Fluid (bbl) 1,023.8 Total CarboBond 16/20 Pumped (lbs.); FracCat Totals 72,995 Water for Injection Test (bbl) 33.0 Total BH Proppant Pumped (lbs.); FracCat Totals 94,052 Total Chemical Additives Invoiced Past WH Invoiced Past WH F103 (gal)50 49.5 J134 (lb)10 0 L065 (gal)47 46.5 J475 (lb)165 163 L071 (gal)95 94 J218 (lb)11 0 J532 (gal)91 90 J580 (lb)1,489 1,224 S123 (gal)47 45.5 Diesel (bbl)0 3 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: L-112a, Stage 2 Formation: Borealis District: Prudhoe Bay Country: United States Client: Hilcorp North Slope, LLC Well: L-112a, Stage 2 Formation: Borealis District: Prudhoe Bay Country: United States Summary On October21, 2023 Schlumberger performed the hydraulic fracturing stimulation for Stage 2 of L-112A. The crew arrived on location at approximately 6:30 am and completed offloading proppant for the job, putting additional containment under the treating equipment and warming up the equipment. By 10:30 am the crew had completed the rigup and performed a brief safety meeting to discuss prime up and pressure test procedures. The prime up was started at 11:15 am. By 12:45, the pressure test was complete and pre job safety meeting was being held. At 1:15 pm, the job was started. It initially began with displacing the wellbore fluids and doing a brief analysis of the decline. Overall, the main treatment went well. The decision was made before the job to pump at a maximum attainable rate during pad and early proppant stages. Rate would then be lowered as we saw friction pressures increasing as proppant concentration (prop con) increased. The first rate drop occurred once 4ppa was being pumped on surface. As prop con increased, rate was gradually lowered throughout the remainder of the job until 14bpm was reached. The well responded as expected to rate changes and friction pressures lowered with rate. While pumping 6ppa on surface, treating pressure remained level and the decision was made to start pumping 7ppa. While pumping 7ppa, pressure remained level as well. Once 7ppa entered formation, pressure increased sharply, and a screenout occurred. In total, 115,000± pounds of proppant was pumped with 94,000± pounds going into formation. A copy of the treatment plot is below. The equipment ran well without any mechanical issues. One of the pumps was brought offline due to what appeared to be a cut valve on a fluid end. The backup pump was brought online with no issues. The loss of a valve in a frac pump when pumping ceramic proppant is a common problem, and is the reason additional pumps are mobilized to location. The valve will be replaced post job when the crew inspect the fluid ends on the pumps. 13:10:38 13:43:58 14:17:18 14:50:38 15:23:58 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 Pressure - psi0 5 10 15 20 25 30 Rate - bbl/min0 2 4 6 8 10 12 14 16 Prop Con - PPATreating Pressure Annulus Pressure Slurry Rate Prop Conc BH Prop Con Main Treatment © Schlumberger 1994-2017 Hilcorp L-112A, Stage 2 10-21-2023 Client: Hilcorp North Slope, LLC Well: L-112a, Stage 2 Formation: Borealis District: Prudhoe Bay 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 Displace WB 33.0 7.2 6.2 Water 1385 0.0 0.0 0 2 Crosslink Check 22.4 8.7 2.9 YF128ST 939 0.0 0.0 0 3 Pad 101.0 10.0 10.1 YF128ST 4240 0.0 0.0 0 4 0.5 PPA 100.0 15.2 7.0 YF128ST 4117 CarboLite 16/20 0.6 0.5 1880 5 Pad 2 100.0 18.0 5.6 YF128ST 4197 CarboLite 16/20 0.5 0.0 63 6 1.0 PPA 119.9 17.5 6.8 YF128ST 4832 CarboLite 16/20 1.1 1.0 4698 7 2.0 PPA 119.9 18.0 6.7 YF128ST 4636 CarboLite 16/20 2.1 2.0 9116 8 3.0 PPA 99.9 17.9 5.6 YF128ST 3713 CarboLite 16/20 3.1 3.0 11002 9 4.0 PPA 107.4 16.7 6.4 YF128ST 3845 CarboLite 16/20 4.2 4.0 15237 10 5.0 PPA 121.4 15.4 7.9 YF128ST 4177 16/20 CarboBOND Lite 5.3 5.0 20793 11 6.0 PPA 138.3 14.1 9.8 YF128ST 4593 16/20 CarboBOND Lite 6.5 6.0 27463 12 7.0 PPA 107.4 14.0 7.7 YF128ST 3447 16/20 CarboBOND Lite 7.2 7.0 24053 13 8.0 PPA 7.4 8.5 3.7 YF128ST 265 16/20 CarboBOND Lite 8.8 4.0 1050 14 FP 1.4 0.6 2.3 Freeze Protect 57 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 Displace WB 7.2 9.7 4974 6338 526 2 Injection 8.7 10.0 5437 6199 981 3 Pad 10.0 10.0 6038 6701 5015 4 0.5 PPA 15.2 19.6 6076 7077 5101 5 Pad 2 18.0 18.1 6254 6727 6119 6 1.0 PPA 17.5 18.8 6034 6450 5760 7 2.0 PPA 18.0 18.5 6099 6219 5998 8 3.0 PPA 17.9 18.2 6136 6202 6067 9 4.0 PPA 16.7 17.9 5678 6233 5461 10 5.0 PPA 15.4 16.6 5500 5783 5083 11 6.0 PPA 14.1 14.5 5663 5747 5300 12 7.0 PPA 14.0 14.2 5709 5826 5669 13 8.0 PPA 8.5 13.8 5814 7224 28 14 FP 0.6 0.8 6026 6555 3866 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 1179.2 88.6 44444 115355 Client: Hilcorp North Slope, LLC Well: L-112a, Stage 2 Formation: Borealis District: Prudhoe Bay 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 9:52:53 Started Pumps 0 0 0.0 0.0 0.0 2 9:53:28 Still Offloading sand and waiting on Vac trucks 0 0 0.0 0.0 0.0 3 10:29:50 1 Vac truck waiting on second 0 0 0.0 0.0 0.0 4 11:33:03 Second Vac truck arrived 6 475 0.0 0.0 0.0 5 11:33:13 Starting Prime up 6 475 0.0 0.0 0.0 6 12:15:56 Swapping Transducer 56 475 0.0 0.0 0.0 7 12:26:58 Starting PT 43 475 0.0 0.0 0.0 8 12:31:42 Check Valve Good 3598 475 0.0 0.0 0.0 9 12:44:58 Good PT 31 475 0.0 0.0 0.0 10 13:00:31 PJSM 35 475 0.0 0.0 0.0 11 13:16:55 Start Displace WB Automatically 1143 492 0.0 0.0 0.0 12 13:16:55 Start Propped Frac Automatically 1143 492 0.0 0.0 0.0 13 13:16:55 Start 1. Stage 2 Automatically 1143 492 0.0 0.0 0.0 14 13:17:04 Started Pumping 1108 497 0.0 0.0 0.0 15 13:17:36 Well Open 514 519 0.0 0.0 0.0 16 13:18:06 Activated Extend Stage 942 588 0.1 1.3 0.0 17 13:54:20 Deactivated Extend Stage 983 3283 33.0 0.0 0.0 18 13:54:20 Start Injection Manually 983 3283 33.0 0.0 0.0 19 13:57:32 Start Pad Manually 6193 3966 55.3 10.0 0.0 20 14:01:32 Stage at Perfs: Displace WB 6198 3968 95.3 10.0 0.0 21 14:04:31 Activated Extend Stage 6676 3959 125.4 9.8 0.0 22 14:04:48 Stage at Perfs: Injection 6442 3973 128.2 9.8 0.0 23 14:07:04 Stage at Perfs: Pad 5166 3984 150.8 10.0 0.0 24 14:08:09 Deactivated Extend Stage 5190 3965 161.6 10.0 0.0 25 14:08:09 Start 0.5 PPA Manually 5190 3965 161.6 10.0 0.0 26 14:08:09 Started Pumping Prop 5190 3965 161.6 10.0 0.0 27 14:14:37 Start Pad 2 Automatically 6693 3965 256.5 18.1 0.5 28 14:14:39 Stage at Perfs: Pad 2 6670 3965 257.1 18.0 0.5 29 14:14:52 Stopped Pumping Prop 6515 3956 261.0 18.1 0.0 30 14:19:56 Stage at Perfs: Pad 2 6231 3965 352.0 18.1 0.0 31 14:20:11 Start 1.0 PPA Automatically 6220 3960 356.5 18.0 0.0 32 14:20:16 Started Pumping Prop 6223 3959 358.0 18.1 0.0 33 14:25:42 Stage at Perfs: 1.0 PPA 6481 3991 452.2 18.7 1.0 34 14:27:02 Start 2.0 PPA Automatically 6134 3977 476.5 18.1 1.0 35 14:32:19 Stage at Perfs: 2.0 PPA 6124 3966 572.0 17.8 2.0 36 14:33:41 Start 3.0 PPA Automatically 6159 3983 596.4 17.8 2.0 37 14:39:00 Stage at Perfs: 3.0 PPA 6176 3956 691.8 17.9 3.0 38 14:39:15 Start 4.0 PPA Automatically 6233 3957 696.3 17.8 3.0 39 14:41:50 Activated Extend Stage 5538 3948 740.4 16.5 4.0 40 14:44:59 Stage at Perfs: 4.0 PPA 5548 3945 791.9 16.5 4.0 41 14:45:41 Deactivated Extend Stage 5613 3943 803.4 16.4 3.8 42 14:45:41 Start 5.0 PPA Manually 5613 3943 803.4 16.4 3.8 43 14:51:37 Activated Extend Stage 5333 3959 896.2 14.7 5.0 44 14:51:48 Stage at Perfs: 5.0 PPA 5476 3957 898.9 14.5 5.0 45 14:53:35 Deactivated Extend Stage 5646 3944 924.8 14.4 5.0 46 14:53:35 Start 6.0 PPA Manually 5646 3944 924.8 14.4 5.0 47 14:57:49 Activated Extend Stage 5637 3915 984.8 13.9 6.0 48 15:00:20 Stage at Perfs: 6.0 PPA 5677 3941 1020.2 13.9 6.1 49 15:03:24 Deactivated Extend Stage 5688 3934 1063.1 13.9 6.0 Client: Hilcorp North Slope, LLC Well: L-112a, Stage 2 Formation: Borealis District: Prudhoe Bay Country: United States Message Log #Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 50 15:03:24 Start 7.0 PPA Manually 5688 3934 1063.1 13.9 6.0 51 15:04:17 Activated Extend Stage 5732 3929 1075.4 14.1 7.1 52 15:10:13 Stage at Perfs: 7.0 PPA 5791 3914 1158.5 13.9 7.0 53 15:11:05 Deactivated Extend Stage 5937 3920 1170.5 13.8 6.9 54 15:11:05 Start 8.0 PPA Manually 5937 3920 1170.5 13.8 6.9 55 15:11:50 Stopped Pumping Prop 6586 3948 1175.3 0.0 -0.0 56 15:26:32 Cleaning up pumps 243 3650 1176.2 1.6 0.0 57 16:04:16 Open Well 2055 1938 1176.2 0.0 0.0 58 16:05:10 Started Pumping to freeze protect treesaver 1776 1932 1176.2 0.0 0.0 59 16:18:21 Start FP Manually 6912 3558 1177.8 1.1 0.0 60 16:38:15 Closed well 3787 3351 1179.2 0.0 0.0 Client: Hilcorp North Slope, LLC Well: L-112a, Stage 2 Formation: Borealis District: Prudhoe Bay Country: United States Additional Treatment Plots 13:05:04 13:42:34 14:20:04 14:57:34 15:35:04 Time - hh:mm:ss 0 2 4 6 8 10 J532, S123_CONC - gal/mgal0 1 2 3 4 5 F103, L065, L071_CONC - gal/mgal0 10 20 30 40 50 60 70 J475_Conc - lb/mgal0 5 10 15 20 25 30 35 40 PCM_GUAR_CONC_STPT - lb/mgalJ532 Conc S123 Conc F103 Conc L065 Conc L071 Conc J580 Conc J475 Conc Additive Plot © Schlumberger 1994-2017 Hilcorp L-112A, Stage 2 10-21-2023 Additive Additive Description F103 Surfactant 1.1 Gal/mGal 101.5 gal J475 Breaker J475 3.2 lb/mGal 300.5 lbm J532 Crosslinker 2.0 Gal/mGal 187.0 gal J580 Gel J580 24.7 lb/mGal 2,349.0 lbm L065 Scale Inhibitor 1.0 Gal/mGal 96.5 gal L071 Clay Control Agent 2.0 Gal/mGal 193.0 gal M275 Bactericide 0.4 lb/mGal 42.0 lbm S123 Activator 0.5 Gal/mGal 48.5 gal S522-1620 Propping Agent varied concentrations 42,360.0 lbm S526-1620 Propping Agent varied concentrations 121,971.0 lbm 82.25847 % 17.13008 % 0.24425 % 0.12466 % 0.03951 % 0.03342 % 0.03226 % 0.02506 % 0.01965 % 0.01836 % 0.01688 % 0.01655 % 0.01520 % 0.00825 % 0.00595 % 0.00367 % 0.00219 % 0.00189 % 0.00132 % 0.00061 % 0.00044 % 0.00026 % 0.00022 % 0.00020 % 0.00016 % 0.00016 % 0.00010 % 0.00010 % 0.00005 % 0.00004 % 0.00004 % 0.00001 % 100 % 64-19-7 Acetic acid (impurity) Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 127-08-2 Acetic acid, potassium salt (impurity) 14464-46-1 Cristobalite 14808-60-7 Quartz, Crystalline silica 14807-96-6 Magnesium silicate hydrate (talc) 1310-73-2 Sodium hydroxide (impurity) 7447-40-7 Potassium chloride (impurity) 7786-30-3 Magnesium chloride 111-46-6 2,2''-oxydiethanol (impurity) 9002-84-0 poly(tetrafluoroethylene) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 91053-39-3 Diatomaceous earth, calcined 10043-52-4 Calcium chloride 112-42-5 1-undecanol (impurity) 68131-39-5 Ethoxylated Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 7647-14-5 Sodium chloride 68131-40-8 Alcohols, c11-15-secondary, ethoxylated 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 7727-54-0 Diammonium peroxidisulphate 107-21-1 Ethylene Glycol 129898-01-7 2-Propenoic acid, polymer with sodium phosphinate 56-81-5 1, 2, 3 - Propanetriol 67-63-0 Propan-2-ol 1303-96-4 Sodium tetraborate decahydrate 66402-68-4 Ceramic materials and wares, chemicals 9000-30-0 Guar gum 67-48-1 2-hydroxy-N,N,N-trimethylethanaminium chloride CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF128ST:Water:WF128 95,227 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. Report ID: RPT-1775 Fluid Name & Volume Concentration Volume Disclosure Type: Post-Job Well Completed: Date Prepared: 12/13/2023 State: Alaska County/Parish: North Slope Borough Case: Client: Hilcorp North Slope Well: L-112A Basin/Field: Prudhoe Bay Page: 1 / 1 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 L-112A Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 222-138 50-029-23129-01-00 CO 736 ADL 0028239, 0047449 12138 Conductor Surface Intermediate Production Liner 6676 80 3074 9358 2996 11749 20" 9-5/8" 7" 2-3/8" 6683 36 - 116 35 - 3109 32 - 9390 8757 - 11753 1568 36 - 116 35 - 2670 32 - 6723 6139 - 6682 None 470 3090 5410 11780 None 1490 5750 7240 11200 10901 - 11749 3-1/2" 9.2# L-80 29 - 91766679 - 6683 Structural 3-1/2" Baker S-3 Packer No SSSV Installed 9118, 6468 No SSSV Installed Date: Torin Roschinger Area Operations Manager Tyson Shriver tyson.shriver@hilcorp.com 907.564.5006 PRUDHOE BAY 9/15/2023 Current Pools: BOREALIS OIL Proposed Pools: BOREALIS 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 By Grace Christianson at 1:07 pm, Sep 07, 2023 323-508 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.09.07 12:40:44 -08'00' Torin Roschinger (4662) DSR-9/11/23SFD 9/11/2023 9/15/2023 Supersedes Sundry Application 323-255 SFD Supersedes Sundry Application 323-255 SFD CDW 09/11/2023 CO 471.011 SFD 10-404 Fracture Stimulate 323-508 *&: JLC 9/12/2023 09/12/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.12 16:05:14 -05'00' RBDMS JSB 091223 Post-CTD 3-stage Ball drop Frac Well: L- 112A Well Name:L-112A API Number:50-029-23129 Current Status:Operable Producer Revision:2 Estimated Start Date:9/15/2023 Rig:SL/Coil/frac/testers Original Sundry #:323-255 Original Date Reg. Approval Rec’vd:5/4/23 Regulatory Contact:Abbie Barker First Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M) Second Call Engineer:Marshall Brown (601)-613-0173 (M) Current Bottom Hole Pressure:2228 psi @ 6600’ TVD 6.5 PPGE | Lower bound Max. Anticipated Surface Pressure:1568 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:753 psi (Taken on 11/17/22) Min ID:2.813” X at 2637’ MD Max Angle:59 Deg @ 5400’ MD MITs: 3/29/2023: MIT-IA to 4440 psi 3/27/2023: MIT-T to 3752 psi 9/3/2023: MIT-T to 4395psi Formation Tops: x Ugnu: 3396’ MD, 2828’ TVD x Schrader Bluff N sands: 5889’ MD, 4188’ TVD x HRZ: 8878’ MD, 6247’ TVD x Kuparuk: 9313’ MD, 6651’ TVD Brief Well Summary: A CTD sidetrack of producer L-112 has been drilled west of L-112. The sidetrack will further develop a fault block that L- 112 has already proved up. After CDR drilled the lateral, the completion consisting of ball drop frac sleeves in the toe then a swell packer and cementing valve mid lateral and solid pipe all the way back to the motherbore with a deployment sleeve was cemented in place. Unfortunately, the cement job did not cover the hole in the tubing. And the liner was landed high so the coil liner deployment sleeve is above the hole which is behind the coil liner. We cannot access the hole with mechanical means so the solution is a cement packer squeeze. Post rig operations on L-112 have resulted in a successful bonsai cement job to isolate the frac locations from the motherbore, a successful packer squeeze to remediate a known tubing leak and verification that we can still pump into the wellbore. Notes Regarding Wellbore Condition x Drill 1/14/2003 x 2/17/2003: Eline – Perforate x 2/22/2003: Frac – 210k# 16-20, max treat: 6467 psi, ave: 5555 psi x Many many HOTs, Coil FCO, B&Fs since. Uneventful well Objective: x 3 stage ball drop frac Post-CTD 3-stage Ball drop Frac Well: L- 112A 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 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. RU and set treesaver per OilStates rep 4. Drop Stage 1 ball a. We may not see it land on seat, but we want to ensure all fluid is exiting out of the frac sleeve and not split between the sleeve and the shoe 5. Frac stage 1 – 3 per pump schedule MIT-T 4395 psi MIT-IA 4440 psi Maximum Anticipated Treating Pressure:6800 psi @ 20 BPM IA Pop-off Set Pressure (~95% of MIT-IA):4200 psi IA Minimum Hold Pressure (POP-off – 300 psi):3900 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1):7895 psi w/ 3900 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:7105 – 7500 psi Global Kickout (95% of MATP):7500 psi N2 POP-off set pressure (MATP):7895 psi Treating Line Test Pressure (MATP + 1000 psi):8895 psi OA Pressure:Monitor Max Anticipated Proppant Loading:8 PPA x The pump schedule is designed to where most of our proppant is away at less than 3 ppa, we’ve seen problems when trying to obtain higher than 4+ ppa. However, when pump rate is reduced to 15 bpm, our fluid seems to arrive on perforation in better quality and higher sand concentrations can be achieved. x When fracing 2-3/8” liners, we should be 15 BPM from 4 ppa and above x If treating pressure starts acting sporadic, consider dropping rate to as low as 12 bpm. If it is acting up at 12 bpm, we should be on flush. Pressure test tree saver and surface treating lines to 8895 psi Pressure test IA pop off to 4200 psi. Pressure test pump trips 7105-7500 psi - CDW 09/11/2023 Post-CTD 3-stage Ball drop Frac Well: L- 112A Coil Tubing 1. MIRU and pressure test 2. MU milling assembly for ball seats a. Ensure we are using high strength coil for needed overpulls b. Refer to L-122 milling BHA for optimal mill to use 3. Mill ball seats to minimum stage 1 frac sleeve a. We don’t necessarily need to mill out stage 1, we just need the sand off it. 4. POH Slickline This step may need to be performed prior to coil FCO if stable returns cannot be established 1. Drift, install catcher 2. Install LGLVs 3. Pull catcher 4. RDMO 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. Current Wellbore Schematic 2. Fracture Stimulation Detail 3. Sundry Change form Post-CTD 3-stage Ball drop Frac Well: L- 112A Current WBD: Post-CTD 3-stage Ball drop Frac Well: L- 112A Liner Details: L-112a Date:September 7, 2023 Subject: L-112A Fracture Stimulation From:Tyson Shriver O:(907) 564-4542 C:(406) 690-6385 To: AOGCC Estimated Start Date:9/15/2023 Attached is Hilcorp’s proposal and supporting documents to perform a 3 stage fracture stimulation on well L-112a in the Kuparuk reservoir of the Prudhoe Bay Unit. A CTD sidetrack of producer L-112 is has been drilled west to further develop a fault block that L-112 has already proved up. After CDR drilled the lateral, the completion consisting of ball drop frac sleeves in the toe then a swell packer and cementing valve mid lateral and solid pipe all the way back to the motherbore with a deployment sleeve was run. After the swell packer had had time to set, service coil cemented uphole of the packer through the cementing valve back to the motherbore and deployment sleeve. This completion is designed to leave the toe uncemented while isolating the motherbore with bonsai cement per program. Unfortunately, while deploying the liner, CTD was unable to get it all the way to bottom. The liner deployment sleeve was left high in the tubing and was covering a known tubing hole. The original intent was to install a high pressure patch over the hole but due to the new wellbore geometry, service coil was sent out to perform a packer squeeze to address the hole. After cementing operations, a successful MIT-T and MIT-IA was obtained making the well ready for fracture treatment operations. Once fracturing operations are complete, service coil will mill out the ball seats then slickline work to get the live gas lift valves installed and the well POP’d through test separator. 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 Tyson Shriver. 3 stage fracture stimulation o 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 SIGNED AFFIDAVIT: COPY OF NOTIFICATION SENT VIA EMAIL: SECTION 2: PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25. 283, a, 2): 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 IGNIKSIKUMI1 Exploratory Abandoned L-201L2 Development Oil Well L-01 Development Abandoned L-201L3 Development Oil Well L-01A Development Oil Producer Shut-In L-201L3PB1 Development Plugged Back For Redrill L-02 Development Abandoned L-201PB1 Development Plugged Back For Redrill L-02A Development Abandoned L-201PB2 Development Plugged Back For Redrill L-02APB1 Development Plugged Back For Redrill L-202 Development Oil Producer Gas Lift L-02B Development Oil Producer Shut-In L-202L1 Development Oil Producer Gas Lift L-02PB1 Development Plugged Back For Redrill L-202L2 Development Oil Producer Flowing L-03 Development Abandoned L-202L3 Development Oil Producer Flowing L-03A Development Suspended L-203 Development Oil Producer Shut-In L-03APB1 Development Plugged Back For Redrill L-203L1 Development Oil Well L-04 Service Water Injector Shut-In L-203L2 Development Oil Well L-100 Development Oil Producer Shut-In L-203L2-01 Development Oil Well L-101 Development Oil Producer Gas Lift L-203L3 Development Oil Well L-102 Development Oil Producer Gas Lift L-203L3PB1 Development Plugged Back For Redrill L-102PB1 Development Plugged Back For Redrill L-203L3PB2 Development Plugged Back For Redrill L-102PB2 Development Plugged Back For Redrill L-203L4 Development Oil Well L-103 Service Water Injector Injecting L-204 Development Oil Producer Gas Lift L-104 Development Oil Producer Gas Lift L-204L1 Development Oil Producer Gas Lift L-105 Service Miscible Injector Operating L-204L2 Development Oil Producer Gas Lift L-106 Development Abandoned L-204L3 Development Oil Producer Gas Lift L-106A Development Oil Producer Gas Lift L-204L4 Development Oil Producer Gas Lift L-107 Development Oil Producer Shut-In L-205 Development Abandoned L-108 Service Water Injector Injecting L-205A Development Oil Producer Gas Lift L-109 Service Water Injector Injecting L-205L1 Development Abandoned L-110 Development Oil Producer Shut-In L-205L2 Development Abandoned L-111 Service Water Injector Injecting L-205L3 Development Abandoned L-112 Development Oil Producer Gas Lift L-205L4 Development Abandoned L-114 Development Abandoned L-205L5 Development Abandoned L-114A Development Abandoned L-205PB1 Development Plugged Back For Redrill L-114B Development Oil Producer Shut-In L-206 Development Oil Producer Gas Lift L-115 Service Water Injector Injecting L-207 Development Oil Producer Gas Lift L-116 Development Abandoned L-210 Service Water Injector Injecting L-116A Development Oil Producer Shut-In L-210PB1 Service Plugged Back For Redrill L-117 Service Miscible Injector Operating L-211 Service Water Injector Injecting L-118 Development Oil Producer Gas Lift L-211PB1 Service Plugged Back For Redrill L-118L1 Development Oil Well L-212 Service Water Injector Injecting L-119 Service Abandoned L-212PB1 Service Plugged Back For Redrill L-119A Service Miscible Injector Operating L-212PB2 Service Plugged Back For Redrill L-119APB1 Service Plugged Back For Redrill L-213 Service Water Injector Injecting L-120 Development Oil Producer Flowing L-214 Service Abandoned L-121 Development Abandoned L-214A Service Water Injector Injecting L-121A Development Oil Producer Gas Lift L-215 Service Miscible Injector Shut-In L-122 Development Oil Producer Gas Lift L-216 Service Water Injector Shut-In L-122L1 Development Oil Producer Shut-In L-217 Service Water Injector Injecting L-123 Service Miscible Injector Shut-In L-218 Service Water Injector Injecting L-123PB1 Development Plugged Back For Redrill L-219 Service Miscible Injector Shut-In L-124 Development Oil Producer Shut-In L-220 Service Water Injector Shut-In L-124PB1 Development Plugged Back For Redrill L-221 Service Water Injector Shut-In L-124L1 Development Oil Producer Shut-In L-222 Service Miscible Injector Operating L-124L1PB1 Development Plugged Back For Redrill L-223 Service Water Injector Shut-In L-124PB2 Development Plugged Back For Redrill L-240 Service Miscible Injector Operating L-200 Development Abandoned L-240PB1 Service Plugged Back For Redrill L-200A Development Oil Producer Gas Lift L-250 Development Oil Producer Shut-In L-200L1 Development Abandoned L-250L1 Development Oil Producer Gas Lift L-200L2 Development Abandoned L-250L2 Development Oil Producer Gas Lift L-201 Development Oil Producer Gas Lift L-250PB1 Development Plugged Back For Redrill L-201L1 Development Oil Well L-50 Development Oil Producer Shut-In L-201L1PB1 Development Plugged Back For Redrill L-50PB1 Development Plugged Back For Redrill SECTION 3: EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25. 