Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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M.
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P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
August 9, 2025
Commissioner Jessie Chmielowski
Alaska Oil & Gas Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
Commissioner Jessie Chmielowski:
Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of
these wells were found to have a void in the conductor. These voids were filled with cement if
needed and corrosion inhibitors, engineered to prevent water from entering the annular space.
As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification
that the treatments took place and meets the requirements of form 10-404, Report of Sundry
Operations. The attached spread sheet presents the well name, top of cement depth prior to filling
and volumes used on each conductor.
Please call Brennen Green or Roger Mouser at 907-659-7506, if you have any questions.
Sincerely,
ConocoPhillips Well Integrity Field Supervisor
RBDMS JSB 081425
Digitally signed by Brennen Green
DN: C=US, O=ConocoPhillips, CN=Brennen Green, E=n1927@
conocophillips.com
Reason: I am the author of this document
Location:
Date: 2025.08.11 16:34:01-08'00'
Foxit PDF Editor Version: 13.1.6
Brennen Green
ConocoPhillips Alaska Inc.Well Name API # PTD #Initial top of cementVol. of Portland Type I cement pumpedFinal top of cementCement top off date Corrosion inhibitorCorrosion inhibitor/ sealant datein gal in gal1C-17 50-029-22872-00-00 198-224 N/AN/A post SC Repair8" N/A 0.85 8/7/20251C-150 50-029-23496-00-00 213-120 N/AN/A Rig cemented to surface4" N/A 3 8/7/20251C-152 50-029-23548-00-00 215-114 50" 34.4 9" 7/31/2025 2.13 8/7/20251C-153 50-029-23549-00-00 215-116 N/AN/A Rig cemented to surface9" N/A 1.73 8/7/20251C-154 50-029-23559-00-00 215-166 70" 51.8 10" 7/31/2025 3.4 8/7/20251C-155 50-029-23561-00-00 215-180 64" 35.8 8" 7/31/2025 1.7 8/7/20251C-15650-029-23750-00-00 223-023 25" 12.00 10" 7/31/2025 5.1 8/7/20251C-157 50-029-23754-00-00 223-038 57" 30.28 9" 7/31/2025 2.2 8/7/20251C-15850-029-23761-00-00 223-056 3"N/A Rig cemented to surface10" 7/31/2025 4.25 8/7/20251C-501 50-029-23757-00-00 223-045 139" 11.40 8" 7/31/2025 3.8 8/7/20251H-107 50-029-23795-00-00 224-092 34" 14.80 10" 7/31/2025 5.25 8/7/20251H-11250-029-23787-01-00 224-032 47" 33.19 7" 7/31/2025 4.25 8/7/20251H-12050-029-23794-01-00 224-081 30" 13.70 8" 7/31/2025 4 8/7/20253H-3550-103-20805-00-00 219-064 45" 32.20 7" 8/1/2025 3.6 8/8/20253H-3650-103-20838-00-00 222-014 60" 44.20 8" 8/1/2025 3.4 8/8/20253H-3750-103-20822-00-00 219-194 35" 23.00 8" 8/1/2025 3.4 8/8/2025Date 08/09/251C, 1H, and 3H PadsKuparuk FieldReport of Sundry Operations (10-404)Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off3H-3650-103-20838-00-00222-01460"44.208"8/1/20253.48/8/2025
Operations shutdownPull TubingFracture StimulatePlug PerforationsSusp Well Insp1. Operations