283, a, 3): Well L-112a 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 9/11/2023 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 9/11/2023 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: 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: After spudding the well on 1/1/2003, a 12-1/4” surface casing hole was uneventfully drilled and 9-5/8” 40# L-80 surface casing was run and set at 3109’. It was cemented in place with 365 bbls ArcticSetIII lead followed by 75 bbls ClassG tail. Had 75 bbls of cement returns, the plug held and the hole stayed full throughout the job. The 7” casing production hole was drilled without issue, the casing was cemented in place with full returns and a bumped plug that held. The drilling rig was released from the well on 1/12/2003. During CTD screening, a tubing leak at ~9070’ was identified just above the sliding sleeve in the well. After evaluation, it was determined that we could set a high pressure patch over the hole after drilling the lateral. On 1/8/2023 CTD milled the window for the L-112a lateral. While drilling the lateral, a fault was crossed where the reservoir pressure was lower than that at the motherbore causing concerns about the drilling rig performing the primary cement job. Upon running the liner, CTD was unable to get the completion to TD and left the top of liner at 8757’, ~300’ above the identified hole in tubing. Post rig operations commenced to first pump the primary cement job, this went well with 16 bbls of cement pumped. However, returns were lost just before final flush volume was pumped so the TOC did not get above the hole in the tubing. A CMIT passed to 3000 psi. this means the cement is above the CTD window, but below the hole in tubing and liner top. An amended sundry was submitted and approved to pump a packer squeeze to establish tubing integrity. Service coil rigged up again and pumped 11.2 bbls of cement down the liner backside. A follow up CBL showed good cement in the tubing annulus 8677’ and a subsequent MIT-T to 3752 psi and an MIT-IA to 4440 psi was obtained.To prepare for the frac an LTP was installed on 9/3/2023 to isolate the liner lap. The LTP subsequently passed an MIT-T to 4,395 psi. All casing is cemented in accordance with 210 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. The frac in 2006 had a max treating pressure of 7800 psi. A CMIT passed to 3000 psi. this means the cement is above the CTD window, but below the hole in tubing and liner top. A Agree. SFD 9/11/2023 75 bbls of cement returns, SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL 20 AAC 25.283, A, 7 On 3/29/2023, the production casing was pressure tested to 4440 psi for a passing MIT-IA On 3/27/2023, the tubing was pressure tested to 3752 psi for a passing MIT-T On 9/3/2023, the tubing was pressure tested to 4,395 psi for a passing MIT-T after installing a LTP 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. 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 9-5/8” Surface Casing 40#L80 5750 3090 7” Production Casing 26#13Cr-80 7240 5410 3-1/2” Production Tubing 9.2#L80 10160 10540 2-3/8” Production Liner 4.7#L80 11200 11780 Wellhead FMC manufactured wellhead, rated to 5, 000 psi. Tubing head adaptor: 11" 5, 000 psi x 4-1/16" 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 outlets Tree: CIW 4-1/16" 5,000 psi A 10k psi rated TreeSaver will be used during these fracturing operations: 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 8878 9130 -6165 -6397 231 0.7 Shale TKLB 9130 9314 -6397 -6570 173 0.7 Shale Top Kup D Shale 9314 9358 -6570 -6611 42 0.65 Shale Top Kup/C interval 9358 9517 -6611 -6760 149 0.62 Silts/SS LCU/ Kuparuk B 9517 --6760 -6907 147 0.65 Silts/SS *Kuparuk A ---6907 -6980 73 0.65 Silts/SS *Miluveach --6980 --0.7 Shale * estimated thickness from L-114 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 L-112A wellborereservoir 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. Casing and Cement assessments for all wells that transect the confining zone: L-112:After cementing the surface casing, the 8-3/4” production hole was drilled to TD of 9640’ where 7” casing was run and cemented in place with 143 bbls of 12ppg lead followed by 32 bbls of 15.8 ppg tail. TOC for production casing calculated at 9021’ MD/-6296’ TVDss, top of Kuparuk interval at -6570’ TVDss. L-112a:After cementing the surface casing, the 8-3/4” production hole was drilled to TD of 9640’ where 7” casing was run and cemented in place with 143 bbls of 12ppg lead followed by 32 bbls of 15.8 ppg tail. TOC for production casing calculated at 9021’ MD/-6296’ TVDss, top of Kuparuk interval at -6570’ TVDss. L-114:After cementing the surface casing in place, the production hole was drilled with a few tight spots noted. It was landed and cemented with 102 bbls of 12 ppg LiteCrete cement, plug was bumped and held at 2100 psi, final circ pressure was 1700 psi. No CBL exists of the production casing interval. When the well was sidetracked to L-114A, the reservoir was abandoned via service coil in two attempts: the first try used 9.7 bbls of 15.8 ppg classG but still had injectivity. The second plug used 11.3 bbls of classG and achieved a good hesitation squeeze. The tubing was chemical cut at 7213’ then the rig showed up and pull completion then set an EZSV plug at 2770’ and finally cut and pulled the production casing at 2627’. A 14 bbl plug of 17 ppg classG cement was balanced on top of the EZSV and stub from 2775’ to 2406’. TOC for production casing calculated at 4077’ MD/-3553’ TVDss, top of Kuparuk interval at -6497’ TVDss. L-114a:After cementing the surface casing in place, the production hole was drilled with a few tight spots noted. It was landed and cemented with 102 bbls of 12 ppg LiteCrete cement, plug was bumped and held at 2100 psi, final circ pressure was 1700 psi. No CBL exists of the production casing interval. When the well was sidetracked to L-114A, the reservoir was abandoned via service coil in two attempts: the first try used 9.7 bbls of 15.8 ppg classG but still had injectivity. The second plug used 11.3 bbls of classG and achieved a good hesitation squeeze. The tubing was chemical cut at 7213’ then the rig showed up and pull completion then set an EZSV plug at 2770’ and finally cut and pulled the production casing at 2627’. A 14 bbl plug of 17 ppg classG cement was balanced on top of the EZSV and stub from 2775’ to 2406’. TOC for production casing calculated at 4077’ MD/-3553’ TVDss, top of Kuparuk interval at -6497’ TVDss. L-111:After cementing the surface casing, the 8-3/4” production hole was drilled to TD of 7605’ MD where 7” casing was run (shoe at 7598’ MD)and cemented in place with 42 bbls of 15.8 ppg GasBlok, TOC at 6430’ MD (-5973’ TVDss).The TAM port collar was then opened at 5,243’ MD and 57 bbls of 15.8 ppg cement was pumped.TOC for production casing calculated at 3605’ MD / -3228’ TVDss, top of Kuparuk interval at -6536’TVDss. L-122:The 5-1/2” x 3-1/2” production casing/liner was run and cemented on 5-28-2003. Cementing operations consisted of pumping 64 bbls of 12.5 ppg lead followed by 33 bbls 15.8 ppg tail. Plug was bump at calculated strokes. No CBL exists for the production casing section. TOC for production casing calculated at 6024’ MD/-4044’ TVDss, top of Kuparuk interval at -6380’ TVDss. L-122L1:The 5-1/2” x 3-1/2” production casing/liner was run and cemented on 5-28-2003. Cementing operations consisted of pumping 64 bbls of 12.5 ppg lead followed by 33 bbls 15.8 ppg tail. Plug was bumped at calculated strokes. No CBL exists for the production casing section. TOC for production casing calculated at 6024’ MD/-4044’ TVDss, top of Kuparuk interval at -6380’ TVDss. TOC for production casing calculated at 4077’ MD/-3553’ TVDss, t TOC for production casing calculated at 4077’ MD/-3553’ TVDss, TOC for production casing calculated at 6024’ MD/-4044’ TVDss, TOC for production casing calculated at 9021’ MD/-6296’ TVDss, No CBL e TOC for production casing calculated at 9021’ MD/-6296’ TVDss, t SECTION 11: LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283, A, 11 Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates that there are 9 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 L-112A. 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 ~14ppg. Faults 1-9 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. L-112A crossed fault #1 at 10185’md and crossed fault #9 at 11540’md. The wellbore trajectory is a long lateral. Maximum stress direction is estimated to be ~30 deg W of N. The fracs should not reach any of the mapped faults. The first frac is 1680’ from fault #1, 500’ from fault #2, 550’ from fault #3, 1050’ from fault #4 and 200’ from fault #9. The second frac is 1360’ from fault #1, 380’ from fault #2, 810’ from fault #3, 830’ from fault #4 and 150’ from fault #9. The third frac is 900’ from fault #1, 320’ from fault #2, 1280’ from fault #3, 540’ from fault #4 and 590’ from fault #9. The maximum anticipated fracture half-length of 200’ is well short of theses distances. Half-length is modeled using hydraulic fracture modelling software and is corroborated by what we have seen in other frac treatments. The frac stages should have sufficient offset to faults #1, #2, #3, #4 and #9 and should not intersect. 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 Top Bottom 1 0-30' DTW HRZ Kingak 2 0-100' DTS HRZ Kingak 3 0-100' DTW Colville Ivishak 4 0-235' DTW Colville Basement 5 0-230' DTS Sagavanirktok Basement 6 80-230' DTW Sagavanirktok Basement 7 90-180' DTSW Sagavanirktok Basement 8 0-50' DTS HRZ Miluveach 9 10' DTE HRZ Miluveach 320’ from fault #2 150’ from fault #9. from fault #9. T e frac stages should have sufficient offset to faults #1, #2, #3, #4 and #9 and should not intersect. 200’ f ~14ppg. Fracture gradients within the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation a 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 Table 5– Anticipated Pressures MIT-T 4395 psi MIT-IA 4440 psi Maximum Anticipated Treating Pressure:6800 psi @ 20 BPM IA Pop-off Set Pressure (~95% of MIT-IA):4200 psi IA Minimum Hold Pressure (POP-off – 300 psi):3900 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1):7895 psi w/ 3900 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:7105 – 7500 psi Global Kickout (95% of MATP):7500 psi N2 POP-off set pressure (MATP):7895 psi Treating Line Test Pressure (MATP + 1000 psi):8895 psi OA Pressure:Monitor Max Anticipated Proppant Loading:8 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 lateral of the well is drilled perpendicular to the maximum horizontal stress meaning the induced fracture will also be perpendicular to the wellbore. The toe frac will be nearly parallel to the maximum horizontal stress so the fracture there should parallel the wellbore. Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 11,747 -6580 -6655 ~200’ 2 11,405 -6585 -6665 ~200’ 3 10,919 -6590 -6670 ~200’ 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. Frac Locations indicated by Red Lines,the stars were Frac Modelling: Maximum Anticipated Treating Pressure: ~6800 psi Surface pressure is calculated based on a closure pressure of ~0.62 psi/ ft or ~4100 psi. Closure pressure plus anticipated net pressure to be built (500 psi) and friction pressure minus hydrostatic results in a surface pressure of ~3100 psi at the time of flush. 4100 psi (closure)+600 psi (net)+6500 psi (friction)-4400 psi (hydrostatic)=6800 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 ~69 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 ~275 ft.e modeled frac is anticipated to reach a half-length of ~275 ft. Average confining layer stress is anticipated to be ~0.7 psi/ ft limiting fracture height to ~69 ft TVD. closure pressure of ~0.62 psi/ ft or ~4100 psi. Pre-Job Anticipated Chemicals to be pumped: 182,910 gal 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 10% water cut and 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. 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 : S e p t e m b e r 7 , 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 L - 1 1 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 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-508, which Supersedes 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 September 11, 2023 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 9/11/2023 (a)(2) Plat Provided with application. SFD 9/11/2023 (a)(2)(A) Well location Well lies in Sections 34, 33, and 32 of T12N, R11E, UM. SFD 9/11/2023 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online 9/11, 2023), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of PBU L-112A. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of PBU L-112A. SFD 9/11/2023 (a)(2)(C) Identify all well types within ½ mile List of all wells within ½-mile radius of the PBU L-112A well path is provided with application. SFD 9/11/2023 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the Western Operating Area of the PBU per the Findings and Conclusion of Aquifer Exemption Order 1. For an outline of the EPA’s current Aquifer Exemption Area for the Prudhoe Bay Unit, see the EPA’s “Alaska Oil & Gas Aquifer Exemptions Interactive Map” available online under the “Permits” section of EPA Region 10’s web page at https://www.epa.gov/uic/underground-injection-control- region-10-ak-id-or-and-wa. SFD 9/11/2023 (a)(4) Baseline water sampling plan None required: No freshwater aquifers are present. SFD 9/11/2023 (a)(5) Casing and cementing information Provided with application. schematic attached. CDW 05/02/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-508, which Supersedes 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 September 11, 2023 (a)(6) Casing and cementing operation assessment 9-5/8” surface casing cemented to surface with 75 bbl returns. 7” casing cemented without issue and full returns. CTD L-112A lateral. Liner cement job didn’t establish returns. Packer squeeze performed. Liner backside cement squeeze performed. CBL showed cement tops and pressure tests were passes. No new issues with cement for the upcoming stimulation. CDW 05/02/2023 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 9/11/2023 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface casing in parent wellbore PBU L-112 was set at 3,109’ MD (-2.587’ TVDSS) and cemented with 73 barrels of cement returns at surface. For PBU L-112, 8-3/4” hole was drilled from the base of to total depth of 9,640’ MD (-6,876’ TVDSS). The 7” casing shoe is set at 9,612’ MD (-3,850’ TVDSS). Top of tail cement is estimated at about 8,692’ MD (-6,001’ TVDSS), which is above the HRZ, so the Kuparuk sands are likely cemented in L-112. Top of lead cement in PBU L-112 is calculated at about 4,661’ MD (-3,447’ TVDSS), so the Schrader Bluff is likely cemented in PBU L-112. PBU L-112A kicked off through a window milled at 9,390’ MD (--6,641’ TVDSS) within the Kuparuk C sand and drilled to total depth. In L-112A production casing was run to 11,753’ MD (-6,600’ TVDSS) and cemented. Volumetric calculations and the operator’s CMIT testing indicate cement is above the window at 9,390’ SFD 4/26/2023 9/11/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-508, which Supersedes 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 September 11, 2023 MD (-6,641’ TVDSS), so hydrocarbon zones are cement- isolated. (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 4440 psi MITIA, 4395 psi MITT completed. CDW 09/11/2023 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi treesaver planned. Max anticipated frac pressure of 6800 psi. Pump knock out 7105- 7500 psi. GORV 7895 psi., lines test 8895 psi are all revised. CDW 09/11/2023 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: HRZ, Kalubik, and Kuparuk D shale, mudstone, and siltstone with an aggregate thickness of about 445’ true vertical thickness (TVT). Fracture gradient is expected to range from about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). Fracturing Zone: Kuparuk C sand interval. Fracture gradient expected to range from about 0.62 psi/ft (11.9 ppg EMW). Lower confining zones: Kuparuk B, which is about 150’ thick in this area, consists of interbedded mudstone/shale with thin lenses of sandstone. Fracture gradient is expected to range from about 0.65 psi/ft (12.5 ppg EMW). Underlying Kuparuk A interval consisting of sandstone and siltstone is expected to be about 70’ thick, with a fracture gradient expected to range from about 0.65 psi/ft (12.5 ppg EMW). The Miluveach and underlying Kingak consist of shale, mudstone, and siltstone not penetrated by L-112A, but the aggregate thickness in nearby well NW Eileen State 1 is about 1,860’ TVT. Fracture gradient is expected to range from about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). SFD 4/26/2023 9/11/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-508, which Supersedes 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 September 11, 2023 (a)(10) Location, orientation, report on mechanical condition of each well Over 100 wells on L-pad. Hilcorp provided a table and plot. Hilcorp has provided isolation information on the 5 wells and laterals in the frac zone. CDW 05/02/2023 (a)(11) Sufficient information to determine wells will not interfere with containment within ½ mile Yes. There are seven wells and wellbores within ½ mile of PBU L-112A: L-111, L-112, L-114, L-114A, L-114B, L-122, and L-122L1. Although there are no cement evaluation logs available for these wells, volumetric calculations by the operator and confirmed by AOGCC indicate that it is highly likely that the Kuparuk sands are cement-isolated in each well. SFD 4/28/2023 9/11/2023 (a)(11) Faults and fractures, Location, orientation (a)(11) Faults and fractures, Sufficient information to determine no interference with containment within ½ mile None. The operator has identified 9 faults on seismic data within a ½-mile radius of PBU L-112A. The three nearest faults, numbered 3, 2, and 9, have azimuths of 350°, 285°, and 0°, respectively. The maximum regional stress direction is estimated to have an azimuth of about 330° in this area. The modeled half-length of the induced fractures is about 275’, and the closest approach of these planned induced fractures to the mapped faults is about 75’ (distance from the NW tip of Stage 2 fracture to the northern tip of Fault 9). This particular fault displays a vertical displacement of about 10 feet, and it dies out within the overlying, confining HRZ shale. It is unlikely that Fault 9 or any of the other mapped faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. SFD 4/27/2023 9/11/2023 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/02/2023 (a)(12)(A) Estimated volume Provided with application. 3 interval frac, 4334 bbl total dirty vol. 500K lb total proppant CDW 09/11/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-508, which Supersedes 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 September 11, 2023 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/02/2023 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided with no proprietary chemicals listed as planned. CDW 05/02/2023 (a)(12)(D) Inert substances , weight or volume of each Provided with application. CDW 05/02/2023 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 6800 psi. Max. 7895 psi allowable treating pressure based on MITT of 4395 psi and anticipated IA hold pressure of 3900 psi. Hilcorp table with anticipated pop offs and line test pressures are now revised this sundry. With 3900 psi back pressure on IA (IA popoff set 4200 psi), max tubing differential should be 2900 psi. CDW 09/11/2023 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures are 200’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be less than 100’ (shallowest top TVDSS of about -6,580’ and deepest base TVDSS of about -6,670’, so induced fractures will likely penetrate into, but not through, the overlying confining interval that displays an aggregate vertical thickness of about 445’ in this area. SFD 4/27/2023 9/11/2023 (a)(13) Proposed program for post- fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. CDW 09/11/2023 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3900 psi back pressure, tested to 4440 psi 03/29/2023, popoff set as 4200 psi CDW 05/02/2023 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing TOC from CBL 27MAR23 in IA as 8681 ft. TOC on 2-3/8” bonsai completion per CBL 27-JAN-23 is at the tubing tail 9,176’ MD. Should provide hydraulic isolation for fracturing. MGR 5/2/23 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-508, which Supersedes 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 September 11, 2023 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 4395 psi completed 09/03/2023. Max pressure differential is estimated as 2900 psi (6800 with 3900 psi backpressure) so test of 4395 psi satisfies 110%. Max pressure differential can be 3995 psi (7895 with 3900 psi backpressure) so test of 4395 psi satisfies 110%. CDW 09/11/2023 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device Corrected pump knock outs and line test pressure of 8895 psi is estimated 1000 psi above expected max. Allowable frac treating pressure CDW 09/11/2023 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/02/2023 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 4200 psi. Surface annulus open. Frac pressures continuously monitored. CDW 05/02/2023 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 05/02/2023 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). SFD 9/11/2023 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Development well – not confidential SFD 9/11/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-508, which Supersedes 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 September 11, 2023 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. DATA SUBMITTAL COMPLIANCE REPORT API No.50-029-23129-01-00Well Name/No.PRUDHOE BAY UN BORE L-112A Completion Status 1-OILCompletion Date 1/17/2023 Permit to Drill 2221380 Operator Hilcorp North Slope, LLC MD 12138 TVD 6676 Current Status 1-OIL 8/17/2023 UIC No Well Log Information: Digital Med/Frmt ReceivedStart Stop OH / CH Comments Log Media Run No Electr Dataset Number Name Interval List of Logs Obtained:MWD / GR / RES, Cement Evaluation NoNo YesMud Log Samples Directional Survey REQUIRED INFORMATION (from Master Well Data/Logs) DATA INFORMATION Log/ Data Type Log Scale DF 2/17/20239053 12138 Electronic Data Set, Filename: PBU L-112A Digital Data.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 1.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 2.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 3.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 4.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 5.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 6.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 7.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 8.las 37503ED Digital Data DF 2/17/2023################Electronic Data Set, Filename: PBU L-112A PWD Run 9.las 37503ED Digital Data DF 2/17/2023 Electronic File: PBU L-112A 2MD Final Log.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 2TVDSS Final Log.cgm 37503ED Digital Data DF 2/17/2023 Electronic File: PBU L-112A 5MD Final Log.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 5TVDSS Final Log.cgm 37503ED Digital Data Thursday, August 17, 2023AOGCC Page 1 of 4 PBU L-112A Digital Data.las DATA SUBMITTAL COMPLIANCE REPORT API No.50-029-23129-01-00Well Name/No.PRUDHOE BAY UN BORE L-112A Completion Status 1-OILCompletion Date 1/17/2023 Permit to Drill 2221380 Operator Hilcorp North Slope, LLC MD 12138 TVD 6676 Current Status 1-OIL 8/17/2023 UIC No DF 2/17/2023 Electronic File: PBU L-112A PWD Run 01.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 02.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 03.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 04.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 05.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 06.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 07.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 08.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 09.cgm37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 2MD Final Log.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 2TVDSS Final Log.PDF 37503ED Digital Data DF 2/17/2023 Electronic File: PBU L-112A 5MD Final Log.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 5TVDSS Final Log.PDF 37503ED Digital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 01.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 02.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 03.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 04..PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 05.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 06.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 07.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 08.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 09.PDF37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 2MD Final Log.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 2TVDSS Final Log.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 5MD Final Log.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A 5TVDSS Final Log.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 01.tif37503EDDigital Data Thursday, August 17, 2023AOGCC Page 2 of 4 DATA SUBMITTAL COMPLIANCE REPORT API No.50-029-23129-01-00Well Name/No.PRUDHOE BAY UN BORE L-112A Completion Status 1-OILCompletion Date 1/17/2023 Permit to Drill 2221380 Operator Hilcorp North Slope, LLC MD 12138 TVD 6676 Current Status 1-OIL 8/17/2023 UIC No Well Cores/Samples Information: ReceivedStart Stop Comments Total Boxes Sample Set NumberName Interval INFORMATION RECEIVED DF 2/17/2023 Electronic File: PBU L-112A PWD Run 02.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 03..tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 04.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 05.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 06.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 07.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 08.tif37503EDDigital Data DF 2/17/2023 Electronic File: PBU L-112A PWD Run 09.tif37503EDDigital Data DF 2/17/2023 Electronic File: L-112A Definitive Surveys.pdf37503EDDigital Data DF 2/17/2023 Electronic File: L-112A Definitive Surveys.xlsx37503EDDigital Data DF 4/17/20237705 8773 Electronic Data Set, Filename: L-112A_27-Mar- 23_MainUpPass30fpm.las 37603ED Digital Data DF 4/17/2023 Electronic File: PBU_L-112A_27-Mar- 23_MemoryRadialCementBondLog.pdf 37603ED Digital Data DF 4/17/2023 Electronic File: PBU_L-112A_27-Mar- 23_MemoryRadialCementBondLog.tif 37603ED Digital Data DF 5/3/2023 Electronic File: 22532-L-112-A-Mem-RBT-26- Mar-23 Field Print.pdf 37624ED Digital Data DF 5/3/2023 Electronic File: PBU_L-112_06-Jan- 23_MemoryRadialCementBondLog.pdf 37624ED Digital Data DF 5/3/2023 Electronic File: RE_ [EXTERNAL] RE_ L-112 RBT Log.pdf 37624ED Digital Data Thursday, August 17, 2023AOGCC Page 3 of 4 DATA SUBMITTAL COMPLIANCE REPORT API No.50-029-23129-01-00Well Name/No.PRUDHOE BAY UN BORE L-112A Completion Status 1-OILCompletion Date 1/17/2023 Permit to Drill 2221380 Operator Hilcorp North Slope, LLC MD 12138 TVD 6676 Current Status 1-OIL 8/17/2023 UIC No Completion Report Production Test Information Geologic Markers/Tops Y Y / NA Y Comments: Compliance Reviewed By:Date: Mud Logs, Image Files, Digital Data Composite Logs, Image, Data Files Cuttings Samples Y / NA Y Y / NA Directional / Inclination Data Mechanical Integrity Test Information Daily Operations Summary Y Y / NA Y Core Chips Core Photographs Laboratory Analyses Y / NA Y / NA Y / NA COMPLIANCE HISTORY Date CommentsDescription Completion Date:1/17/2023 Release Date:12/14/2022 Thursday, August 17, 2023AOGCC Page 4 of 4 M. Guhl 8/21/2023 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 L-112A Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 222-138 50-029-23129-01-00 CO 736 ADL 0028239 12138 Conductor Surface Intermediate Production Liner 6676 80 3074 9358 2996 11749 20" 9-5/8" 7" 2-3/8" 6683 36 - 116 35 - 3109 32 - 9390 8757 - 11753 1568 36 - 116 35 - 2670 32 - 6723 6139 - 6682 None 470 3090 5410 11780 None 1490 5750 7240 11200 10901 - 11749 3-1/2" 9.2# L-80 29 - 91766679 - 6683 Structural 3-1/2" Baker S-3 Packer No SSSV Installed 9118, 6468 No SSSV Installed Date: Torin Roschinger Area Operations Manager Brodie Wages David.Wages@hilcorp.com 907.564.5006 PRUDHOE BAY 5/8/2023 Current Pools: BOREALIS OIL Proposed Pools: BOREALIS 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 323-255 By Kayla Junke at 10:41 am, Apr 25, 2023 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.04.24 16:46:24 -08'00' Torin Roschinger (4662) , ADL0047449 SFD 1568 SFD 4/28/2023 DSR-4/26/23MGR04MAY23 10-404 CDW 05/02/2023 Fracture Stimulate JLC 5/4/2023 5/4/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.04 10:37:22 -08'00' RBDMS JSB 050823 Post-CTD 3-stage Frac Well: L- 112A Well Name:L-112A API Number:50-029-23129 Current Status:Operable Producer Estimated Start Date:5/08/2023 Rig:SL/Coil/frac/testers Sundry #:Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker First Call Engineer:Brodie Wages (907) 564-5006 (O)(713) 380-9836 (M) Second Call Engineer:Claire Mayfield (509)-670-8001 (M) Current Bottom Hole Pressure:2228 psi @ 6600’ TVD 6.5 PPGE | Lower bound Max. Anticipated Surface Pressure:1568 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:753 psi (Taken on 11/17/22) Min ID:2.813” X at 2637’ MD Max Angle:59 Deg @ 5400’ MD MITs: 3/29/2023: MIT-IA to 4440 psi 3/27/2023: MIT-T to 3752 psi Formation Tops: x Ugnu: 3396’ MD, 2828’ TVD x Shrader Bluff N sands: 5889’ MD, 4188’ TVD x HRZ: 8878’ MD, 6247’ TVD x Kuparuk: 9313’ MD, 6651’ TVD Brief Well Summary: A CTD sidetrack of producer L-112 has been drilled west of L-112. The sidetrack will further develop a fault block that L- 112 has already proved up. After CDR drilled the lateral, the completion consisting of ball drop frac sleeves in the toe then a swell packer and cementing valve mid lateral and solid pipe all the way back to the motherbore with a deployment sleeve was cemented in place. Unfortunately, the cement job did not cover the hole in the tubing. And the liner was landed high so the coil liner deployment sleeve is above the hole which is behind the coil liner. We cannot access the hole with mechanical means so the solution is a cement packer squeeze. Post rig operations on L-112 have resulted in a successful bonsai cement job to isolate the frac locations from the motherbore, a successful packer squeeze to remediate a known tubing leak and verification that we can still pump into the wellbore. Notes Regarding Wellbore Condition x Drill 1/14/2003 x 2/17/2003: Eline – Perforate x 2/22/2003: Frac – 210k# 16-20, max treat: 6467 psi, ave: 5555 psi x Many many HOTs, Coil FCO, B&Fs since. Uneventful well Objective: x 3 stage ball drop frac Schrader Bluff SFD Post-CTD 3-stage Frac Well: L- 112A 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 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. RU and set treesaver per OilStates rep 4. Drop Stage 1 ball a. We may not see it land on seat, but we want to ensure all fluid is exiting out of the frac sleeve and not split between the sleeve and the shoe 5. Frac stage 1 – 3 per pump schedule MIT-T 3752 psi MIT-IA 4440 psi Maximum Anticipated Treating Pressure:6570 psi @ 20 BPM IA Pop-off Set Pressure (~95% of MIT-IA):4200 psi IA Minimum Hold Pressure (POP-off – 300 psi):3900 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T):7650 psi w/ 3900 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:6885 - 7260 Global Kickout (95% of MATP):7260 psi N2 POP-off set pressure (MATP + 1000 psi):8650 psi Treating Line Test Pressure (MATP + 1000 psi):8700 psi OA Pressure:Monitor Max Anticipated Proppant Loading:8 PPA x The pump schedule is designed to where most of our proppant is away at less than 3 ppa, we’ve seen problems when trying to obtain higher than 4+ ppa. However, when pump rate is reduced to 15 bpm, our fluid seems to arrive on perforation in better quality and higher sand concentrations can be achieved. x When fracing 2-3/8” liners, we should be 15 BPM from 4 ppa and above x If treating pressure starts acting sporadic, consider dropping rate to as low as 12 ppa. If it is acting up at 12 ppa, we should be on flush. With a MITT of 3752 psi, Max frac string differential is 3411 psi for 110% testing requirement. This equates to a MATP of 7311psi for a 3900 psi IA hold pressure. CDW 05/02/2023 Pressure test tree saver to 8311 psi. Pressure test IA pop off to 4200 psi. Pressure test treating lines 8311 psi Pressure test pump trips 6579 -6945 psi - mgr Post-CTD 3-stage Frac Well: L- 112A Coil Tubing 1. MIRU and pressure test 2. MU milling assembly for ball seats a. Ensure we are using high strength coil for needed overpulls b. Refer to L-122 milling BHA for optimal mill to use 3. Mill ball seats to minimum stage 1 frac sleeve a. We don’t necessarily need to mill out stage 1, we just need the sand off it. 4. POH Slickline This step may need to be performed prior to coil FCO if stable returns cannot be established 1. Drift, install catcher 2. Install LGLVs 3. Pull catcher 4. RDMO 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. Current Wellbore Schematic 2. Fracture Stimulation Detail 3. Sundry Change form Post-CTD 3-stage Frac Well: L- 112A Current WBD: Post-CTD 3-stage Frac Well: L- 112A Liner Details: L-112a Date: April 24, 2023 Subject: L-112A Fracture Stimulation From: David Wages O: (907) 564-5006 C: (713) 380-9836 To: AOGCC Estimated Start Date: 5/15/2023 Attached is Hilcorp’s proposal and supporting documents to perform a 3 stage fracture stimulation on well L-112A in the Kuparuk reservoir of the Prudhoe Bay Unit. A CTD sidetrack of producer L-112 is has been drilled west to further develop a fault block that L-112 has already proved up. After CDR drilled the lateral, the completion consisting of ball drop frac sleeves in the toe then a swell packer and cementing valve mid lateral and solid pipe all the way back to the motherbore with a deployment sleeve was run. After the swell packer had had time to set, service coil cemented uphole of the packer through the cementing valve back to the motherbore and deployment sleeve. This completion is designed to leave the toe uncemented while isolating the motherbore with bonsai cement per program/WBD attached. Unfortunately, while deploying the liner, CTD was unable to get it all the way to bottom. The liner deployment sleeve was left high in the tubing and was covering a known tubing hole. The original intent was to install a high pressure patch over the hole but due to the new wellbore geometry, service coil was sent out to perform a packer squeeze to address the hole. After cementing operations, a successful MIT-T and MIT-IA was obtained making the well ready for fracture treatment operations. Once fracturing operations are complete, service coil will mill out the ball seats then slickline work to get the live gas lift valves installed and the well POP’d through test separator. 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 David Wages. Estimated Start Date: 5/15/2023 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 SIGNED AFFIDAVIT: COPY OF NOTIFICATION SENT VIA EMAIL: SECTION 2: PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25. 283, a, 2): 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 IGNIKSIKUMI1 Exploratory Abandoned L-201L2 Development Oil Well L-01 Development Abandoned L-201L3 Development Oil Well L-01A Development Oil Producer Shut-In L-201L3PB1 Development Plugged Back For Redrill L-02 Development Abandoned L-201PB1 Development Plugged Back For Redrill L-02A Development Abandoned L-201PB2 Development Plugged Back For Redrill L-02APB1 Development Plugged Back For Redrill L-202 Development Oil Producer Gas Lift L-02B Development Oil Producer Shut-In L-202L1 Development Oil Producer Gas Lift L-02PB1 Development Plugged Back For Redrill L-202L2 Development Oil Producer Flowing L-03 Development Abandoned L-202L3 Development Oil Producer Flowing L-03A Development Suspended L-203 Development Oil Producer Shut-In L-03APB1 Development Plugged Back For Redrill L-203L1 Development Oil Well L-04 Service Water Injector Shut-In L-203L2 Development Oil Well L-100 Development Oil Producer Shut-In L-203L2-01 Development Oil Well L-101 Development Oil Producer Gas Lift L-203L3 Development Oil Well L-102 Development Oil Producer Gas Lift L-203L3PB1 Development Plugged Back For Redrill L-102PB1 Development Plugged Back For Redrill L-203L3PB2 Development Plugged Back For Redrill L-102PB2 Development Plugged Back For Redrill L-203L4 Development Oil Well L-103 Service Water Injector Injecting L-204 Development Oil Producer Gas Lift L-104 Development Oil Producer Gas Lift L-204L1 Development Oil Producer Gas Lift L-105 Service Miscible Injector Operating L-204L2 Development Oil Producer Gas Lift L-106 Development Abandoned L-204L3 Development Oil Producer Gas Lift L-106A Development Oil Producer Gas Lift L-204L4 Development Oil Producer Gas Lift L-107 Development Oil Producer Shut-In L-205 Development Abandoned L-108 Service Water Injector Injecting L-205A Development Oil Producer Gas Lift L-109 Service Water Injector Injecting L-205L1 Development Abandoned L-110 Development Oil Producer Shut-In L-205L2 Development Abandoned L-111 Service Water Injector Injecting L-205L3 Development Abandoned L-112 Development Oil Producer Gas Lift L-205L4 Development Abandoned L-114 Development Abandoned L-205L5 Development Abandoned L-114A Development Abandoned L-205PB1 Development Plugged Back For Redrill L-114B Development Oil Producer Shut-In L-206 Development Oil Producer Gas Lift L-115 Service Water Injector Injecting L-207 Development Oil Producer Gas Lift L-116 Development Abandoned L-210 Service Water Injector Injecting L-116A Development Oil Producer Shut-In L-210PB1 Service Plugged Back For Redrill L-117 Service Miscible Injector Operating L-211 Service Water Injector Injecting L-118 Development Oil Producer Gas Lift L-211PB1 Service Plugged Back For Redrill L-118L1 Development Oil Well L-212 Service Water Injector Injecting L-119 Service Abandoned L-212PB1 Service Plugged Back For Redrill L-119A Service Miscible Injector Operating L-212PB2 Service Plugged Back For Redrill L-119APB1 Service Plugged Back For Redrill L-213 Service Water Injector Injecting L-120 Development Oil Producer Flowing L-214 Service Abandoned L-121 Development Abandoned L-214A Service Water Injector Injecting L-121A Development Oil Producer Gas Lift L-215 Service Miscible Injector Shut-In L-122 Development Oil Producer Gas Lift L-216 Service Water Injector Shut-In L-122L1 Development Oil Producer Shut-In L-217 Service Water Injector Injecting L-123 Service Miscible Injector Shut-In L-218 Service Water Injector Injecting L-123PB1 Development Plugged Back For Redrill L-219 Service Miscible Injector Shut-In L-124 Development Oil Producer Shut-In L-220 Service Water Injector Shut-In L-124PB1 Development Plugged Back For Redrill L-221 Service Water Injector Shut-In L-124L1 Development Oil Producer Shut-In L-222 Service Miscible Injector Operating L-124L1PB1 Development Plugged Back For Redrill L-223 Service Water Injector Shut-In L-124PB2 Development Plugged Back For Redrill L-240 Service Miscible Injector Operating L-200 Development Abandoned L-240PB1 Service Plugged Back For Redrill L-200A Development Oil Producer Gas Lift L-250 Development Oil Producer Shut-In L-200L1 Development Abandoned L-250L1 Development Oil Producer Gas Lift L-200L2 Development Abandoned L-250L2 Development Oil Producer Gas Lift L-201 Development Oil Producer Gas Lift L-250PB1 Development Plugged Back For Redrill L-201L1 Development Oil Well L-50 Development Oil Producer Shut-In L-201L1PB1 Development Plugged Back For Redrill L-50PB1 Development Plugged Back For Redrill SECTION 3: EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25. 