Change Approved ProgramAlter CasingOther StimulatePerforateInstall WhipstockPerformed:
Other: ______________________Coiled Tubing OpsRepair WellPerforate New PoolMod Artificial Lift
ExploratoryDevelopmentConocoPhillips
6. API Number:ServiceStratigraphic
8. Well Name and Number:7. Property Designation (Lease Number):
10. Field/Pool(s):9. Logs (List logs and submit electronic data per 20AAC25.071):
11. Present Well Condition Summary:
feetnonefeetmeasured 17235Total Depth
true vertical 5948 feetnonefeet
feet12271feetmeasured 17196Effective Depth
feet5890feettrue vertical 5947
feetMeasured depthPerforation depth
feetTrue Vertical depth
Tubing (size, grade, measured and true vertical depth)4-1/2"5917.9' TVD12.6ppf L-80 12451.5' MD
Packers and SSSV (type, measured and true vertical depth)TNT Packer No SSSV12,270.9' MD / 5890.1'TVD
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:Post Job Report Below
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:Kuparuk River Pool
15. Well Class after work:
StratigraphicExploratory Development ServiceDaily Report of Well Operations
16. Well Status after work: Oil Gas WDSPLCopies of Logs and Surveys Run
GSTOR GINJElectronic Fracture Stimulation Data SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Contact Name:Digital Signature with Date:
Contact Email:
Contact Phone:Authorized Title:
5947', 5948', 5961', 5957', 5952' (No Stim), 5951', 5951' (No Stim), 5949',
5944', 5941', 5940'
Sr Pet Eng:
9210
Sr Res Eng:Sr Pet Geo:
WINJ WAG
N/A
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
N/A
0
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Tubing PressureCasing PressureGas-Mcf
MDSize
119
52103200.6
196
7-5/8"
11590
7-5/8"
4790
7850
6890
10860
0N/AN/A
2217N/A N/A
17196', 16835', 16356', 15962', 15505' (No Stim), 15133', 14717' (No Stim),
14261', 13908', 13471', 13034'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
222-014
50-103-20838-00-00
P.O. Box 100360 Anchorage, Alaska, 99510-03603. Address:
NA
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL365501 / ADL025524 / ADL025532 / ADL025531
Kuparuk River Pool
KRU 3H-36
Plugs
measuredJunk
Post Job Report Below
Length
120
3161.5
119Conductor
Surface
Intermediate
20"
10-3/4"
measured
TVD
Intermediate
Liner
11564.3
100.6
4787.3
Casing
Structural
5716.3
5926
4-1/2"
11603.4
12604
17230 5948.2
2970.8
CollapseBurst
2470
Development Service
GINJ SUSP SPLUG
Gas
G
Submit in PDF format to aogcc.permitting@alaska.govDue Within 30 days of OperationsForm 10-404 Revised 10/2022
Dustin Morrow
Completion Engineer
By Grace Christianson at 3:06 pm, Jun 20, 2023