283, a, 3): Well L-112A 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.Concur. SFD 4/26/2023 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 Concur. SFD 4/26/2023 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: 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: After spudding the well on 1/1/2003, a 12-1/4” surface casing hole was uneventfully drilled and 9-5/8” 40# L-80 surface casing was run and set at 3109’. It was cemented in place with 365 bbls ArcticSetIII lead followed by 75 bbls ClassG tail. Had 75 bbls of cement returns, the plug held and the hole stayed full throughout the job. The 7” casing production hole was drilled without issue, the casing was cemented in place with full returns and a bumped plug that held. The drilling rig was released from the well on 1/12/2003. During CTD screening, a tubing leak at ~9070’ was identified just above the sliding sleeve in the well. After evaluation, it was determined that we could set a high pressure patch over the hole after drilling the lateral. On 1/8/2023, CTD milled the window for the L-112a lateral. While drilling the lateral, a fault was crossed where the reservoir pressure was lower than that at the motherbore causing concerns about the drilling rig performing the primary cement job. Upon running the liner, CTD was unable to get the completion to TD and left the top of liner at 8757’, ~300’ above the identified hole in tubing. Post rig operations commenced to first pump the primary cement job, this went well with 16 bbls of cement pumped. However, returns were lost just before final flush volume was pumped so the TOC did not get above the hole in the tubing. A CMIT passed to 3000 psi. this means the cement is above the CTD window, but below the hole in tubing and liner top. An amended sundry was submitted and approved to pump a packer squeeze to establish tubing integrity. Service coil rigged up again and pumped 11.2 bbls of cement down the liner backside. A follow up CBL showed good cement in the tubing annulus 8677’ and a subsequent MIT-T to 3752 psi and an MIT-IA to 4440 psi was obtained. All casing is cemented in accordance with 210 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. The frac in 2006 had a max treating pressure of 7800 psi which is similar to what our max pressure would be in the planned frac. 75 bbls of cement returns, Maximum anticipated frac pressure is stated as 6570 psi @ 20bpm. CDW 05/02/2023. A CMIT passed to 3000 psi. this means the cement is above the CTD window, but below the hole in tubing and liner top. A SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL 20 AAC 25.283, A, 7 On 3/29/2023, the production casing was pressure tested to 4440 psi for a passing MIT-IA On 3/27/2023, the tubing was pressure tested to 3752 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. Maximum Treating Pressure 7311 psi - mgr Tree Saver Test Pressure 8311 psi - mgr Minimum Annulus Pressure 3900 psi - mgr IA Pop off 4200 psi - mgr IA test to 4440 psi Tubing tested to 3750 psi Treating line test pressure MATP + 1000 8311 psi - mgr Pump trip 90% - 95% (MATP) 6579 psi - 6946 psi - mgr 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 9-5/8” Surface Casing 40#L80 5750 3090 7” Production Casing 26#13Cr-80 7240 5410 3-1/2” Production Tubing 9.2#L80 10160 10540 2-3/8” Production Liner 4.7#L80 11200 11780 Wellhead FMC manufactured wellhead, rated to 5, 000 psi. Tubing head adaptor: 11" 5, 000 psi x 4-1/16" 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 outlets Tree: CIW 4-1/16" 5,000 psi A 10k psi rated TreeSaver will be used during these fracturing operations: 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 8878 9130 -6165 -6397 231 0.7 Shale TKLB 9130 9314 -6397 -6570 173 0.7 Shale Top Kup D Shale 9314 9358 -6570 -6611 42 0.65 Shale Top Kup/C interval 9358 9517 -6611 -6760 149 0.62 Silts/SS LCU/ Kuparuk B 9517 --6760 -6907 147 0.65 Silts/SS *Kuparuk A ---6907 -6980 73 0.65 Silts/SS *Miluveach --6980 --0.7 Shale * estimated thickness from L-114 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 L-112A 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. Casing and Cement assessments for all wells that transect the confining zone: L-112:After cementing the surface casing, the 8-3/4” production hole was drilled to TD of 9640’ where 7” casing was run and cemented in place with 143 bbls of 12ppg lead followed by 32 bbls of 15.8 ppg tail. TOC for production casing calculated at 9021’ MD/-6296’ TVDss, top of Kuparuk interval at -6570’ TVDss. L-112A:After cementing the surface casing, the 8-3/4” production hole was drilled to TD of 9640’ where 7” casing was run and cemented in place with 143 bbls of 12ppg lead followed by 32 bbls of 15.8 ppg tail. TOC for production casing calculated at 9021’ MD/-6296’ TVDss, top of Kuparuk interval at -6570’ TVDss. L-114:After cementing the surface casing in place, the production hole was drilled with a few tight spots noted. It was landed and cemented with 102 bbls of 12 ppg LiteCrete cement, plug was bumped and held at 2100 psi, final circ pressure was 1700 psi. No CBL exists of the production casing interval. When the well was sidetracked to L-114A, the reservoir was abandoned via service coil in two attempts: the first try used 9.7 bbls of 15.8 ppg classG but still had injectivity. The second plug used 11.3 bbls of classG and achieved a good hesitation squeeze. The tubing was chemical cut at 7213’ then the rig showed up and pull completion then set an EZSV plug at 2770’ and finally cut and pulled the production casing at 2627’. A 14 bbl plug of 17 ppg classG cement was balanced on top of the EZSV and stub from 2775’ to 2406’. TOC for production casing calculated at 4077’ MD/-3553’ TVDss, top of Kuparuk interval at -6497’ TVDss. L-114A:After cementing the surface casing in place, the production hole was drilled with a few tight spots noted. It was landed and cemented with 102 bbls of 12 ppg LiteCrete cement, plug was bumped and held at 2100 psi, final circ pressure was 1700 psi. No CBL exists of the production casing interval. When the well was sidetracked to L-114A, the reservoir was abandoned via service coil in two attempts: the first try used 9.7 bbls of 15.8 ppg classG but still had injectivity. The second plug used 11.3 bbls of classG and achieved a good hesitation squeeze. The tubing was chemical cut at 7213’ then the rig showed up and pull completion then set an EZSV plug at 2770’ and finally cut and pulled the production casing at 2627’. A 14 bbl plug of 17 ppg classG cement was balanced on top of the EZSV and stub from 2775’ to 2406’. TOC for production casing calculated at 4077’ MD/-3553’ TVDss, top of Kuparuk interval at -6497’ TVDss. L-111:After cementing the surface casing, the 8-3/4” production hole was drilled to TD of 9640’ where 7” casing was run and cemented in place with 143 bbls of 12ppg lead followed by 32 bbls of 15.8 ppg tail. TOC for production casing calculated at 9021’ MD/-6296’ TVDss, top of Kuparuk interval at -6570’ TVDss. L-122:The 5-1/2” x 3-1/2” production casing/liner was run and cemented on 5-28-2003. Cementing operations consisted of pumping 64 bbls of 12.5 ppg lead followed by 33 bbls 15.8 ppg tail. Plug was bump at calculated strokes. No CBL exists for the production casing section. TOC for production casing calculated at 6024’ MD/-4044’ TVDss, top of Kuparuk interval at -6380’ TVDss. L-122L1:The 5-1/2” x 3-1/2” production casing/liner was run and cemented on 5-28-2003. Cementing operations consisted of pumping 64 bbls of 12.5 ppg lead followed by 33 bbls 15.8 ppg tail. Plug was bumped at calculated strokes. No CBL exists for the production casing section. TOC for production casing calculated at 6024’ MD/-4044’ TVDss, top of Kuparuk interval at -6380’ TVDss. TOC for production casing calculated at 4077’ MD/- TOC for production casing calculated at 4077’ MD/ TOC for production casing calculated at 6024’ MD/ TOC for production casing calculated at 9021’ MD/ L-111: TD: 7605' MD; 7-inch shoe at 7589' MD Shoe cemented with 42 bbls of Gas Blok 15.8 ppg est. TOC at 6430' MD (-5973' TVDSS); Stage tool at 5243' MD, cemented with 57 bbls of GasBlok 15.8 ppg est. TOC at 3605' MD (-3228' TVDSS) SFD 4/26/2023 TOC for production casing calculated at 9021’ MD/ No CBL e Top Kuparuk C at 7,009' MD (-6,536' TVDSS) SFD 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 8 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 L-112A. 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 ~14ppg. Faults 1-9 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. L-112A crossed fault #1 at 10185’md and crossed fault #9 at 11540’md. The wellbore trajectory is a long lateral. Maximum stress direction is estimated to be ~30 deg W of N. The fracs should not reach any of the mapped faults. The first frac is 1680’ from fault #1, 500’ from fault #2, 550’ from fault #3, 1050’ from fault #4 and 200’ from fault #9. The second frac is 1360’ from fault #1, 380’ from fault #2, 810’ from fault #3, 830’ from fault #4 and 150’ from fault #9. The third frac is 900’ from fault #1, 320’ from fault #2, 1280’ from fault #3, 540’ from fault #4 and 590’ from fault #9. The maximum anticipated fracture half-length of 200’ is well short of theses distances. Half-length is modeled using hydraulic fracture modelling software and is corroborated by what we have seen in other frac treatments. The frac stages should have sufficient offset to faults #1, #2, #3, #4 and #9 and should not intersect. 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 Top Bottom 1 0-30' DTW HRZ Kingak 2 0-100' DTS HRZ Kingak 3 0-100' DTW Colville Ivishak 4 0-235' DTW Colville Basement 5 0-230' DTS Sagavanirktok Basement 6 80-230' DTW Sagavanirktok Basement 7 90-180' DTSW Sagavanirktok Basement 8 0-50' DTS HRZ Miluveach 9 10' DTE HRZ Miluveach 200’ from fault #9. T 8 mapped faults that transect the Kuparuk interval a f ~14ppg. 320’ from fault #2, 9 150’ from fault #9. SECTION 12: PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283, a, 12Fracture Stimulation Pump SchedulePlease see Frac program included with this sundry application Table 5 – Anticipated Pressures MIT-T 3752 psi MIT-IA 4440 psi Maximum Anticipated Treating Pressure:6570 psi @ 20 BPM IA Pop-off Set Pressure (~95% of MIT-IA):4200 psi IA Minimum Hold Pressure (POP-off – 300 psi):3900 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T):7650 psi w/ 3900 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:6885 - 7260 Global Kickout (95% of MATP):7260 psi N2 POP-off set pressure (MATP + 1000 psi):8650 psi Treating Line Test Pressure (MATP + 1000 psi):8700 psi OA Pressure:Monitor Max Anticipated Proppant Loading:8 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 lateral of the well is drilled perpendicular to the maximum horizontal stress meaning the induced fracture will also be perpendicular to the wellbore. The toe frac will be nearly parallel to the maximum horizontal stress so the fracture there should parallel the wellbore. With a MITT of 3752 psi, Max frac string differential is 3411 psi for 110% testing requirement. This equates to a MATP of 7311psi for a 3900 psi IA hold pressure. CDW 05/02/2023 ? Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 11,747 -6580 -6655 ~200’ 2 11,405 -6585 -6665 ~200’ 3 10,919 -6590 -6670 ~200’ 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. Frac Locations indicated by Red Lines, the stars were planned but the liner did not get to bottom Frac Modelling: Maximum Anticipated Treating Pressure: ~6570 psi Surface pressure is calculated based on a closure pressure of ~0.62 psi/ ft or ~4100 psi. Closure pressure plus anticipated net pressure to be built (500 psi) and friction pressure minus hydrostatic results in a surface pressure of ~3100 psi at the time of flush. 4100 psi (closure)+ 820 psi (net)+ 6250 psi (friction)- 4600 psi (hydrostatic)= 6570 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 ~69 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 ~275 ft. modeled frac is anticipated to reach a half-length of ~275 ft. closure pressure of ~0.62 psi/ ft or ~4100 psi. = 6570 psi (max surface press) Average confining layer stress is anticipated to be ~0.7 psi/ ft limiting fracture height to ~69 ft TVD. Pre-Job Anticipated Chemicals to be pumped: 182,910 gal 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 10% water cut and 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, LLCHilcorp North Slope, LLCChanges to Approved Workover Sundry ProcedureDate: April 24, 2023Subject: Changes to Approved Sundry Procedure for Well L-112ASundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the workover (WO) “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 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 May 4, 2023 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 4/26/2023 (a)(2) Plat Provided with application. SFD 4/26/2023 (a)(2)(A) Well location Well lies in Sections 34, 33, and 32 of T12N, R11E, UM. SFD 4/26/2023 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application (accessed online April 26, 2023), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of PBU L-112A. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of PBU L-112A. SFD 4/26/2023 (a)(2)(C) Identify all well types within ½ mile List of all wells within ½-mile radius of the PBU L-112A well path is provided with application. SFD 4/26/2023 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the Western Operating Area of the PBU per the Findings and Conclusion of Aquifer Exemption Order 1. For an outline of the EPA’s current Aquifer Exemption Area for the Prudhoe Bay Unit, see the EPA’s “Alaska Oil & Gas Aquifer Exemptions Interactive Map” available online under the “Permits” section of EPA Region 10’s web page at https://www.epa.gov/uic/underground-injection-control-region-10-ak-id-or-and-wa. SFD 4/26/2023 (a)(4) Baseline water sampling plan None required: No freshwater aquifers are present. SFD 4/26/2023 (a)(5) Casing and cementing information Provided with application. schematic attached. CDW 05/02/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 May 4, 2023 (a)(6) Casing and cementing operation assessment 9-5/8” surface casing cemented to surface with 75 bbl returns. 7” casing cemented without issue and full returns. CTD L-112A lateral. Liner cement job didn’t establish returns. Packer squeeze performed. Liner backside cement squeeze performed. CBL showed cement tops and pressure tests were passes. No new issues with cement for the upcoming stimulation. CDW 05/02/2023 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 4/26/2023 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface casing in parent wellbore PBU L-112 was set at 3,109’ MD (-2.587’ TVDSS) and cemented with 73 barrels of cement returns at surface. For PBU L-112, 8-3/4” hole was drilled from the base of to total depth of 9,640’ MD (-6,876’ TVDSS). The 7” casing shoe is set at 9,612’ MD (-3,850’ TVDSS). Top of tail cement is estimated at about 8,692’ MD (-6,001’ TVDSS), which is above the HRZ, so the Kuparuk sands are likely cemented in L-112. Top of lead cement in PBU L-112 is calculated at about 4,661’ MD (-3,447’ TVDSS), so the Schrader Bluff is likely cemented in PBU L-112. PBU L-112A kicked off through a window milled at 9,390’ MD (--6,641’ TVDSS) within the Kuparuk C sand and drilled to total depth. In L-112A production casing was run to 11,753’ MD (-6,600’ TVDSS) and cemented. Volumetric calculations and the operator’s CMIT testing indicate cement is above the window at 9,390’ SFD 4/26/2023 Drlg Eng 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 May 4, 2023 MD (-6,641’ TVDSS), so hydrocarbon zones are cement-isolated. (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 4440 psi MITIA, 3752 psi MITT completed. CDW 05/02/2023 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi treesaver planned. Max anticipated frac pressure of 6570 psi. Pump knock out 6885 to 7260 psi. GORV 7260 psi., lines test 8700 psi are all wrong. CDW 05/02/2023 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: HRZ, Kalubik, and Kuparuk D shale, mudstone, and siltstone with an aggregate thickness of about 445’ true vertical thickness (TVT). Fracture gradient is expected to range from about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). Fracturing Zone: Kuparuk C sand interval. Fracture gradient expected to range from about 0.62 psi/ft (11.9 ppg EMW). Lower confining zones: Kuparuk B, which is about 150’ thick in this area, consists of interbedded mudstone/shale with thin lenses of sandstone. Fracture gradient is expected to range from about 0.65 psi/ft (12.5 ppg EMW). Underlying Kuparuk A interval consisting of sandstone and siltstone is expected to be about 70’ thick, with a fracture gradient expected to range from about 0.65 psi/ft (12.5 ppg EMW). The Miluveach and underlying Kingak consist of shale, mudstone, and siltstone not penetrated by L-112A, but the aggregate thickness in nearby well NW Eileen State 1 is about 1,860’ TVT. Fracture gradient is expected to range from about 0.65 to 0.70 psi/ft (12.5 to 13.5 ppg EMW). SFD 4/26/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 May 4, 2023 (a)(10) Location, orientation, report on mechanical condition of each well Over 100 wells on L-pad. Hilcorp provided a table and plot. Hilcorp has provided isolation information on the 5 wells and laterals in the frac zone. CDW 05/02/2023 (a)(11) Sufficient information to determine wells will not interfere with containment within ½ mile Yes. There are seven wells and wellbores within ½ mile of PBU L-112A: L-111, L-112, L-114, L-114A, L-114B, L-122, and L-122L1. Although there are no cement evaluation logs available for these wells, volumetric calculations by the operator and confirmed by AOGCC indicate that it is highly likely that the Kuparuk sands are cement-isolated in each well. SFD 4/28/2023 Drlg Eng (a)(11) Faults and fractures, Location, orientation (a)(11) Faults and fractures, Sufficient information to determine no interference with containment within ½ mile None. The operator has identified 9 faults on seismic data within a ½-mile radius of PBU L-112A. The three nearest faults, numbered 3, 2, and 9, have azimuths of 350°, 285°, and 0°, respectively. The maximum regional stress direction is estimated to have an azimuth of about 330° in this area. The modeled half-length of the induced fractures is about 275’, and the closest approach of these planned induced fractures to the mapped faults is about 75’ (distance from the NW tip of Stage 2 fracture to the northern tip of Fault 9). This particular fault displays a vertical displacement of about 10 feet, and it dies out within the overlying, confining HRZ shale. It is unlikely that Fault 9 or any of the other mapped faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. SFD 4/27/2023 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/02/2023 (a)(12)(A) Estimated volume Provided with application. 5355 bbl total dirty vol. 500K lb total proppant CDW 05/02/2023 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 May 4, 2023 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/02/2023 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided with no proprietary chemicals listed as planned. CDW 05/02/2023 (a)(12)(D) Inert substances , weight or volume of each Provided with application. CDW 05/02/2023 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 6570 psi. Max. 7311 psi allowable treating pressure based on MITT of 3752 psi and anticipated IA hold pressure of 3900 psi. Hilcorp table with anticipated pop offs and line test pressures are incorrect. With 3900 psi back pressure on IA (IA popoff set 4200 psi), max tubing differential should be 2670 psi. CDW 05/02/2023 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures are 200’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be less than 100’ (shallowest top TVDSS of about -6,580’ and deepest base TVDSS of about -6,670’, so induced fractures will likely penetrate into, but not through, the overlying confining interval that displays an aggregate vertical thickness of about 445’ in this area. SFD 4/27/2023 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified but Hilcorp has many disposal options for L-Pad waste. CDW 05/02/2023 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3900 psi back pressure, plan to test to 4440 psi, popoff set as 4200 psi CDW 05/02/2023 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing TOC from CBL 27MAR23 in IA as 8681 ft. TOC on 2-3/8” bonsai completion per CBL 27-JAN-23 is at the tubing tail 9,176’ MD. Should provide hydraulic isolation for fracturing. MGR 5/2/23 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 May 4, 2023 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3752 psi completed. Max pressure differential is estimated as 2670 psi (6570 with 3900 psi backpressure) so test of 3752 psi satisfies 110% CDW 05/02/2023 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device Hilcorp is basing pressure relief pressures on incorrect MATP. First pump knock out should be at 6580 psi (for Hilcorp identified 90-95% of MATP). IA PRV set as 4200 psi. CDW 05/02/2023 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/02/2023 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 4200 psi. Surface annulus open. Frac pressures continuously monitored. CDW 05/02/2023 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 05/02/2023 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above), (k) Confidential information Clearly marked and specific facts supporting nondisclosure Development well – not confidential (l) Variances requested Modifications of deadlines, requests for variances or waivers 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU L-112A (PTD No. 222-138; Sundry No. 323-255) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 May 4, 2023 No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 26, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC L-112A PRUDHOE BAY UN BORE L-112A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/26/2023 L-112A 50-029-23129-01-00 222-138-0 N SPT 6468 2221380 4500 1989 2490 2508 2486 49 366 336 322 OTHER P Bob Noble 3/29/2023 AOGCC MIT-IA to 4500 psi as per 10-403 323-116 for cement repair tubing x IA. Tubing had tubing tail plug installed. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN BORE L- 112A Inspection Date: Tubing OA Packer Depth 665 4618 4492 4440IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN230330071232 BBL Pumped:5.8 BBL Returned:4.9 Wednesday, April 26, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 4500 psi as per 10-403 323-116 cement repair tubing x IA. James B. Regg Digitally signed by James B. Regg Date: 2023.04.26 14:05:34 -08'00' Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 04/14/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230414 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPF-81 50029229590000 200066 3/29/2023 READ CaliperSurvey MPI-04A 50029220680100 201092 4/2/2023 READ CaliperSurvey MPI-27 50029236920000 221013 4/2/2023 READ CaliperSurvey MPI-27 50029236920000 221013 3/20/2023 READ CaliperSurvey MPL-12 50029223340000 193011 4/2/2023 READ CaliperSurvey MPU I-27 50029236920000 221013 3/23/2023 READ LeakPointSurvey PBU 09-23A 50029210660100 198044 3/28/2023 READ MultipleArrayProductionProfile PBU L-112A 50029231290100 222138 3/27/2023 READ MemoryRadialCementBondLog END 1-11 50029221070000 190157 3/19/2023 AK E-LINE Perf END 1-29 50029216690000 186181 2/9/2023 AK E-LINE Perf NCI A-08 50883200280000 169063 3/20/2023 AK E-LINE Perf BCU 19RD 50133205790100 219188 4/4/2023 AK E-LINE PPROF SRU 224-10 50133101380100 222124 3/31/2023 AK E-LINE CIBP_GPT_Perf SRU 224-10 50133101380100 222124 4/3/2023 AK E-LINE GPT_Perf SRU 231-33 50133101630100 223008 3/29/2023 AK E-LINE GPT Please include current contact information if different from above. T37595 T37596 T37599 T37599 T37597 T37599 T37598 T37601 T37603 T37600 T37602 T37594 T37604 T37604 T37605 PBU L-112A 50029231290100 222138 3/27/2023 READ MemoryRadialCementBondLog Kayla Junke Digitally signed by Kayla Junke Date: 2023.04.17 14:10:44 -08'00' 323-009, 323-065 & 323-116 L-80 / 13Cr80 8 By James Brooks at 9:39 am, Apr 06, 2023 Completed 1/17/2023 JSB RBDMS JSB 040623 GMGR02AUG2023SFD 4/26/2023 DSR-4/14/23 4.5.2023 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.04.05 14:36:58 -08'00' Monty M Myers Activity Date Ops Summary 1/5/2023 Rig accepted at 08:00. RU checklists. Safe in Rig. Open well up to gauge. 0 psi. Oil change on Koomey oil. Perform LTT on swab to 3500#. NU MPD line. Test gas alarms. All pass. Nipple up BOPE. Change oil in Koomey unit. Re-plumb cement hardline. Verify test joint connections. Grease choke and stack valves. M/U nozzle, M/U injector to well. Flush and fluid pack surface lines. Test BOPs as per PTD and Hilcorp guidelines. Test witness waived by AOGCC Inspector Kam StJohn. All tests 250/3500 psi. Test 1: IRV, Stripper, C7, C9, C10, C11 - Pass. Test 2: Blind/Shears, R2, BL2, C15 - Pass. Slide injector back, insert test jt. Test 3: Annular (2"), TIW1, B1, B4 - Pass. Test 4: Upper 2" Pipe/Slip, TIW2, B2, B3 - F/P on B2 grease then pass. Test 5: Lower 2" Pipe / Slip, C5, C6, C8, TV2 - Pass. Test 6: Choke A, Choke C - Pass. Accumulator Drawdown. Test 7: C1, C4, TV1 - F/P on TV1, grease then pass. Test 8: 2-3/8" Pipe/Slip, C2, C3 - Pass. BOPE test complete 05:30. 1/6/2023 Remove test risers, Install drilling risers and QTS. Install weight bars in lubricators. Pressure test ODS PDL / MPD line / Drilling Risers to 3500#. Pressure test DS PDL to 3500#. BHI install floats in UQC. Pressure test body to 3500#. Test Floats to 4500#. Good test. Stab injector on. Load coil with 1%KCL. Spot Methanol up to T1/T2. PJSM for bullhead kill. Bullhead. 10 bbls Neet Methanol Catch fluid at about ~7 bbls away. 150 bbls 1% SL KCL w/ 0.6 Safelube. Circulate to tiger tank. Bring inside. Losing 30 bph. PJSM, Establish hole fill. Make up BHA#1 MWD w/ nozzle. RIH with Nozzle BHA #1. Rate: 0.60 bpm in, 0.44 bpm out. Circ pressure: 265 psi. Mud Weight: 8.36 ppg in, 8.38 ppg out. Shut choke. Run to bottom. Log down for tie-in from 9070' to 9278 MD (formation) with -8' correction. Continue logging down to tag. Wt ck at 9440' is 38k clean. Tag at 9446' 4k DWOB. Pick up to 9411' and flag pipe. P/U above perfs and break circulation. Pump 20 bbls hi- vis, leave across and above perfs. Pump 1 x B/U to tiger tank 1.5 / 1.4 bpm. Bring returns to pits, 10 min flow check on bottom is good, no flow. POOH. Tag stripper, 10 min flow check is good no flow. Lift injector and slide back, pull BHA #1 remove nozzle. M/U mem CBL tools on CoilTrak. M/U injector. RIH BHA #2. Tie-in depth from 9200 correct -11'. RIH to flag 9437' and line up to pump across top. Log up from 9437' to 9000' at 30 ft/min. RIH to 9437' and log repeat pass up 30 ft/min. Stop at 9000' line up to pump down CT. POOH. Tag stripper, 10 min flow check is good, no flow. Lift injector off and slide back. Pull BHA #2 out, L/D mem CBL tools and download data. 1/7/2023 Stand-by for download of data. Swap out DGS blind for DGS HOT. Make up and scribe NS 3-1/2" x 7" HEW whipstock. Make up injector. Test QTS. RIH with Whipstock BHA #3. Rate: 0.50 bpm in, 0.57 bpm out. Circ pressure: 260 psi. Mud Weight: 8.38 ppg in, 8.23 ppg out. Lose communication with tools. Troubleshoot surface. Surface good. Pooh. Pooh to troubleshoot comms. Rate: 1.55 bpm in, 0.93 bpm out. Circ pressure: 1260 psi. Mud Weight: 8.40 ppg in, 8.36 ppg out. Come off line. Flow check. Well still losing. Troubleshoot communication issue with tools. Anchor pulled. Pump back till e-line stopped. Cut 100' of pipe. MU coil connector. Pull test to 50K, Test to 4000#. Install stinger and nozzle. Pump slack forward for UQC. Movement heard immediately. MU UQC w/ floats and test to 3500#. Pump forward at 3.5 bpm for 2 coil volumes. Fill well. Open swab. Flow check. M/U BHA #3, whipstock + setting tools. RIH BHA #3, pump through open EDC. Set pump and slackoff trips tight for RIH with whipstock. Tie-in depth from 9200' correct -10.5'. Drift down to 9400', clear. Pick up to 9200' log CCL to 9400'. Our CCL matches well plan CCL. RIH to 9394.72' leaves top WS at 9386' at 10L orientation. Get up wt back. Close EDC. Pressure up and shear out setting tool 2700 psi. Set down 3.65k DWOB, no movement, good set. POOH pump 1.8 / 1.25 bpm. At surface, 10 min flow check is good, no flow. Lift injector off and skid back. L/D BHA #4, whipstock and setting tools. M/U BHA #5, window mill + 2 jts CSH + CoilTrak. Mill 2.81/2.80 Go/NoGo Reamer 2.80/2.79 Go/NoGo. RIH BHA #5, window mill. Run past sliding sleeve slowly, nothing seen. Log tie-in from 9250' correct -12'. Close EDC, ease down and dry tag pinch point at 9391.1'. Go to milling rate 1.85 / 1.49 bpm. Mill window from 9390.5' @ 10L. 2750 psi Free Spin. 8.39 / 8.39 ppg In/Out. ECD = 9.06 ppg. 1/8/2023 Milling window to 9393.52'. Free spin: 2750 psi, 1.85 bpm. Rate: 1.80 bpm in, 1.58 bpm out. Circ pressure: 2700 psi. Mud weight: 8.38 ppg in, 8.39 ppg out, Window ECD: 9.20 ppg. WOB increasing. Forward progress in question. Pick off window clean. Milling window 9393.52' to 9394.24'. Free spin: 3330 psi, 1.82 bpm. Rate: 1.82 bpm in, 1.57 bpm out. Circ pressure: 3330 - 3700 psi. Mud weight: 8.40 ppg in, 8.40 ppg out, Window ECD: 9.27 ppg. WOB climbing up to 4.1K PU to top of window. 1 fpm up / 1 fpm down. Milling window 9394.24' to 9394.4'. Free spin: 2880 psi, 1.85 bpm. Rate: 1.85 bpm in, 1.58 bpm out. Circ pressure: 2880 - psi. Mud weight: 8.38 ppg in, 8.39 ppg out, Window ECD: 9.29 ppg. Stalled and pickup. Establish parameters. Casing exit at 9394.4' MD. Continue milling at 1 fph to get reamer out. Mill rathole to 9404' MD with 2.4K WOB at 14 fph. Milled last 5' with HiVis pill at bit. Perform reaming passes while pumping pill up for sample. Rathole sample showed 95% fine grained KC3C. Swap from 8.7 ppg Powerpro. Completed reaming passes at 15 L and R of as milled. Clean passes. Dry drifted window. Bobble at 9400' MD. Rih to 9405' Come online. Backream 1 fpm from TD through window. Come offline. Dry drift to TD without issue. Pull above window. Open EDC and perform 10 min No Flow. Pooh. Rate: 2.0 bpm in, 1.18 bpm out. Circ pressure: 2943 psi. Mud weight: 8.79 ppg in, 8.81 ppg out. Flow check. Well minimal losses. Lay down window milling BHA #5. Mill and reamer same gauge as when they went in. M/U nozzle, M/U injector. Jet stack. Change out QTS valve bank. M/U BHA #6, build BHA. RIH, BHA #6. Pump 1.6 bpm through open EDC. Tie-in depth from 9200' correct -8'. Stop at 9350 close EDC. Pass window 10L, 0 pump, 25 ft/min nothing seen. Tag 9406' get up wt + 2 ft start pumps 1.8 bpm. Drill 9406' to 9500'. 1.83 / 1.5 bpm @ 3600 psi free spin. 8.76 / 8.80 ppg In / Out. Window ECD = 10.53 ppg on open choke. Drill 9500' to 9550'. 1.83 / 1.71 bpm. 8.79 / 8.80 ppg In / Out. Window ECD = 10.60 ppg open choke. 9500' 5 bbls lo / hi vis, start adding black product to mud. Pull 100' wiper trip from 9550' up wt 38k clean up/down. Drill from 9550'. 1.83 / 1.75 bpm. 8.80 / 8.85 ppg In / Out. Window ECD = 10.73 ppg open choke. 9605' pump 5 bbls lo / hi vis. 50-029-23129-01-00API #: Well Name: Field: County/State: PBW L-112A Prudhoe Bay West Hilcorp Energy Company Composite Report , Alaska 1/8/2023Spud Date: Milling window 9393.52' to 9394.24'. Casing exit at 9394.4' MD. Milling window to 9393.52'. F Mill window from 9390.5' 1/9/2023 Continue drilling build section from 9550' to 9625'. 1.83 / 1.75 bpm. 8.80 / 8.85 ppg In / Out. Pump sweeps, Pooh. Perform 100' jog prior to pulling through window. Clean pass. Shut choke. Trap 10.8 ppg ECD. Open EDC. Pooh. - Rate: 2.08 bpm in, 1.53 bpm out. Circ pressure: 3731 psi. Mud weight: 8.86 ppg in, 8.88 ppg out, Window ECD: 10.84 ppg IA pressure: 1100 psi. Tag up and space out. Trap 630 psi. Perform pressure un-deploy sequence for BHA#6. Swap motor out, Pickup agitator. Bit graded 0-0-pn-n-i-bu-bha. Make up BHA#7 w/ NOV agitator, 0.8 AKO motor, Rerun HCC bit. Perform pressure deploy sequence. RIH with 3.25 drilling BHA #7. Shallow tested agitator at 300' Good test. Rate: 1.49 bpm in, 1.61 bpm out. Circ pressure: 2697 psi. Mud Weight: 8.85 ppg in, 8.87 ppg out. Log down for tie-in from 9190' MD to 9246.43' MD (formation) with -11 correction. Close EDC. PUW 36K / RIW 17K. Drill 3.25 lateral from 9625 MD to 9700' MD. Free spin: 3790 psi, 1.82 bpm. Rate: 1.82 bpm in, 1.67 bpm out. Circ pressure: 3790 - 3985 psi. Mud weight: 8.84 ppg in, 8.87 ppg out, Window ECD: 10.8 ppg. ROP: 20-40 fph, WOB: 2.7 KLBS. Drill 3.25 lateral from 9700' MD to 9775' MD. Free spin: 4395 psi, 1.82 bpm. Rate: 1.82 bpm in, 1.67 bpm out. Circ pressure: 4395 - 4603 psi. Mud weight: 8.83 ppg in, 8.86 ppg out, Window ECD: 11.06 ppg. ROP: 20-50 fph, WOB: 1.7 - 3.0 KLBS. Perform 150' wiper trip. Pump 5 / 5 Lo vis HiVis. Drill 3.25 lateral from 9775' MD to 9925'. Free spin: 4678 psi, 1.82 bpm. Rate: 1.82 bpm in, 1.63 bpm out. Circ pressure: 4678 - 4603 psi. Mud weight: 8.84 ppg in, 8.88 ppg out, Window ECD: 11.3 ppg. ROP: 20-50 fph, WOB: 1.7 - 3.0 KLBS. 150' wiper trip from 9925', clean up and down. Drill 3.25" lateral from 9925' MD to 10075'. Free spin: 4600 psi, 1.8 bpm.1.80 bpm in, 1.74 bpm out. Circ pressure: 4600-4750 psi. Mud weight: 8.84 ppg in, 8.88 ppg out, Window ECD: 11.28 ppg. 9950', 10060': 5 bbls lo/hi vis. ROP: 50 fph, DWOB 1-2K. Wiper trip from 10075' to window. Clean pass to window, 100' jog then pull through 10L, 0.5 bpm. Jog above window full rate then open EDC. Pump 5 bbls lo/hi vis. Tie-in depth correct +4.5'. RIH and jet tray w/ open EDC. Pull back and close EDC, RIH to bottom. Drill 3.25 lateral from 10075' MD. Free spin: 4600 psi, 1.79 bpm. Rate: 1.79 bpm in, 1.79 bpm out. Circ pressure: 4580 - 4800 psi. Mud weight: 8.86 ppg in, 8.86 ppg out, Window ECD: 11.31 ppg. ROP: 50 fph, DWOB: 2-3 KLBS. 10185' 5 bbls lo/hi vis. 1/10/2023 Drill 3.25 lateral from 10185' MD - 10241' MD. - Free spin: 4600 psi, 1.79 bpm. - Rate: 1.79 bpm in, 1.79 bpm out. Circ pressure: 4580 - 4800 psi. Mud weight: 8.86 ppg in, 8.86 ppg out, Window ECD: 11.31 ppg. ROP: 50 fph, DWOB: 2-3 KLBS. Perform 150' BHA wiper. Drill 3.25 lateral from 10241' MD to 10377' MD. Free spin: 4656 psi, 1.82 bpm. Rate: 1.82 bpm in, 1.82 bpm out. Circ pressure: 4656 - 4998 psi. Mud weight: 8.87 ppg in, 8.90 ppg out, Window ECD: 11.41 ppg. ROP: 50 fph, DWOB: 2-3 KLBS. 150 BHA wiper. Drill 3.25 lateral from 10377' MD to 10525' MD. Free spin: 4725 psi, 1.82 bpm. Rate: 1.82 bpm in, 1.82 bpm out. Circ pressure: 4725 - 4998 psi. Mud weight: 8.89 ppg in, 8.92 ppg out, Window ECD: 11.44 ppg. ROP: 100-110 fph, DWOB: 2-3 KLBS. Long wiper to window. Rate: 1.79 bpm in, 1.75 bpm out. Circ pressure: 4760 psi. Mud weight: 8.91 ppg in, 8.96 ppg out, Window ECD: 11.46 ppg. Perform 100' jog below window. Pull through at minimum rate. Perform 100' jog in 7". Trap 11.4# ECD. Open EDC. Jet tray. Chase up to tubing tail. Log tie in with +4.5' correction. Close EDC. Rih thru window without issue. Bring pump up to min rate. Drill 3.25 lateral from 10550' MD - 10732' MD. Free spin: 4650 psi, 1.81 bpm. Rate: 1.81 bpm in, 1.80 bpm out. Circ pressure: 4650 - 4789 psi. Mud weight: 8.93 ppg in, 8.94 ppg out, Window ECD: 11.44 ppg. ROP: 80-100 fph, DWOB: 1.7 - 2.7 KLBS. 10810' pump 5 bbls lo- vis. 150' wiper from 10850' clean up and down. Drill 3.25" from 10850' MD - 11000' MD. Free spin: 4650 psi, 1.79 bpm. Rate: 1.79 bpm in, 1.79 bpm out. Circ pressure: 4650 - 4800 psi. Mud weight: 8.94 ppg in, 8.97 ppg out, Window ECD: 11.52 ppg.10900' pump 5 lo-vis. ROP: 80-100 fph, DWOB: 1 KLBS. Wiper trip from 11000' to window. Start new mud down CT. Clean pass to window. 100' jog below window then pull through 10L, 0.5 bpm clean. Jog at full rate above window then open EDC. Jet whipstock tray, chase new mud to surface. Tie-in depth correct +5.5'. Close EDC, RIH to bottom. Drill 3.25" hole from 11000' MD - 11150' MD. Free spin: 4100 psi, 1.79 bpm. Rate: 1.81 bpm in, 1.81 bpm out. Circ pressure: 4100-4250 psi. Mud weight: 8.74 ppg in, 8.79 ppg out, Window ECD: 11.00 ppg. 150' wiper trip from 11150' clean up and down. Drill 3.25" hole. Free spin: 4200 psi, 1.83 bpm. Rate: 1.84 bpm in, 1.84 bpm out. Circ pressure: 4100-4320 psi. Mud weight: 8.78 ppg in, 8.79 ppg out, Window ECD: 10.97 ppg. 1/11/2023 Drill 3.25" hole from 11150' MD - 11303' MD. Free spin: 4263 psi, 1.85 bpm. Rate: 1.85 bpm in, 1.84 bpm out. Circ pressure: 4263-4362 psi. Mud weight: 8.78 ppg in, 8.79 ppg out, Window ECD: 11.01 ppg. ROP: 50 fph, WOB: 0.5K - 2.0 KLBS. 150' BHA Wiper. Drill 3.25" hole from 11303' MD to 11450' MD. Free spin: 4263 psi, 1.85 bpm. Rate: 1.85 bpm in, 1.84 bpm out. Circ pressure: 4263-4555 psi. Mud weight: 8.80 ppg in, 8.82 ppg out, Window ECD: 11.09 ppg. ROP: 25-60 fph, WOB: 0.5K - 2.0 KLBS. Pump 5 bbls LoVis / 5 bbls HiVis. 150' BHA Wiper. Long wiper trip. Rate: 1.85 bpm in, 1.84 bpm out. Circ pressure: 4503 psi. Mud weight: 8.80 ppg in, 8.80 ppg out, Window ECD: 11.06 ppg. Perform jog at window. Open EDC. Jet tray with sweeps and chase up to tubing tail at 50% pulling speed. Log down for tie-in with +6.5' correction. Rih. Drill 3.25" hole from 11450' MD to 11528' MD. Free spin: 4269 psi, 1.83 bpm. Rate: 1.83 bpm in, 1.84 bpm out. Circ pressure: 4269-4555 psi. Mud weight: 8.79 ppg in, 8.80 ppg out, Window ECD: 11.09 ppg. ROP: 25-60 fph, WOB: 0.5K - 2.0 KLBS. Drill 3.25" hole from 11528' MD to 11650' MD. Free spin: 4269 psi, 1.83 bpm. Rate: 1.82 bpm in, 1.84 bpm out. Circ pressure: 4269-4555 psi. Mud weight: 8.79 ppg in, 8.81 ppg out, Window ECD: 11.15 ppg. ROP: 25-40 fph, WOB: 0.5K - 2.0 KLBS. Drill 3.25" hole from 11650' MD. Free spin: 4269 psi, 1.83 bpm. Rate: 1.81 bpm in, 1.76 bpm out. Circ pressure: 4269-4560 psi. Mud weight: 8.80 ppg in, 8.82 ppg out, Window ECD: 11.18 ppg. ROP: 25-40 fph, WOB: 0.5K - 2.0 KLBS. POOH from 11716' MD to inspect BHA. Rate: 1.81 bpm in, 1.69 bpm out. Circ pressure: 4269-4560 psi. Mud weight: 8.70 ppg in, 8.81 ppg out, Window ECD: 11.13 ppg. 1/12/2023 Continue out of hole from 10380' MD to inspect bit / agitator. Rate: 1.81 bpm in, 1.69 bpm out. Circ pressure: 4269-4560 psi. Mud weight: 8.70 ppg in, 8.81 ppg out, Window ECD: 11.13 ppg. Perform jog at window, Open EDC, Jet tray with 5 bbls LoVis. Chase up to tubing tail at 50%. Pooh. Pump sweep at 2500' MD. Once out EDC at at surface. Jog in hole to flush cutting stalling in stack. Inspect pipe while pooh. Looked good. Pressure un-deploy BHA#7 lateral. Bit graded 2-2-er-n-x-i-bu- pr. Maintain 11.0 ppg ECD with MPD . Perform weekly BOPE function test. Inspect pipe above coil connector. 0.156- 0.160 wall Will inspect again prior to liner. Replace pack-offs, Test to 250 psi / 3500 psi Good test. Make up 2-3/8" ERT-Max, Motor 0.7 AKO, 2.70" x 3.25" HCC bit. Perform pressure deploy sequence while maintaining 11.0 ppg ECD at window. Shallow test agitator. Good reaction from 1.5 bpm to 1.8 bpm. Rih w/ BHA#8 Lateral BHA. Rate: 1.52 bpm in, 1.87 bpm out. Circ pressure: 3254 psi. Mud weight: 8.79 ppg in, 8.82 ppg out, Window ECD: 11.05 ppg. Log down for tie-in from 9200 to 9240.71 MD (formation) with -4.5 correction. Close EDC, Run thru window without issue. Run to bottom. Drill 3.25 lateral from 11713' to 11790'. Free spin: 4902 psi, 1.82 bpm. Rate: 1.82 bpm in, 1.81 bpm out. Circ pressure: 4979 psi. Mud weight: 8.78 ppg in, 8.80 ppg out, ECD: 11.2 ppg. ROP: 10 -50 fph, WOB: .2 - 1.3 KLBS. Drill 3.25 lateral from 11790' to 11910'. Free spin: 4902 psi, 1.82 bpm. Rate: 1.87 bpm in, 1.79 bpm out. Circ pressure: 4843 - 4979 psi. Mud weight: 8.79 ppg in, 8.83 ppg out, ECD: 11.14 ppg. ROP: 10 -50 fph, WOB: .2 - 1.3 KLBS. Drill 3.25 lateral from 11910' to 11946'. Free spin: 4902 psi, 1.82 bpm. Rate: 1.86 bpm in, 1.78 bpm out. Circ pressure: 4467 - 4589 psi. Mud weight: 8.81 ppg in, 8.84 ppg out, ECD: 11.28 ppg. ROP: 10 - 15 fph, WOB: .7 - 1.3 KLBS. Pump 50 bbl new mud. 1/13/2023 Drill 3.25 lateral from 11946' to 12089' . Free spin: 4468 psi, 1.82 bpm (639# diff). Rate: 1.86 bpm in, 1.80 bpm out. Circ pressure: 4468 - 4600 psi. Mud weight: 8.81 ppg in, 8.82 ppg out, ECD: 11.15 ppg. ROP: 10 - 15 fph, WOB: .7 - 1.0 KLBS. Turnarounds very difficult, Multiple PU's. Perform long wiper to window. Rate: 1.81 bpm in, 1.67 bpm out. Circ pressure: 4432 psi. Mud weight: 8.81 ppg in, 8.82 ppg out, ECD: 11.26 ppg. Pump multiple sweeps. Perform jog at window. Pull through without issues. Log tie in with a +22.5' correction. Run through window without issues. Start new mud with 3.5% lubes down coil. Drill 3.25 lateral from 12089' MD to 12142' MD. Free spin: 4360 psi, 1.83 bpm (817# diff). Rate: 1.86 bpm in, 1.80 bpm out. Circ pressure: 4468 - 4600 psi. Mud weight: 8.75 ppg in, 8.84 ppg out, ECD: 11.15 ppg. Get final survey and pump Lo/Hi vis sweeps around at final TD of 12142'. POOH from 12142' for wiper trip to surface. Rate: 1.79 bpm in, 1.69 bpm out. Circ pressure: 4468 - 4600 psi. Mud weight: 8.80 ppg in, 8.82 ppg out, ECD: 11.10 ppg. Jog below window and pull through window clean. Open EDC and continue OOH pumping max rate. Tag up at surface. Correct depth and RIH. Rate: 1.28 bpm in, 1.32 bpm out. Circ pressure: 2910 - 2936 psi. Mud weight: 8.79 ppg in, 8.81 ppg out, ECD: 11.20 ppg. IA = 1088 psi, OA = 261 psi. 1/14/2023 RIH. Rate: 1.26 bpm in, 1.49 bpm out. Circ pressure: 2792 psi. Mud weight: 8.79 ppg in, 8.80 ppg out, ECD: 11.21 ppg. Log tie in with -9.5' correction. Close EDC. Drift to TD at min rate. Minor bobbles at 0.3 bpm. Tag corrected TD at 12138' MD'. Pump 40 bbls Liner pill with 1.5 ppb Alpine beads. Circulate 11.0 ppg NaCl / NaBr from 9577' to surface. Paint yellow flag 9073.74' bit depth (8998.34' CEOP) . Perform 10 min flow check. Pooh for liner. Rate: 1.07 bpm in, 0.88 bpm out. Circ pressure: 1256 psi. Mud weight: 11.04 ppg in, 11.05 ppg out, ECD: 11.55 ppg. Paint white flag at 6321.17' (6245.77' CEOP). At surface, Perform 10 min flow check. Inspect coil flat spot 0.135 wall thickness. Lay down BHA. Cut 28' coil. Install new CTC. Pull test to 40K. Good test. Re-head BHI and test floats to 5k. Good test. - Inspect and service top drive. Prep floor to run liner. Run NS 2 3/8" 4.6# L-80 HYD 511 solid liner with NSAK frac sleeves per approved tally. Fill liner every 10 joints. Conduct kick while tripping drill and hold AAR. Continue running 2 3/8" 4.6# L-80 HYD 511 solid liner with NSAK frac sleeves per approved tally. Fill liner every 10 joints. M/U MWD. M/U NS Sealed GS. M/U Injector. RIH with 2 3/8" 4.6# L-80 HYD 511 solid liner with NSAK frac sleeves. Rate: 1.07 bpm in, 0.88 bpm out. Circ pressure: 1256 psi. Mud weight: 11.04 ppg in, 11.05 ppg out, ECD: 11.55 ppg. IA = 1199 psi, OA = 0 psi. Correct depth at window flag -26.5'. Circulate out 11.0 ppg KWF 1/15/2023 Ciirculate KWF out with Powerpro. Rate in: 0.70 bpm, Rate out: 0.61 bpm. MW in: 8.81 ppg, MW out: 11.05 ppg. Run liner into openhole. PUW 35K, RIW 15K. Set down at 10592' MD. Came off liner. Rih and latch back up. Started bobbling our way to bottom. Start working liner downhole. Liner down to 11071' MD. Pump 10 bbls LoVis, 30 bbls Dead Crude, 10 bbls Lovis. Pump 10 Dead crude out liner shoe Close choke. Let coil pressure bleed off. Rih to 11476' MD. Pump another 5 bbls out shoe. Rih to 11594' MD. Pump another 5 bbls out shoe. Run liner to 11735' MD. Circulate Dead crude out. Purge lubricator. Pump 10 bbls spacer, 75 bbls Dead Crude, 10 bbls spacer. Pump 35 bbls around liner. Shut choke. Continually set down same place. Pull up to 11615'. Pulled heavy. Work to get moved back down to 11733' in compression. Stack weight 10K. Bring pumps on at 1.2 bpm. Taking some time to get returns. Discuss options with town. Decision made to leave liner at current depth of 11733' uncorrected. Circulate well over to 1% KCL. Rate in: 1.16 bpm, Rate out: 1.09 bpm. MW in: 8.48 ppg, MW out: 7.89 ppg. 1% KCL returns at surface. Pump off liner and POOH for CCL logging pass. Log CCL from 7650' - 8737' to confirm TOL. OOH - Flow check well and confirm no flow. L/D liner running tool. All 0-rings missing on sealable GS. M/U and RIH with 2.50" nozzle freeze protect BHA./T LRS hot oil to 4500 psi. Freeze protect well from 2500' TVD with diesel. Leave neat methanol in top 100' of well and tree. Service all tree valves with grease crew. 1/16/2023 Jet stack with remaining methanol / freshwater. Remove injector, Pull floats out of UQC, Install big hole nozzle. Stab on and test QTS. Halliburton N2 cooled down and PT 500 psi/ 4000 psi. Pumped 30 bbls Inhibited Freshwater into reel followed by 3 bbls methanol. Bring N2 on at 1200 scf / min for 15 min. Total of 19500 scf pumped. Rig down Halliburton and let remaining N2 bleed down. Remove injector. BHI remove UQC, Cut coil connector off. Boot e-line. Dress coil for grapple. PJSM. Pull test grapple. Re-tighten. Pull coil across and secure to reel. Cut 24' tail off. Continue prepping reel for removal. Swap 2" reels. Shim hubs. Install saddle clamps. M/U inner reel iron. R/D pack off assembly and install new brass. M/U pack off assembly to injector. 1/17/2023 N/D MPD liner. N/D BOP stack. R/D cellar. Prep to pull coil across. Secure stack in cellar. RDMO 06:00. ACTIVITYDATE SUMMARY 1/18/2023 T/I/O=SI/0/0. Post CDR2. Remove 4" tapped blind on top of SV. install 4" tree cap assembly. torque to spec. Remove 4" kill line from flow cross. install chem. blind. torque to spec. PT tree 300 low 5000 high (pass). *** RDMO*** 2/1/2023 T/I/O=227/104/2 LRS 76 MIT-IA to 2500 psi Failed, LLR 0f 5 bpm @ 2100 psi Loaded IA with 170 bbls DSL Final WHP's 1128/1415/0 Pad Op notified on departure ( LRS transport) 2/3/2023 LRS unit 76 SB for weather 2/9/2023 LRS CTU #2 1.50" Blue Coil. Job Objective: Squeeze LNR Spot in equipment and start rigging up. ***Job in Progress*** 2/9/2023 Heat 2 transports of diesel for CTD to 90* *** Job continued to 02-10-2023 *** 2/10/2023 LRS CTU #2 1.50" Blue Coil. Job Objective: Squeeze LNR RIH w/ 1.85" DJN and drift cleanly to 10,875' CTM. POOH while pumping DSL down CTB. MU NSAK. Deploy 1-3/8" ball. Wait 20 mins for ball to fall past 4-1/2" x 3-1/2" XO @ 73'. RIH w/ NSAK Stinger & Shifting Tool. Park @ 10,717', pump DSL to establish baseline circ press. RIH - circ press spike to 4100 psi. POOH to inspect tools. Verified upper seals on cmt stinger damaged. Re-dress NSAK stinger assembly & RBIH to 10800'. Circulate in 5 BBL gel pill into the liner. S/D on sliding sleeve at 10,862' CTM / 10,855' MD. Shear burst disk at ~ 3100 psi. Establish circulating rates through the sleeve at 0.9 BPM / 4250 psi & 0.5 BPM / 1933 psi. Bleed WHP to 0 psi with 0.5 BPM returns (returns are independent of pump rate). ***Job in Progress*** 2/10/2023 ** Assist Coil ** Heat diesel transports to 90* per company rep. 2/10/2023 *** Job continued from 2-9-2023 *** Heat 2 DSL tankers for CTU to 90* 2/11/2023 LRS CTU #2 1.50" Blue Coil. Job Objective: Squeeze LNR Pumped 16 BBL's of 15.5 ppg class "G" cement and displace with 5 BBL gel & DSL. Squeeze all 16 BBL's behind pipe (final circ pressure 3960 psi at 0.5 BPM). Start losing returns near the end. 15bbl returned. Estimated TOC: 8904 MD. PU and close the sleeve. Pump a couple BBL's trying to get returns at surface with no luck. POOH pumping pipe displacement. MU NSAK liner top stinger assembly & RIH. Sting in. Cannot establish circulation. Sting back in. Still cannot establish circulation. Pump liner vol DSL. POOH while pumping pipe displacement. Well freeze protected with diesel. RDMO. ***Job Complete*** 2/15/2023 T/I/O= MIT-IA max applied 3500 psi. Pumped 21 bbls Diesel down the IA. IA would not pressure up above 2600 psi, as rate increased pressure dropped to 2575 psi. Established liquid leak rate to be 1.14 bpm at 2575 psi. T/I/O= 126/500/10 2/16/2023 ***WELL S/I ON ARRIVAL*** (ctd) SET 3-1/2" LTTP ON DEPLOYMENT SLEEVE AT 8,757' MD LRS ATTEMPTED MIT-T (IA instantly tracked), PERFORMED PASSING CMIT-TxIA TO 3,000 psi ***CONTINUE ON 2/17/23 WSR*** 2/16/2023 T/I/O=630/610/10 Assist S-Line (MIT-Tbg, CMIT TxIA) MIT-T Failed. IA tracked TBG. Pumped 5.8 bbls Down Tbg to reach test pressure. CMIT TxIA PASSED Losse of 85/85 psi TxIA 1st 15 min, Loss of 28/28 psi 2nd 15 min for a total loss of 113/113 psi during 30 min test. Bled back 8.5 bbls. Freeze protect FL w/ 12 bbls 60/40 FWHP=800/800/20 S-Line on location upon departure Daily Report of Well Operations PBU L-112A Estimated TOC: 8904 MD. Daily Report of Well Operations PBU L-112A 2/17/2023 ***CONTINUED FROM 2/16/23 WSR*** (CTD) PULL 3-1/2" LTTP (CAT VALVE) FROM DEPLOYMENT SLEEVE AT 8,757' MD ***WELL S/I ON DEPARTURE*** 3/11/2023 T/I/O= 1250/550/500 TFS unit 4 Assist E-Line, (LDL) Pump down IA at 2 BPM MAP of 4000 PSI during E-Line log. Pumped 713 bbls dsl followed by 24 bbls 60/40 to assist E-Line ***Job continued on 03/12/2023*** 3/11/2023 *** WELL S/I ON ARRIVAL *** ( LEAK DETECTION LOG) PT 300L/3500H PERFORM LEAK DETECTION LOG W/PRESSURE,TEMPERATURE,SPINNER TO LOG FROM SURFACE TO DEPLOYMENT SLEEVE @ 8750'. THUNDERBIRD PUMP AT ~2 BPM FOR 10 BBLS BEFORE STARTS LOGGING DOWN THE FIRST PASS LOGGING SPEED 80,120 FPM UP/DN ,WHILE THUNDERBIRD PUMPING DOWN IA TO FORMATION ~ 1 BPM LEAK ACTIVATE T/I/O=2509/2550/500 psi, PERFORM STATION AT 8750' AND CONFIRM LEAK ABOVE THE DEPLOYEMENT SLEEVE PERFORM SATATION LOG ON ALL GL FROM GL #2 TO GL #4 THE SPINNER REACTION ON ALL GL CONTINUE LOG UP W/ STATION STOPS TO FIND THE LEAK WHILE THUNDERBIRD PUMP ~1BPM ***JOB CONTINUE ON 3/12/2023*** 3/12/2023 ***JOB CONTINUED FROM 3/11/2023*** (LEAK DETECTION IN PROGRESS) CONTINUE RECORD SATATION UP TO 1880' MD AND SPINNER READS THUNDERBIRD RUN OUT OF FLUID , MAKEPHONE CALL TO BRODIE WAGES AND MAKE DECISION TO PULL OUT OF HOLE AND SEND DATA TO TOWN FOR FINAL PROCESS RIG DOWN ***WELL S/I ON DEPARTURE*** 3/12/2023 ***Job continued from 03/11/2023*** TFS unit 4 Assist E-Line (LDL) Pumped 68 bbls DSL to Assist E-Line. E-Line in control of well upon departure. FWHP= 1300/580/0 3/13/2023 Heat Diesel Transport to 90*F for CTU. 3/13/2023 LRS CTU #2 1.5" Blue Coil. Job Objective: Packer Squeeze MIRU. Drift to 11,403' CTM w/ 1.5" DJN. MU 2.23" BOT liner stinger assembly and RBIH. Sat down in GLM #4 at 4599' MD and unable to pass. POOH, add two 4' LRS stingers, and RBIH. ***Job in Progress*** 3/14/2023 Heat DSL tanker to 90* Daily Report of Well Operations PBU L-112A 3/14/2023 LRS CTU #2 1.5" Blue Coil. Job Objective: Packer Squeeze Continue RIH with BOT stinger assembly (2.79" no-go sub) and sit down again in GLM #4 at 4599' MD. POOH, size down to 2.72" no-go sub, and add a knuckle above the stingers. RBIH and able to bobble past GLM #4. Continue in hole and sting into the deployment sleeve at 8754' CTM / 8757' MD. Pressure test down the CTB to ~ 1000 psi (lost 28 psi in 10 min). Circulate hot diesel through the coil. Pump 11.2 BBL's of 15.3 ppg class "G" cement and displace with diesel. Place 9.2 BBL's in the liner/tubing/PC annulus through the tubing leak at 9071' MD. Circulate gel pill to surface, and the POOH pumping pipe displacment. RBIH with slim LRS 1.5" JSN to 10,879' CTM. Pump 25 BBL gel off bottom to clean the liner/tubing. Place 1 BBL gel pill across the liner top. POOH pumping diesel for pipe displacement. Blow the reel down with N2. RDMO and head to the LRS yard for pipe swap. ***Job Complete*** 3/24/2023 T/I/O = 501/18/29. MIT-IA to 2000 psi PASSED Pressured IA to 2000 psi w/ 2.3 bbls Diesel. IA Lost 100 psi in 1st 15 mim., and 27 psi in 2nd 15 mi, for a total loss of 127 psi in 30 minute test. Bled back ~ xx bbls FWHP T/I/O = 506/25/29 SV/WV/SSV = S, MV = O, IA/OA = OTG. Pad op notified upon LRS departure. 3/26/2023 ** Assist SL** Pump 1 bbl DSL down to assist S-Line. Continued on 03-27-2023 3/26/2023 ****WELL S/I ON ARRIVAL**** (new well post) DRIFT W/ 20' x 2" DUMMY GUNS, 2.75" CENT & 2.60" LIB TO DEPLOYENT SLEEVE AT 8,757' MD (no impression) BEGIN MEMORY CBL FROM 8,729' SLM TO SURFACE. ***CONTINUE ON 3/27/23 WSR*** 3/27/2023 Continueed from 03-26-2023 **Assist S-Line** MIT-T Passed to 3752PSI. . Pumped 1.3 bbls Diesel down Tbg. to reach 4000 psi. Loss of196 psi 1st 15 min. Loss of 52 psi 2nd 15 min. Continued on 03-28-2023 WSR 3/27/2023 ***CONTINUED FROM 3/26/23 WSR*** (new well post) RAN RCH CBL FROM DEPLOYMENT SLEEVE AT 8,757' MD PER PROGRAM (TOC at 8,677') RAN 2.75" CENT BARBELL & 2.25" BRUSH TO DEPLOYMENT SLEEVE AT 8,757' MD RAN 2.75" CENT BARBELL W/ 2.25" PTSA DRIFT TO DEPLOYMENT SLEEVE AT 8,757' MD (TT pins smeared/ ring around no-go) SET 3-1/2" NS MONO-PACK LTP W/ PTSA AT 8,757' MD LRS ATTEMPTED MIT-T TO 4500 PSI (pressure rapidly fell off at 4450 psi) PULL 1.781" RSG PLUG FROM LTP AT 8,757' MD SET 1.781" XX-PLUG IN LTP PTSA AT 8,757' MD LRS PERFORMED PASSING MIT-T TO 3,752 psi ***CONTINUE ON 3/28/23 WSR*** 3/28/2023 Continued from 03-27-2023 Assist S-Line ****MIT-IA PASSED to 4270 psi.**** Pump down Tbg. w/ 5.6 bbls Diesel to reach 4500 psi. Loss of 177 psi 1st 15 min, Loss of 53 psi 2nd 15 min. FWHP=500/500/0 S-Line on location upon departure. 3/28/2023 ***CONTINUED FROM 3/27/23 WSR*** (new well post) LRS PERFORMED PASSING MIT-IA TO 4270 psi ***WELL S/I ON DEPARTURE*** 3/28/2023 LRS Well Testing Unit 6, Start WSR 3-28-23, IL Well L-112, Well Test, STBY, Cont WSR on 3-29-23 3/29/2023 LRS Well Testing Unit 6, Cont WSR from 3-28-23, IL Well L-112, Well Test, STBY, Cont WSR on 3-30-23 Daily Report of Well Operations PBU L-112A 3/29/2023 T/I/O= 560/640/49 Temp= SI. LRS 72 (NEW WELL POST) Pumped 0.7 bbls into the TBG to increase the pressure to 2000 psi prior to test. AOGCC ( Bob Noble) MIT-IA to 4500 psi (4618 psi max applied) PASSED at 4440 psi. IA lost 126 psi during the first 15 minutes and 52 psi during the second 15 minutes. IA lost 178 psi during the 30 minute test. Pumped 5.8 bbls of 86*F diesel to achieve test pressure. Bled back 4.9 bbls to Final T/I/O= 2008/640/25. Bled back 0.6 bbls from the TBG to Final T/I/O= 460/440/19. 3/29/2023 Assist S-Line No fluids pumped. Continued on 03-30-2023 3/29/2023 ***WELL S/I ON ARRIVAL*** R/U SLICKLINE. ***WSR CONTINUED ON 3-30-23*** 3/30/2023 ***WSR CONTINUED FROM 3-29-23*** ATTEMPTED TO PULL 1.781" XX PLUG FROM LTP @ 8757' MD; PULLED ENTIRE LTP ASS'Y W/ PLUG (ALL ELEMENTS ACCOUNTED FOR). ***WELL S/I ON DEPARTURE*** 3/30/2023 T/I/O= 725/614/23. Temp - SI. Conduct Injectivity Test. Pumped 83 bbls DSL, 2 bbls 60/40, and 75 bbls 120* 1* KCL into TBG to load TBG. Dropped ball. Pumped 59 bbls DSL and 95 bbls 110* 1% KCL (See log for rates). Pumped 2 bbls 60/40 and 30 bbls DSL for Freeze Protect. FWHP's = 2720/785/315 3/30/2023 Standby for S-Line Job Canceled. No fluids pumped 3/30/2023 LRS Well Testing Unit 6, Cont WSR from 3-29-23, IL Well L-112, Well Test, STBY, Cont WSR on 3-31-23 3/31/2023 ***WELL S/I ON ARRIVAL*** SET 3-1/2" WHIDDON ON DEP SLEEVE @ 8,757' MD PULLED RK-DGLV'S FROM ST#2 (7,710' MD), ST#3 (6,462' MD) & ST#4 (4,599' MD) SET RK-LGLV'S IN ST#4 (4,599' MD) & ST#3 (6,462' MD) SET RK-OGLV IN ST#2 (7,710' MD) PULLED EMPTY WHIDDON FROM DEP SLEEVE @ 8,757' MD ***WELL S/I ON DEPARTURE*** 3/31/2023 LRS Well Testing Unit 6, Cont WSR from 3-30-23, IL Well L-112, Well Test, STBY, Continue RU, PT, Cont WSR on 4-01-23 4/1/2023 LRS Well Testing Unit 6, Cont WSR from 3-31-23, IL Well L-112, Well Test, Finish PT, POP, Cont WSR on 4-02-23 4/2/2023 T/I/O= 1670/1700/0 Assist well test unit Pumped 23 BBLS 60/40 down TBG. FWHP= 2100/1700/0 4/2/2023 T/I/O = 350/1660/10. Temp = Warm. T & IA FL (Teser req). ALP = 1660 psi, AL online. T FL @ near surface. IA FL @ 7710' (sta #2, SO). Tester in control of well upon departure. 10:30 WELL NAME Date : Shoe @ :FC @ :Top Liner @ Type: Type : Type : Type : Type : Yes X No Yes X No Yes X No Yes X No Yes X No Date : Volume lost during displacement (bbls) : Density (ppg) : 8.33 Volume pumped (bbls) : 2 L-112a CEMENT REPORT 11-Feb-23 Hole Size :3.25"Casing Size :2-3/8" Lead Slurry Class G Volume (bbls): 16 15.5 Yield : 1.23 Sacks : 73 Mixing / Pumping Rate (bpm) : 0.7 Density (ppg) : Tail Slurry Volume (bbls) : Density (ppg) : Yield : Sacks : Mixing / Pumping Rate (bpm) : Post Flush (Spacer) 1.5 ppb Geovis Density (ppg) : 8.4 Rate (bpm) : Bump press : Volume : 7 Displacement : diesel Density (ppg) : 7.1 Rate (bpm) : 0.6 Volume (actual / calculated) : 17 0.6 Method Used To Determine TOC : cement location when returns were lost Casing Rotated? Reciprocated? % Returns during job : 0 Cement returns to surface? Spacer returns? Vol to Sur : 0 FCP (psi) : 1950 Pump used for disp : Coil Unit Plug Bumped? Cement In Place At : 13:05 2/11/2023 Estimated TOC : 8904' 10 Remarks: FI R S T S T A G E 11753 10901 8757 Preflush (Spacer) fresh water 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:Guhl, Meredith D (OGC) Subject:FW: PBU L-112A (PTD #222-138) Date:Tuesday, February 21, 2023 11:12:15 AM Meredith, Just an FYI: I gave approval for the following delay to a 10-407. Mel From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Tuesday, February 21, 2023 10:49 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Brodie Wages <David.Wages@hilcorp.com>; Abbie Barker <Abbie.Barker@hilcorp.com> Subject: PBU L-112A (PTD #222-138) Mel, Just a head’s up, we’ll be submitting another 10-403 for L-112A. This well was completed on 1/17/23 and was to be cemented post rig (Sundry #323-065). After pressure testing, it seems there is more work to be done which will be submitted ASAP. Once these sundries are completed I will submit the 10-407 with all work completed. Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. By Samantha Carlisle at 9:01 am, Feb 23, 2023 323-116 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2023.02.22 17:56:45 -09'00' Stan Golis (880) Biennial CMIT-TxIA or MIT-IA for cement packer integrity check. DSR-2/23/23 Compliance to CO 736 cement packer squeeze required. 10-404 MGR23FEB23 SFD 2/27/2023JLC 2/27/2023 2/27/23Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.27 17:10:58 -09'00' RBDMS JSB 022823 Post-CTD Packer Squeeze Well: L- 112a Well Name:L-112a API Number: 50-029-23129-01-00 Current Status:Operable Producer Estimated Start Date:3/1/2023 Rig:SL/Coil Sundry #: Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker First Call Engineer:Brodie Wages (907) 564-5006 (O) (713) 380-9836 (M) Second Call Engineer:Claire Mayfield (509)-670-8001 (M) AFE:221-00115.01.01 Current Bottom Hole Pressure:2228 psi @ 6600’ TVD 6.5 PPGE | Lower bound Max. Anticipated Surface Pressure:1568 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:753 psi (Taken on 11/17/22) Min ID:2.813” X at 2637’ MD Max Angle:59 Deg @ 5400’ MD MITs: 11/28/2022: CMIT to 4645 psi Formation Tops: x Ugnu: 3396’ MD, 2828’ TVD x Shrader Bluff N sands: 5889’ MD, 4188’ TVD x HRZ: 8878’ MD, 6247’ TVD x Kuparuk: 9313’ MD, 6651’ TVD Brief Well Summary: A CTD sidetrack of producer L-112 has been drilled west of L-112. The sidetrack will further develop a fault block that L-112 has already proved up. After CDR drilled the lateral, the completion consisting of ball drop frac sleeves in the toe then a swell packer and cementing valve mid lateral and solid pipe all the way back to the motherbore with a deployment sleeve was cemented in place. Unfortunately, the cement job did not cover the hole in the tubing. And the liner was landed high so the coil liner deployment sleeve is above the hole which is behind the coil liner. We cannot access the hole with mechanical means so the solution is a cement packer squeeze. This updated program covers the packer squeeze only. Once a passing MIT-T and MIT-IA is obtained, we will proceed with flowing the well to obtain WC% and make a determination if we will frac the well or not. Notes Regarding Wellbore Condition x Drill 1/14/2003 x 2/17/2003: Eline – Perforate x 2/22/2003: Frac – 210k# 16-20, max treat: 6467 psi, ave: 5555 psi x Many many HOTs, Coil FCO, B&Fs since. Uneventful well After CTD landed the 2-3/8” liner high, and the liner cement job was performed Objective: x Post-CTD, cement liner in place via bonsai completion, install LTP and LGLVs, POP through testers Post-CTD Packer Squeeze Well: L- 112a Coil (Complete 2/11/2023) 1. MU Northern Solutions Bonsai Cementing Stinger assembly to cementing BHA a. w/ bi-directional B shifting tools for sliding sleeve 2. RIH to cementing valve @ ~10,000’ a. Caution through deployment sleeve b. Review final drilling tally to confirm depths c. Record pickup weights above liner deployment sleeve 3. Prior to stinging into cementing valve, establish circulation pressures down coil taking returns up the coil backside a. These pressures will be compared to after we sting in to confirm we are injecting into the cementing valve and circulating up the liner annulus 4. RIH and sting into cementing valve a. Stinging in will simultaneously open the cementing valves via the shifting tools below the circ port 5. Stack out weight per NS company rep to ensure coil is in compression, flag pipe as needed 6. Establish circulation pressures, compare to pre-sting pressures 7. Circulate through ORCA valve with 1-2% KCl while RU cementers until returns are clean and no more changes are observed 8. RU Cementers, PT lines to leaktight at 4700 psi, set pump tips at 4700 psi 9. Line up cementers to pump down the coil, pump cement as follows, stage off coil micromotion a. 5 bbl freshwater spacer b. 23 bbls cement c. Freshwater displacement coil volume Cement Blend Details: Density, ppg 15.3 (+/- 0.25 ppg) Fluid Loss (mL/30 min): 100-200 Free water (mL): 0 Rheology: Yield Point: 15-25 Thickening Time (HRS): 3-4 hours Mix on the fly WSL Preference 4-5 hours Batch Mixxed WSL Preference Compressive Strength: Minimum 500 psi achieved 10. Displace cement at 0.75-1.5 BPM to 3 bbls above cementing valve 11. With 3 bbls of cement in the coil and above the stinger, stop pump and PU 20’ to pull off cementing valve and close the sliding sleeve. a. If unable to unsting, slack off 10k and pump at max rate to circulate out cement from the well, follow with a gel pill to clean liner annulus. Discuss with OE/NS plan forward 12. Pause for 5 min to allow cement to gel up 13. Re-establish circulation maintaining WHP a. Try to keep WHP constant so we don’t allow the cement to move 14. RIH to ~10’ above flag while circulating 1:1 then shut in the backside and push any cement left in the liner out the shoe of the liner, pump a full liner volume (~12 bbls) 15. At deployment sleeve, reciprocate while pumping to ensure LTP can set smoothly 16. WOC Completed Post-CTD Packer Squeeze Well: L- 112a 17. Freeze protect well Slickline (Complete 2/17/23) 18. Install plug in 2-3/8” liner @ ~8800’, 1-2 joints into the 2-3/8” liner a. Deviation at liner top area is ~25 deg 19. Dump ~10’ of sand on test plug 20. Pull St2 21. Install circ valve in St2 22. Circulate well to diesel 23. Dmy #2 24. MIT-T to 4500 psi 25. MIT-IA to 4500 psi while holding 2000 psi on the tubing a. Pre-CTD CMIT to 4645 psi b. This should pressure test the production casing through the hole to the top of cement which should be inside the 2-3/8” liner window. c. The test plug will prevent us from losing cement down the liner through the liner shoe track d. If TxIA does not track this indicates the cement has covered the hole in tubing, proceed to pull the test plug and set NS liner top packer and extended sealbore assembly per slickline steps below. e. If TxIA tracks, obtain circulating rates/pressures at 0.5, 1 and 2 BPM while taking returns up the tubing, Pull station 2 if necessary (we can circ diesel in IA through the hole if needed) and circulate the well to diesel, dummy station 2, coil will return to perform a packer squeeze 26. Freeze protect well 27. Pull test plug Eline with fullbore assist 1. Obtain leak detect log while fullbore pumps diesel into the IA a. Toolstring should be pressure, temperature, fullbore and inline spinners b. Log to be obtained from surface to the liner deployment sleeve c. Fullbore start pumping at 2 bpm for 10 bbls before eline starts datalogging i. No returns needed, pumped fluids should be pumped through the 2-3/8” liner to formation ii. Max pressure 4000 psi iii. Logging pump rate: 1-2 bpm d. Obtain 80, 120 fpm from 0’ to ~8750’ e. Discuss need for stop counts near GLMs depending on how moving pass data looks f. We are looking to make sure all valves are in pocket and no other holes have appeared Slickline w/ fullbore assist 2. Circulate well to dead crude or diesel a. Wellbore volume to hole @ 9071’: 266 bbls 3. Make up deployment sleeve stinger, Orca cementing valve, 3-1/2” x 4-1/2” Reactive water swell packer and NS deployment sleeve per Northern Solutions a. L-112a has the extended liner deployment sleeve per drawing below, use corresponding stinger Completed Post-CTD Packer Squeeze Well: L- 112a b. Include R plug with equalizing port when deploying LTP 4. Plant stinger in liner deployment sleeve 5. CMIT to 1000 psi to confirm the stinger is stung in and the lock is holding 6. Circulate a wellbore volume of fresh water through the hole in tubing 7. Pump 2500’ freeze protect in the tubing and IA a. Tubing vol to 2500’: 21.8 bbls b. IA volume to 2500’: 66 bbls 8. Pull R plug WAIT ON SWELL PACKER TO SET, 4 days Coil 9. RIH with ORCA cementing stinger and shifting tool 10. Prior to stinging in, circulate tubing to diesel 11. Sting in, open ORCA valve and land on ORCA no-go a. Fluid flow path with the packer set will be down the coil, out the orca valve, into the liner x tubing annulus, to the hole in tubing and finally, into the IA on top of the 4-1/2” production packer. 12. Pump diesel or dead crude down coil taking returns up the IA through the hole in the tubing a. At this time the wellbore and coil should be full of diesel 13. Pump Cement as follows: a. 5 bbl diesel spacer as needed b. 23 bbls cement i. This volume will fill the TxIA annulus from 9118’ to 8000’ which will be below St#2 GLM. c. Diesel displacement coil volume Cement Blend Details: Density, ppg 15.3 (+/- 0.25 ppg) Fluid Loss (mL/30 min): 100-200 Free water (mL): 0 Rheology: Yield Point: 15-25 Thickening Time (HRS): 8-10 hours Mix on the fly WSL Preference 10-12 hours Batch Mixxed WSL Preference Compressive Strength: Minimum 500 psi achieved 14. At 1-2 bbls from the nozzle with positive WHP, shut in the IA and pumps 15. Unsting from ORCA valve maintain WHP and circulate out remaining cement. 16. RIH with nozzle and circulate out any cement below the deployment sleeve, circulate clean to 10,000’ 17. WOC, RDMO Slickline 18. Install plug in stinger R-nipple 19. MIT-T to 4500 psi Run CBL from TOL to minimum of 200' above TOC. CBL to AOGCC. mgr from cement leaving coil 29.5 bbls of cement Post-CTD Packer Squeeze Well: L- 112a 20. MIT-IA to 4500 psi while holding 2000 psi on the tubing 21. Install LGLVs per GL engineer 22. Pull Liner test plug 23. RU Fullbore to pump stage 1 ball to open liner 24. Drop 1.375” ball and pump to sleeve 1 a. On L-1214 we never saw a pressure spike, only drop, the sleeves are pinned at 1200 psi b. Displace with 2% KCL or similar if more hydrostatic pressure is needed. Testers 1. POP well via SLBU: a. 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. b. Limit flow to 500 bpd c. If solids are < 1%, after 1.5 wellbore volumes (120 bbls) increase the production rate to 750 BLPD. d. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. e. 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. f. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr welltest. A separate program will be submitted for the frac and post frac operations to be covered under a separate sundry 2. Bi-biennial MIT-IA or CMIT-TxIA to 2500 psi. 24 hour notice for state to witness. Post-CTD Packer Squeeze Well: L- 112a Current WBD: DMY Post-CTD Packer Squeeze Well: L- 112a Proposed WBD (bonsai w/ packer squeeze): Post-CTD Packer Squeeze Well: L- 112a Proposed P&A WBD: Post-CTD Packer Squeeze Well: L- 112a Liner Details: L-112a Post-CTD Packer Squeeze Well: L- 112a Swell packer chart: 1 Rixse, Melvin G (OGC) From:Brodie Wages <david.wages@hilcorp.com> Sent:Thursday, February 23, 2023 3:20 PM To:Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] 20220223 1500 PTD222-138 PBU L-112A Sundry IA Squeeze HelloMel,seeanswersbelowinRED Thankyouforquickturnaround David“Brodie”Wages OpsEngineer C:713.380.9836 From:Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov> Sent:Thursday,February23,20233:11PM To:BrodieWages<david.wages@hilcorp.com> Subject:[EXTERNAL]202202231500PTD222Ͳ138PBULͲ112ASundryIASqueeze Brodie, Questionsregardingcementpackersqueeze: 1. TheschematicshowsthestatusofGLMs: a. SOat9037’ b. MMGat7710’ c. MMGat6462’ d. MMGat4599’ Aretheseactuallydummied? Yessir,butthatwasalsothereasonforthepreͲpackersqueezespinnerlog,tomakesureallthevalvesarestillinpocket 2. DoescurrentworkstartwithElinewithfullboreassist Yessir Leakdetectlog? WewillbeusingSpinners,temperatureandpressurechangesasourleakdetectlog.I’musingLDLasagenericterm 3. UnderCoilstep13Icalculate9118’–8000’(.0264)=29.5bbls.Doyouagree? Agree 4. Understep14“At1Ͳ2bblsfromthenozzle……1Ͳ2bblsofdieselorcement? Cement,ideawouldbetounderflushtokeep1Ͳ2bblsofcementinsidethecoilwhenwegotounstingfromtheORCA valve.Thatway,uponclosing,weshouldhavecementrightatthevalvebelowthenewswellpacker 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. CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 2 ThiswellwillberequiredtomeetrequirementsofCO736. 1. ACBLwillneedtoberun.Whendoyouwanttodothat? Iforgottoaddthat,willaddittotheslicklinestepwhilewearegettingtheMITs 2. MITseverytwoyears. Willdo. MelRixse SeniorPetroleumEngineer(PE) AlaskaOilandGasConservationCommission 907Ͳ793Ͳ1231Office 907Ͳ297Ͳ8474Cell CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission(AOGCC), StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,useor disclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit, and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactMelRixseat(907Ͳ793Ͳ1231)or(Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. David Douglas Hilcorp North Slope, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 02/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: L-112A PTD: 222-138 API: 50-029-23129-01-00 FINAL LWD FORMATION EVALUATION LOGS (01/08/2023 to 01/14/2023) Multiple Propagation Resistivity & Gamma Ray (2” & 5” MD/TVD Color Logs) Pressure While Drilling (PWD) Final Definitive Directional Surveys SFTP Transfer - Data Folders: Please include current contact information if different from above. February 3, 2023 February 1, 2023 By Samantha Carlisle at 11:51 am, Feb 01, 2023 323-065 MGR03FEB23 February 3, 2023 10-404 SFD 2/1/2023 DSR-2/1/23JLC 2/3/2023 2/3/2023Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.03 15:14:51 -09'00' RBDMS JSB 020323 Post-CTD Bonsai Cement Well: L- 112a Well Name:L-112a API Number: 50-029-23129-01-00 Current Status:Operable Producer Estimated Start Date:2/03/2023 Rig:SL/EL/Coil Sundry #: Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker First Call Engineer:Josh Stephens 907-777-8420 (O)970-779-1200 (M) Second Call Engineer:Claire Mayfield (509)-670-8001 (M) AFE:221-00115.01.01 Current Bottom Hole Pressure:2228 psi @ 6600’ TVD 6.5 PPGE | Lower bound Max. Anticipated Surface Pressure:1568 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:753 psi (Taken on 11/17/22) Min ID:2.813” X at 2637’ MD Max Angle:59 Deg @ 5400’ MD MITs: 11/28/2022: CMIT to 4645 psi Brief Well Summary: A CTD sidetrack of producer L-112 is planned to drill west of L-112. The sidetrack will further develop a fault block that L-112 has already proved up. After CDR drills the lateral, the completion consisting of ball drop frac sleeves in the toe then a swell packer and cementing valve mid lateral and solid pipe all the way back to the motherbore with a deployment sleeve will be run. After the swell packer has had time to set, service coil will RU to cement uphole of the packer through the cementing valve back to the motherbore and deployment sleeve. This program only covers final liner cement job, installing the patch to re-establish wellbore integrity testing tubing integrity and popping the well to obtain updated water cuts for this new area of the fault block. A separate frac sundry and program will be submitted if the WC% comes in favorable. Update: CDR was unable to land the liner to TD and ended up setting the liner top above the known TBG leak at 9,069’. The proposed sundry change is to continue the liner cement job with intention of scabbing over the TBG leak since setting a patch is no longer a viable option. Notes Regarding Wellbore Condition x Drill 1/14/2003 x 2/17/2003: Eline – Perforate x 2/22/2003: Frac – 210k# 16-20, max treat: 6467 psi, ave: 5555 psi x Many many HOTs, Coil FCO, B&Fs since. Uneventful well Objective: x Post-CTD, cement liner in place via bonsai completion,bring TOC to top of line to scab over known TBG leak.leak. TBG liner Post-CTD Bonsai Cement Well: L- 112a Sundry Procedure (PTD#: 222-138) Fullbore 1. MIT-IA and perform LLR of known TBG leak a. If IA LLR is greater than 1.5BPM at 2,500psi, load IA with 170bbls diesel, taking returns to formation. Note pressure and rates during load and final IA pressure. 2. RDMO Fullbore Slickline (contingent if fullbore cannot load IA) 1. Pull DGLV #2 2. Have fullbore load IA with 145bbls of diesel 3. Install DGLV #2 Coil 1. MU Northern Solutions Bonsai Cementing Stinger assembly to cementing BHA a. w/ bi-directional B shifting tools for sliding sleeve 2. Load TBG and Liner with heated Diesel, and monitor WHP a. If WHP is below 300psi, drop 1-3/8” dissolvable ball to help with losses during cleanout b. Do not land ball on seat to avoid hydro locking stinger assembly c. Ball seat is pinned to 1,250psi so WHP must be kept to a minimum during operations to avoid shear out. 3. RIH to above cement cementing valve @ ~10,855’ a. Caution through deployment sleeve b. Review final drilling tally to confirm depths c. Record pickup weights above liner deployment sleeve 4. Prior to stinging into cementing valve, establish circulation pressures down coil taking returns up the coil backside a. These pressures will be compared to after we sting in to confirm we are injecting into the cementing valve and circulating up the liner annulus 5.Stop and circulate 5bbl gel pill in the CTxLiner annulus 6. RIH and sting into cementing valve a. Stinging in will simultaneously open the cementing valves via the shifting tools below the circ port 7. Stack out weight per NS company rep to ensure coil is in compression, flag pipe as needed 8. Establish circulation pressures, compare to pre-sting pressures 9. Circulate through cementing sleeve with Diesel while RU cementers until returns are clean and no more changes are observed 10. RU Cementers, PT lines to leaktight at 4700 psi, set pump trips at 4700 psi 11. Line up cementers to pump down the coil, pump cement as follows, stage off coil micromotion a. 5 bbl freshwater spacer b. 20 bbls cement c. Freshwater displacement coil volume Post-CTD Bonsai Cement Well: L- 112a Cement Blend Details: Density, ppg 15.3 (+/- 0.25 ppg) Fluid Loss (mL/30 min): 100-200 Free water (mL): 0 Rheology: Yield Point: 15-25 Thickening Time (HRS): 3-4 hours Mix on the fly WSL Preference 4-5 hours Batch Mixxed WSL Preference Compressive Strength: Minimum 500 psi achieved 12. Displace cement at 0.75-1.5 BPM 13. As the last of the cement leaves the coil. Pick up to unsting and close sleeve with the BO shifting tool. Continue to pick up without circulating (so as to minimize residual cement falling out of the coil) until back above the depth powervis was circulated in at (~10600). 14. Begin circulating residual cement, FW, and powervis out of the coil taking 1:1 returns and minimizing ECD and BHP. Once FW spacer circulated out, and powervis at the nozzle run back in hole to within 25’ of sleeve depth to contaminate cement that may have fallen back through the sleeve or fallen out of the coil. 15. If frac ball pumped, it may have seated at this point and will provide an additional 1250 psi of BHP support. Any increased BHP or losses will still attempt to push the cement from behind the liner into formation so we want to minimize this effect if possible. 16. Chase out contaminated cement, powervis, and any residual cement from around the liner lap to surface by circulating diesel. 17. At surface, quickly lay down tools, and make up the NS liner top seal assembly assembly. 18. RIH taking pipe displacement returns. 19. Stab into the liner top and pressure up with diesel to shift bottom frac sleeve if ball was dropped. Once sleeve opened and tubing isolation confirmed (no WHP response when pressuring up) Swap to powervis and slick seawater/2% KCl and circulate at max rate down the coil to flush/clean liner and ensure no residual cement across the sliding sleeve or ball seats. 20. Turn coil and liner back over to diesel, unsting, and POOH pumping pipe displacement. Maintain 1:1 as best as possible so as not to disturb cement. 21. RDMO CTU. Slickline 1. WOC 4 days 2. Drift TBG to deployment sleeve 3. MU liner top test plug and set in TOL at 8,757 4. Perform CMIT-TxIA to 3,000psi a. 3,300psi max applied 5. Perform MIT-T to 3,000psi a. 3,300psi max applied b. Note any TxIA communication c. If MIT-T fails perform LLR from TBG to IA 6. If MITs pass pull liner test plug a. Install live GLVs Post-CTD Bonsai Cement Well: L- 112a Testers (contingent on MITs) 1. POP well via SLBU: a. 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. b. Limit flow to 500 bpd c. If solids are < 1%, after 1.5 wellbore volumes (120 bbls) increase the production rate to 750 BLPD. d. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. e. 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. f. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr welltest. A separate program will be submitted for the frac and post frac operations to be covered under a separate sundry Post-CTD Bonsai Cement Well: L- 112a As-Build WBD: Post-CTD Bonsai Cement Well: L- 112a Proposed WBD (Post Liner Cement): Post-CTD Bonsai Cement Well: L- 112a Liner Details: Post-CTD Bonsai Cement Well: L- 112a Patch and Liner Details: 1.11.2023 By Meredith Guhl at 9:51 am, Jan 11, 2023 323-009 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.01.11 08:53:25 -09'00' Monty M Myers DSR-1/11/23DLB 01/11/2023 MGR11JAN23 Operations report inclusive of the drilling 10-407 completion report. X Biweekly BOPE test to 3500 psi to be continued from PTD. Brett W. Huber, Sr. GCW 01/13/23JLC 1/13/2023 1/13/23 RBDMS JSB 011723 The L-112A completion plan will be altered from solid liner run and cemented on Rig. The revised plan will be as follows: Rig Work: - Run 2-3/8” L-80 with 3 Frac sleeves, Swell packer, and Cementing valve. -RDMO Post Rig work: - Liner cementing to be conducted with service coil post rig. - A separate Sundry submission will be required for post rig cementing o Proposed schematic is attached. Rig Completion: 2-3/8” Solid Liner w/ Bonzai Frac Issues and Potential Hazards: x Liner will be run with E-line coil tubing using the BHI CoilTrak BHA with a hydraulic release GS tool. o The GS is designed to release via flow (~1½ bbls/min) while stacking weight. o Pump at minimum rate while RIH. o If the liner stacks out and requires picking up, pumping at minimum rate should minimize the likelihood of releasing the liner accidently. o The EDC will not open or close with more than 10,000 lbs hanging below it. Only RIH with the EDC open if running a short liner section. x NS Frac Sleeve o Seat Activation pressure – 2,500 psi (Plugged) – Limit the pump pressure to 2,000 psi going in the hole. o Tensile 74,000Lbs o 4-5’ pup joints will be installed above and below the sleeves for handling at the rig x Reactive Water Swell Packer o Elastomer OD x length – 2.6” x 3’ o Base pipe and threads – 2-3/8” 5.95# H511 o Swell time in 6% KCl – 12 hrs to 2.75”; 24hrs to 2.8”; 4.3 days to 3.0” x NS Cementing valve o Closed while RIH o Seat Activation pressure – 2,500 psi (Plugged) – Limit the pump pressure to 2,000 psi going in the hole. General Overview: This well will be completed with a 2-3/8”, 4.7# L-80 solid liner with 3 Frac sleeves, a swell packer, and a cementing valve. It will be run in hole using GS Spear. Liner will be released and left uncemented. Cement and FRAC to take place during post rig activities Operation Steps: 1. Order 1% KCl brine to displace the mud after liner is on bottom. 2. Drift and tally all liner and completion components. Record IDs, ODs, lengths and relevant fishing specs of all equipment. x Use minimal dope on the connections. Recommended to MU each connection with a stabbing guide to prevent pin & box end damage. x Drift first five made-up connections to confirm proper make-up torque and ensure clear path for the Frac Sleeve Ball (use 1.89” OD x 40’ drift, use CSH with a nozzle connected to a tugger). Maintain identical make-up torque on all subsequent joints. 3. Make up liner BHA as follows: Nom Size Item lb/ft Material Thread Notes 2д”Bull Nose Guide Shoe N/A L-80 HYD511 TD ~ 12,450’ MD 2д”Float Collar N/A L-80 HYD511 2д” 15’ joint 4.7 L-80 HYD511 No cementralizer 2д”Float Collar N/A L-80 HYD511 2д”5’ Pup joint 4.7 L-80 HYD511 2д”NS Frac Sleeve N/A P-110 HYD511 12,091’ 1.313” seat 2.625” OD 2д”5’ Pup joint 4.7 L-80 HYD511 2д” 30’ joints as needed 4.7 L-80 TH511 No cementralizer 2д”5’ Pup joint 4.7 L-80 HYD511 2д”NS Frac Sleeve N/A P-110 HYD511 11,591’ 1.438” seat 2.625” OD 2д”5’ Pup joint 4.7 L-80 HYD511 2д” 30’ joints as needed 4.7 L-80 TH511 No cementralizer 2д”5’ Pup joint 4.7 L-80 HYD511 2д”NS Frac Sleeve N/A P-110 HYD511 11,091’ 1.562” seat 2.625” OD 2д”5’ Pup joint 4.7 L-80 HYD511 2д” 30’ joints as needed 4.7 L-80 TH511 No cementralizer 2д”5’ Pup joint 4.7 L-80 HYD511 2.6”Swell Packer 5.95 L-80 H511 11,000’ 2д”5’ Pup joint 4.7 L-80 HYD511 2д” 30’ joints as needed 4.7 L-80 TH511 No cementralizer 2д”5’ Pup joint 4.7 L-80 HYD511 xx NS cementing valve N/A L-80 H511 10,930’ 2д”5’ Pup joint 4.7 L-80 HYD511 2д” 30’ joints as needed 4.7 L-80 TH511 Include cementralizers 2.70”2.70 Deployment Sleeve N/A L-80 TH511 9150’ MD Liner Running Tools Hydraulic Sealed GS running tool XO to BHI CoilTrak Tools 4. Confirm procedure for stripping liner in hole, when liner weight exceeds injector carriage limit (Max injector carriage weight is 20,000 lbs). x Ensure correct liner spaceout for making up CTC and stripping injector over pipe. 5. RIH with liner. Max 100 ft/min above window, 50 ft/min through window and in 100 ft/min in OH. Pump down the CT at 0.2 – 0.4 bbl/min to ensure that the liner is not plugged. Correct depth at first flag. x Note liner hanging weight at surface and obtain up and down weight of liner before entering the open hole. x Limit circulation pressure to 2000 psi to keep from inadvertently opening sleeves if packoff occurs. x Circulate KWF out of wellbore to drilling fluid at window before going into open hole. This is so we can circulate and work liner to bottom and don’t have to swap in open hole. o Ensure backpressure is held to apply the same pressure on the formation as seen while drilling. 6. Tag TD and correlate depth. PU and check weight. Stack 10 klbs on bottom and establish circulation rate as per rep. Release liner from hydraulic GS. Confirm based on surface string weight and BHI DHWOB. x Note: Reevaluate TOL position in tubing prior to release if landed off bottom. 7. Displace drilling fluid with KCl completion brine. Ensure to hold backpressure to remain overbalanced. 8. Make Tie-in Pass. To confirm depth of top of liner, make tie in log to ensure that liner is on depth at TD. running Fluids to be overbalanced to pore pressure when running liner. mgr 9. On trip out of hole, freeze protect tubing from ~2500’ TVD with diesel. Ensure to hold backpressure to remain overbalanced. 10. POH. Grease and shut tree valves. 11. Perform slack management to prepare for the next well (unless reel swap is planned). 12. If tree work is required post-rig, dry rod in TWC/BPV. If lubricator is required setting should be done post rig. 13. NU tree cap with new green O-ring & ring gasket. 14. Pressure test tree cap with MeOH against closed swab to 3500 psi. This is a visual test only as leak-by past swab is possible. Document in WellEz: “Leak tight test results - no visible leaks”. 15. Verify tree valves (MV, SV) closed for move off of the well. 16. RDMO CTD. Post-CTD Bonsai Cement Well: L- 112a Well Name:L-112a API Number: 50-029-23129 Current Status:Operable Producer Estimated Start Date:1/20/2023 Rig:SL/EL/Coil Sundry #: Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker First Call Engineer:Brodie Wages (907) 564-5006 (O) (713) 380-9836 (M) Second Call Engineer:Claire Mayfield (509)-670-8001 (M) AFE:221-00115.01.01 Current Bottom Hole Pressure:2228 psi @ 6600’ TVD 6.5 PPGE | Lower bound Max. Anticipated Surface Pressure:1568 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:753 psi (Taken on 11/17/22) Min ID:2.813” X at 2637’ MD Max Angle:59 Deg @ 5400’ MD MITs: 11/28/2022: CMIT to 4645 psi Brief Well Summary: A CTD sidetrack of producer L-112 is planned to drill west of L-112. The sidetrack will further develop a fault block that L-112 has already proved up. After CDR drills the lateral, the completion consisting of ball drop frac sleeves in the toe then a swell packer and cementing valve mid lateral and solid pipe all the way back to the motherbore with a deployment sleeve will be run. After the swell packer has had time to set, service coil will RU to cement uphole of the packer through the cementing valve back to the motherbore and deployment sleeve. This program only covers final liner cement job, installing the patch to re-establish wellbore integrity and Popping the well to obtain updated water cuts for this new area of the fault block. A separate frac sundry and program will be submitted if the WC% comes in favorable. Notes Regarding Wellbore Condition x Drill 1/14/2003 x 2/17/2003: Eline – Perforate x 2/22/2003: Frac – 210k# 16-20, max treat: 6467 psi, ave: 5555 psi x Many many HOTs, Coil FCO, B&Fs since. Uneventful well Objective: x Post-CTD, cement liner in place via bonsai completion, install LTP and LGLVs, POP through testers -01-00 DLB Post-CTD Bonsai Cement Well: L- 112a Sundry Procedure (PTD#: XXX-XXX) Coil 1. MU Northern Solutions Bonsai Cementing Stinger assembly to cementing BHA a. w/ bi-directional B shifting tools for sliding sleeve 2. RIH to cementing valve @ ~10,000’ a. Caution through deployment sleeve b. Review final drilling tally to confirm depths c. Record pickup weights above liner deployment sleeve 3. Prior to stinging into cementing valve, establish circulation pressures down coil taking returns up the coil backside a. These pressures will be compared to after we sting in to confirm we are injecting into the cementing valve and circulating up the liner annulus 4. RIH and sting into cementing valve a. Stinging in will simultaneously open the cementing valves via the shifting tools below the circ port 5. Stack out weight per NS company rep to ensure coil is in compression, flag pipe as needed 6. Establish circulation pressures, compare to pre-sting pressures 7. Circulate through ORCA valve with 1-2% KCl while RU cementers until returns are clean and no more changes are observed 8. RU Cementers, PT lines to leaktight at 4700 psi, set pump tips at 4700 psi 9. Line up cementers to pump down the coil, pump cement as follows, stage off coil micromotion a. 5 bbl freshwater spacer b. 23 bbls cement c. Freshwater displacement coil volume Cement Blend Details: Density, ppg 15.3 (+/- 0.25 ppg) Fluid Loss (mL/30 min): 100-200 Free water (mL): 0 Rheology: Yield Point: 15-25 Thickening Time (HRS): 3-4 hours Mix on the fly WSL Preference 4-5 hours Batch Mixxed WSL Preference Compressive Strength: Minimum 500 psi achieved 10. Displace cement at 0.75-1.5 BPM to 3 bbls above cementing valve 11. With 3 bbls of cement in the coil and above the stinger, stop pump and PU 20’ to pull off cementing valve and close the sliding sleeve. a. If unable to unsting, slack off 10k and pump at max rate to circulate out cement from the well, follow with a gel pill to clean liner annulus. Discuss with OE/NS plan forward 12. Pause for 5 min to allow cement to gel up 13. Re-establish circulation maintaining WHP a. Try to keep WHP constant so we don’t allow the cement to move 14. RIH to ~10’ above flag while circulating 1:1 then shut in the backside and push any cement left in the liner out the shoe of the liner, pump a full liner volume (~12 bbls) 15. At deployment sleeve, reciprocate to ensure LTP can set smoothly Post-CTD Bonsai Cement Well: L- 112a 16. RDMO Slickline 17. Drift 18. Have fullbore displace well to diesel or crude a. Volume to LTP: 80 bbls b. Diesel hydrostatic to 6497’ (9150’ MD): 2264 psi c. Reservoir pressure: 2200 psi d. L-112 is in the same fault block, due to low reservoir pressure we had difficulty pulling the R- plug out of the LTP PTSA. 19. MU and RIH with Northern Solutions LTP and PTSA seal assembly a. 225 PTSA seal assembly 10’ long 20. Pull/reset R-lock and test tool in nipple/deployment seal to PT LTP assembly to 3000 psi 21. Install 3-1/2” x 2-3/8” nipple reducer with plug in X nipple @ 9143’ a. Patch ID after setting is 2.330” b. Pressure test to 3000 psi to confirm set c. IA will track via the hole in tubing at ~9071’ Eline 1. RIH with Spinner/Temperature/Pressure log to determine leak depth a. Pre-work identified leak at ~9071’, above the sliding sleeve b. Perform multiple passes at 40-80 fpm while fullbore pumps dead crude or diesel into the IA taking returns up the tubing c. After hole depth is found, allow tubing/IA to U-tube to reestablish freeze protect d. If unable to find with spinner/temp, discuss with OE using an acoustic log 2. Using STP log as tie in, set X-Span patch over hole 3. Obtain MIT-T to 4500 psi a. 4750 max applied b. 0 psi on IA Slickline/Fullbore 1. Install LGLVs per GL engineer 2. Pull plug in nipple reducer 3. RU Fullbore to pump stage 1 ball to open liner 4. Drop 1.375” ball and pump to sleeve 1 Testers 4. POP well via SLBU: a. 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. b. Limit flow to 500 bpd c. If solids are < 1%, after 1.5 wellbore volumes (120 bbls) increase the production rate to 750 BLPD. d. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. Post-CTD Bonsai Cement Well: L- 112a e. 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. f. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr welltest. A separate program will be submitted for the frac and post frac operations to be covered under a separate sundry Post-CTD Bonsai Cement Well: L- 112a Proposed WBD (bonsai): Post-CTD Bonsai Cement Well: L- 112a Liner Details: Post-CTD Bonsai Cement Well: L- 112a Patch and Liner Details: 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 Monty Myers Drilling Manager Hilcorp North Slope Alaska, LLC 3800 CenterPoint Drive, Suite 1400 Anchorage Alaska 99503 Re: Prudhoe Bay Field, Borealis Oil Pool, PBU L-112A Hilcorp North Slope, LLC Permit to Drill Number: 222-138 Surface Location: 2525' FSL, 3874' FEL, Sec. 34, T12N, R11E, UM, AK Bottomhole Location: 807' FNL, 1206' FEL, Sec. 32, T12N, R11E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this ___ day of December, 2022. 14 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.12.14 15:11:30 -09'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 12091' TVD: 6682' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon:8.DNR Approval Number:13.Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3800' 4b. Location of Well (State Base Plane Coordinates - NAD 27):10.KB Elevation above MSL (ft):15.Distance to Nearest Well Open Surface: x-583040 y- 5978244 Zone- 4 to Same Pool: 700' 16.Deviated wells: Kickoff depth: 9390 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 111 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 3-1/4" 2-3/8" 4.7# L-80 Hyd 511 2941' 9150' 6497' 12091' 6682' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): None TVD 36 - 116 35 - 2670 32 - 6932 Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Sean McLaughlin Contact Email:sean.mclaughlin@hilcorp.com Contact Phone:907-223-6784 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng January 5, 2023 Monty Myers Drilling Manager 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 3074 260 sx Arctic Set (Approx.) 36 - 116 35 - 31099-5/8" 479 sx AS Lite III, 360 sx Class G Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: 358 sx Class G, 146 sx Class GProduction Liner 9580 Intermediate Authorized Name: 9358 - 9382 Conductor/Structural 20"80 9640 6958 LengthCasing 9164 Cement Volume MDSize Plugs (measured): (including stage data) 122 sx Class G 6511 9164 5019 18. Casing Program: Top - Setting Depth - BottomSpecifications 2197 Total Depth MD (ft): Total Depth TVD (ft): 107205344 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1537 1101' FNL, 1148' FWL, Sec. 33, T12N, R11E, UM, AK 807' FNL, 1206' FEL, Sec. 32, T12N, R11E, UM, AK 00-001 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 Hilcorp North Slope, LLC 2525' FSL, 3874' FEL, Sec. 34, T12N, R11E, UM, AK ADL 028239 & 047449 PBU L-112A PRUDHOE BAY, BOREALIS OIL Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements.50-029-23129-01-00 6693 - 6716 32 - 96127" Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 12.8.2022 By Anne Prysunka at 9:41 am, Dec 09, 2022 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2022.12.08 16:25:36 -09'00' Monty M Myers 222-153 X Concur DLB X X X X X X 138 MGR14DEC2022 DSR-12/9/22 REVISION * BOPE test to 3500 psi. * Variance to 20 AAC 25.112(i) Alternate plug placement previous lateral abandonment. *CBL to AOGCC upon completion. DLB DLB 12/09/2022GCW 12/14/22 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.12.14 15:11:48 -09'00' To: Alaska Oil & Gas Conservation Commission From: Sean McLaughlin Drilling Engineer Date: December 8, 2022 Re: PBU L-112A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well PBU L-112 with the Nabors CDR2 Coiled Tubing Drilling. Proposed plan for L-112A Producer: See L-112 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock and MIT. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. A 3-1/2"x7" HEW whipstock will be set with the rig. A 2.80" window +10’ of formation will be milled out of the 7” casing. The well will kick off drilling and land in the Kuparuk. The lateral will continue in the Kuparuk to TD. The proposed sidetrack will be completed with a 2-3/8” L-80 solid liner and cemented in place. The well will be selectively perforated post rig (see future perf sundry). This completion will completely isolate and abandon the parent Kuparuk perfs. After the well has produced for approximately 3 month a separate Sundry will be filed for conversion to injection service. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: x Reference L-112 Sundry submitted in concert with this request for full details. x General work scope of Pre-Rig work: 1. Eline: CBL of 7” casing below tubing tail 2. Slickline: Dummy WS drift 3. Fullbore: MITs Rig Work - (Estimated to start in January 2023): 1. MIRU and test BOPE to 3500 psi. MASP with gas (0.10 psi/ft) to surface is 1,537 psi a. Give AOGCC 24hr notice prior to BOPE test b. Test against swab and master valves (No TWC) c. Load pits with drilling fluid d. Open well and ensure zero pressure 2. Set 3-1/2”x7” HEW (whipstock) a. Set top of whipstock at 9,386’ MD b. Set 10° LOHS 3. Mill 2.80” single string window (out of 7”) plus 10’ of rathole a. Top of window (whipstock pinch point) at 9,390’ MD. b. Hold 11.0 ppg MPD while milling window 4. Drill – Build & Lateral a. 2-3/8” BHA with GR/RES / Bi-center Bit (3.25”) b. 32° DLS build section – 400’ MD / Planned TD 9,790’ MD c. 8° DLS lateral section – 2,762’ MD / Planned TD 12,091’ MD d. Drill with a constant bottom hole pressure for entire sidetrack e. Pressure deployment will be utilized f. After TD and on the last trip out of hole lay in completion/kill weight fluid in preparation for liner run g. No flow test prior to laying down drilling BHA 5. Run and Cement 2-3/8” L-80 solid liner a. Have 2” safety joint with TIW valve ready to be picked up while running liner b. Release from liner and come out of hole. c. Make up cementing BHA and sting into liner shoe. Swap the well over to 2% KCl. d. Cement liner with 27 bbls, 15.3 ppg Class G (TOC to TOL).* e. Freeze protect well from ~2200’ MD (min) f. RDMO Post Rig: 1. V: Valve & tree work 2. S: Set LTP* (if necessary) 3. C: Post rig perforate ~200’ (see future perf sundry) 4. S: Set live LGLVs 5. T: Portable test separator flowback * Approved alternate plug placement per 20 AAC 25.112(i) Managed Pressure Drilling: Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of the WC choke. Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will be accomplished utilizing 3” (bighole) & 2-3/8” (slimhole) pipe/slip rams (see attached BOP configurations). The annular preventer will act as a secondary containment during deployment and not as a stripper. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected: MPD Pressure at the Planned Window (9,390’ MD - 6,723’ TVD) Pumps On Pumps Off A Target BHP at Window (ppg)3,846 psi 3,846 psi 11 B Annular friction - ECD (psi/ft)836 psi 0 psi 0.09 C Mud Hydrostatic (ppg)3,007 psi 3,007 psi 8.6 B+C Mud + ECD Combined 3,842 psi 3,007 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 3 psi 839 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 2,197 psi at 6,600’ TVD (6.4 ppg equivalent). DLB MPD Pressure at the Planned Window (9,390’ MD - 6,723’ TVD) pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Managed Pressure Drilling:gg Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom holegp g q py p pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surfacepyg ppgg p x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 1,537 psi (from estimated reservoir pressure). Mud Program: x Drilling: Minimum MW of 8.4 ppg KCL with Geovis for drilling. Managed pressure used to maintain constant BHP. x KWF will be stored on location. The tankage will contain 1.5 wellbore volumes of KWF to exceed the maximum possible BHP to be encountered as the lateral is drilled. Adjust with real time BHP monitoring. x Completion: A minimum MW 8.4 ppg KWF to be used for liner deployment. Will target 11.0 ppg to match managed pressure target. Disposal: x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. x Fluids >1% hydrocarbons or flammables must go to GNI. x Fluids >15% solids by volume must go to GNI. x Fluids with solids that will not pass through 1/4” screen must go to GNI. x Fluids with PH >11 must go to GNI. Hole Size: x 3.25” hole for the entirety of the production hole section. Liner Program: x 2-3/8”, 4.6#, L-80 solid/cemented liner: 9,150’ MD – 12,091’ MD (2,941’ liner) x The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary x A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Well Control: x BOP diagram is attached. MPD and pressure deployment is planned. x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. x The annular preventer will be tested to 250 psi and 2,500 psi. x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. x A X-over shall be made up to a 2” safety joint including a TIW valve for all tubulars ran in hole. x 2” safety joint will be utilized while running solid or slotted liner. The desire is to keep the same standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint with pre- installed TIW valve). When closing on a 2” safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Directional: x Directional plan attached. Maximum planned hole angle is 111°. Inclination at kick off point is 20°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 3,800’ x Distance to nearest well within pool – 700’ Logging: x MWD directional, Gamma Ray, and Resistivity will be run through the entire open hole section. x Real time bore pressure to aid in MPD and ECD management. Perforating: x ~200’ perforated post rig – See future perf/frac sundry. x If deemed necessary, the rig will perforate under this PTD (1-11/16” Perf Guns at 6 spf). Anti-Collision Failures: x No failures on WP03 Hazards: x PBU L-pad is an H2S pad. The highest recorded H2S well on the pad was from L-124 (1,000 ppm) in 2021. Last recorded H2S on L-112 was 46 ppm in 2021. x One fault crossing expected. x Medium lost circulation risk. Sean McLaughlin CC: Well File Drilling Engineer 907-223-6784 Joseph Lastufka 6WDQGDUG3URSRVDO5HSRUW 2FWREHU 3ODQ /$ZS +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ / 3ODQ / /$ 560058006000620064006600680070007200True Vertical Depth (400 usft/in)5000 5200 5400 5600 5800 6000 6200 6400 6600 6800 7000 7200 7400 7600 7800 8000 8200 8400 8600 8800 9000Vertical Section at 283.89° (400 usft/in)L-112A wp03 Tgt2L-112A wp03 Tgt3L-112A wp03 Tgt4L-112A wp03 Tgt1L-112A wp03 Tgt5L-112A wp03 Tgt6L-112A wp03 Tgt7L-112A wp03 polygon80008500900095009640L-1127" TOW2 3/8" x 3 1/4"95001 0 0 0 0 1 0500 11 0 0 0 11 5 0 0 1 2000 1 20 9 1L-112A wp03KOP : Start Dir 9º/100' : 9390' MD, 6723.19'TVD : 10° LT TFStart Dir 32º/100' : 9420' MD, 6751.17'TVDStart Dir 8º/100' : 9789.93' MD, 6837.11'TVDTotal Depth : 12091' MD, 6682.03' TVDHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: L-112Ground Level: 47.70+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005978244.240583040.400 70° 21' 1.9315 N 149° 19' 32.8636 WSURVEY PROGRAMDate: 2022-10-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool93.00 722.00 L-112 Srvy 1 CB GYRO SS (L-112) 3_CB-Film-GSS766.48 9390.00 L-112 Srvy 2 MWD+IFR+MS (L-112)3_MWD (BP MWD+IFR+MS-WOCA)9390.00 12091.00 L-112A wp03 (L-112A) 3_MWDFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-112, True NorthVertical (TVD) Reference:Kelly Bushing / Rotary Table @ 82.04usft (DOYON 14)Measured Depth Reference:Kelly Bushing / Rotary Table @ 82.04usft (DOYON 14)Calculation Method: Minimum CurvatureProject:Prudhoe BaySite:LWell:Plan: L-112Wellbore:L-112ADesign:L-112A wp03CASING DETAILSTVD TVDSS MD SizeName6724.13 6642.09 9391.00 7 7" TOW6682.03 6599.99 12091.00 2-3/8 2 3/8" x 3 1/4"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 9390.00 19.79 288.63 6723.19 1657.81 -5552.23 0.00 0.00 5787.85 KOP : Start Dir 9º/100' : 9390' MD, 6723.19'TVD : 10° LT TF2 9420.00 22.45 287.40 6751.17 1661.15 -5562.51 9.00 -10.00 5798.63 Start Dir 32º/100' : 9420' MD, 6751.17'TVD3 9634.93 90.00 268.81 6864.43 1672.60 -5729.69 32.00 -20.00 5963.674 9789.93 109.28 222.17 6837.11 1613.01 -5864.84 32.00 -64.30 6080.56 Start Dir 8º/100' : 9789.93' MD, 6837.11'TVD5 9989.93 110.71 239.14 6768.27 1494.30 -6009.44 8.00 82.00 6192.446 10265.79 90.53 248.28 6717.59 1375.61 -6251.32 8.00155.00 6398.747 10815.79 90.59 292.28 6711.93 1378.22 -6787.86 8.00 89.70 6920.228 11015.79 91.39 276.30 6708.45 1427.41 -6981.02 8.00 -87.00 7119.549 11315.79 92.49 300.29 6698.13 1520.81 -7263.62 8.00 87.00 7416.2910 11465.79 92.02 288.29 6692.20 1582.34 -7399.99 8.00 -92.00 7563.4511 11865.79 90.39 320.25 6683.54 1804.63 -7726.17 8.00 92.50 7933.4612 12091.00 90.37 302.24 6682.03 1952.50 -7894.81 8.00 -90.00 8132.66 Total Depth : 12091' MD, 6682.03' TVD -550 -275 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 South(-)/North(+) (550 usft/in)-8250 -7975 -7700 -7425 -7150 -6875 -6600 -6325 -6050 -5775 -5500 -5225 -4950 -4675 West(-)/East(+) (550 usft/in) L-112A wp03 polygon L-112A wp03 Tgt7 L-112A wp03 Tgt6 L-112A wp03 Tgt5 L-112A wp03 Tgt1 L-112A wp03 Tgt4 L-112A wp03 Tgt3 L-112A wp03 Tgt2 5250550057506000625065006958L-112 7" TOW 2 3/8" x 3 1/4"6682L-112A wp03KOP : Start Dir 9º/100' : 9390' MD, 6723.19'TVD : 10° LT TF Start Dir 32º/100' : 9420' MD, 6751.17'TVD Start Dir 8º/100' : 9789.93' MD, 6837.11'TVD Total Depth : 12091' MD, 6682.03' TVD CASING DETAILS TVD TVDSS MD Size Name 6724.13 6642.09 9391.00 7 7" TOW 6682.03 6599.99 12091.00 2-3/8 2 3/8" x 3 1/4" Project: Prudhoe Bay Site: L Well: Plan: L-112 Wellbore: L-112A Plan: L-112A wp03 WELL DETAILS: Plan: L-112 Ground Level: 47.70 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5978244.240 583040.400 70° 21' 1.9315 N 149° 19' 32.8636 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: L-112, True North Vertical (TVD) Reference:Kelly Bushing / Rotary Table @ 82.04usft (DOYON 14) Measured Depth Reference:Kelly Bushing / Rotary Table @ 82.04usft (DOYON 14) Calculation Method:Minimum Curvature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eparation Factor9450 9600 9750 9900 10050 10200 10350 10500 10650 10800 10950 11100 11250 11400 11550 11700 11850 12000 12150 12300Measured Depth (300 usft/in)L-122L-112No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: L-112 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 47.70+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005978244.240583040.40070° 21' 1.9315 N149° 19' 32.8636 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-112, True NorthVertical (TVD) Reference: Kelly Bushing / Rotary Table @ 82.04usft (DOYON 14)Measured Depth Reference:Kelly Bushing / Rotary Table @ 82.04usft (DOYON 14)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-10-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool93.00 722.00 L-112 Srvy 1 CB GYRO SS (L-112) 3_CB-Film-GSS766.48 9390.00 L-112 Srvy 2 MWD+IFR+MS (L-112) 3_MWD (BP MWD+IFR+MS-WOCA)9390.00 12091.00 L-112A wp03 (L-112A) 3_MWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)9450 9600 9750 9900 10050 10200 10350 10500 10650 10800 10950 11100 11250 11400 11550 11700 11850 12000 12150 12300Measured Depth (300 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference9390.00 To 12091.00Project: Prudhoe BaySite: LWell: Plan: L-112Wellbore: L-112APlan: L-112A wp03CASING DETAILSTVD TVDSS MD Size Name6724.13 6642.09 9391.00 7 7" TOW6682.03 6599.99 12091.00 2-3/8 2 3/8" x 3 1/4" Well Date Quick Test Sub to Otis -1.1 ft Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular 2.75 ft C L Annular 3.40 ft Bottom Annular 4.75 ft CL Blind/Shears 6.09 ft CL 2.0" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip 9.54 ft CL 2.0" Pipe / Slips 10.40 ft TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR2-AC BOP Schematic CDR2 Rig's Drip Pan Fill Line from HF2 Normally Disconnected 3" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2.0" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2.0" Pipe/Slips 2-3/8" Pipe / Slip HF nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN BORE L-112AInitial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2221380PRUDHOE BAY, BOREALIS OIL - 640130NA1 Permit fee attachedYes Surface location in ADL0028239; top prod interval and TD in ADL0047449.2 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, BOREALIS OIL - 640130, governed by CO 471, modified by CO 471.0114 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Borealis Oil Pool is governed by AIO 24C.14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes PBU L-112, PBU L-114A15 All wells within 1/4 mile area of review identified (For service well only)No Well will not be pre-produced; will be flowed back for clean-up only.16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes This well is an inzone sidetrack from a parent well.18 Conductor string providedYes This well is an inzone sidetrack from a parent well.19 Surface casing protects all known USDWsYes This well is an inzone sidetrack from a parent well.20 CMT vol adequate to circulate on conductor & surf csgYes This well is an inzone sidetrack from a parent well.21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented 2-3/8" liner.22 CMT will cover all known productive horizonsYes This well is an inzone sidetrack from a parent well.23 Casing designs adequate for C, T, B & permafrostYes CDR 2 had adequate tankage and good trucking support.24 Adequate tankage or reserve pitYes Variance to 20 AAC 25.112(i) approved Sundry 322-616 Approved.25 If a re-drill, has a 10-403 for abandonment been approvedYes No collision risk wells identified in Halliburton collision scan26 Adequate wellbore separation proposedNA This well is an inzone sidetrack from a parent well.27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 1 CT pack off, 1 annular, 4 ram CTD stack29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3500 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes PBU L pad is an H2S pad. Monitoring will be required.33 Is presence of H2S gas probableYes L-112 parent, L-114A identified and checked for integrity.34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required. L-Pad wells are H2S bearing.35 Permit can be issued w/o hydrogen sulfide measuresYes Reservoir is expected to be under-pressured (6.4 ppg EMW). Real-time bore pressure monitoring and36 Data presented on potential overpressure zonesNA MPD will be utilized with 8.4 ppg mud to maintain 11 ppg EMW at the casing window.37 Seismic analysis of shallow gas zonesNA One fault crossing expected. Medium lost circulation risk.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate10/31/2022ApprMGRDate12/13/2022ApprSFDDate10/27/2022AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 12/14/2022 Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. (REVISION) X 222-138 PBU X X Borealis Oil PBU L-112A