Page 1/2Procedure Closeout3H-36Primary Job TypeSUPPORT OTHER OPERATIONSStart Date5/11/2023End Date5/21/2023Final Job StatusCOMPLETEDTotal Time Log Hours (hr)197.93SummaryNetwork/Order Number Project Desc Estimator10427640 3H-36 - FracStart Date ZX Code Time Log Hrs (hr)Cum Time Log (days) Last 24hr Sum5/11/2023 ZX02 Fracturing 12.00 0.50 SET UP TANK FARM IN CONTAINMENT. IN PROGRESS5/12/2023 ZX02 Fracturing 12.00 1.00 PREPPED EQUIPMENT. DELIVERED BLENDER, ADP & CASTLES TO LOCATION. CHANGED C PUMP IN ACID PUMP. WAIT FOR SLICKLINE TO FINISH POST RIG WELLWORK. IN PROGRESS5/14/2023 ZX02 Fracturing 12.00 1.50 HAL >> STAND UP CASTLES. RIG UP BLENDER, ADP, MISSILE & 6 FRAC PUMPS. RUN 4" IRON TO WELL. LOIL >> LOAD SAND CASTLES & SPOT WATER HEATERWELL SUPPORT >> SPOT POP OFF TANKS AND RU IA & OA POP OFF LINES AND FLOWLINE. 5/15/2023 ZX02 Fracturing 17.99 2.25 GREAT NORTH->>RIGGED UP LAUCHER EQUIPMENT, BALL LAUNCH LINE & ACID PUMP. SCAFFOLD WAS MODIFIED AROUND LAUNCH EQUIPOMENT. HAL ->> RIGGED UP FRONT YARD EQUIPMENT & EPRV'SWORLEY->> BEGAN HAULING WATER FROM CPF3 TO 3H @ 1:00 PM. IN PROGRESS5/16/2023 ZX02 Fracturing 23.99 3.25 RUN CABLES TO TCC & CHECK COMMS. FINISH LOADING & HEATING SEAWATER. COMPLETE WATER TESTING FROM TANKS. IN PROGRESS5/17/2023 ZX02 Fracturing 23.99 4.25 PRESSURE UP TO 6067 PSI TO SHEAR GLASS ARSENAL DISC & ALPHA SLEEVE.PERFORM DFIT, SRT & SDT. **WAITING ON SUNDRY**. IN PROGRESS5/18/2023 ZX02 Fracturing 23.99 5.25 RECIEVED SUNDRY. HAD TO MAKE REPAIR TO BLENDER AGITATOR. PUMPED MINI FRAC. OBSERVE CLOSURE PRESSURE & FLUID EFFICIENCYPUMP STAGE #1 (ALPHA SLEEVE) PER DESIGN w/ 3448 LBS OF 100 MESH & 19,509 LBS OF 20/40 UP TO 4.14 PPG.STAGE #2 - DROP PRIMARY DART **NO SEAT** DROP BACKUP **GOOD SEAT**PUMPED STAGE PER DESIGN w/ 1622 LBS OF 100 MESH & 22,410 LBS OF 20/40 UP TO 3.93 PPGSTAGE #3 - DROP PRIMARY DART **NO SEAT** DROP BACKUP **GOOD SEAT**PUMPED STAGE PER DESIGN w/ 2416 LBS OF 100 MESH & 40,923 LBS OF 20/40 UP TO 3.98 PPGSTAGE #4 - DROP PRIMARY DART **GOOD SEAT**PUMP STAGE #4 PER DESIGN w/ 2564 LBS OF 100 MESH & 57,563 LBS OF 20/40 UP TO 6.34 PPGIN PROGRESS5/19/2023 ZX02 Fracturing 23.99 6.25 STAGE #6 - DROP PRIMARY DART **GOOD SHIFT**PUMPED STAGE PER DESIGN w/ 1908 LBS OF 100 MESH & 32,584 LBS OF 20/40 UP TO 3.93 PPGSTAGE #8 - DROPPED 3 DARTS BEFORE SEEING **GOOD SHIFT** PUMPED ALTERED STAGE DUE TO TIGHT SANDS w/ 1957 LBS OF 100 MESH & 57,090 LBS OF 20/40 UP TO 3.02 PPG. STAGE #9 - DROP PRIMARY DART **NO SEAT OBSERVED**DROP BACKUP DART (OLD BATCH DART) **GOOD SHIFT**PUMPED STAGE PER DESIGN w/ 3228 LBS OF 100 MESH & 57,090 LBS OF 20/40 UP TO 7.17 PPGSTAGE #10 - DROP PRIMARY DART **FAINT SHIFT** OBSERVE WATER HAMMER TO VERIFY DART WAS ON DEPTH. PUMPED STAGE PER DESIGN w/ 4102 LBS OF 100 MESH & 76,203 LBS OF 20/40 UP TO 6.04 PPGIN PROGRESS**NOTE: STAGES #5 & #7 WERE SKIPPED DUE TO PROXIMITY TO FAULTS (PER COMPLETION PROCEDURE)**5/20/2023 ZX02 Fracturing 23.99 7.25 STAGE #11 - DROP PRIMARY DART MECHANICAL DART **GOOD SHIFT**PUMPED STAGE PER DESIGN w/ 5732 LBS OF 100 MESH & 96,183 LBS OF 20/40 UP TO 6.73 PPG.FRAC COMPLETE. BEGIN RIGGING DOWN FRAC. IN PROGRESS
Page 2/2Procedure Closeout3H-36Start Date ZX Code Time Log Hrs (hr)Cum Time Log (days) Last 24hr Sum5/21/2023 ZX02 Fracturing 23.99 8.25 GNWF ->> RIG DOWN LAUNCHER EQUIPMENT, WELL SUPPORT ->> RIGGED DOWN SUPPORT TANKS & HAULED OFF TANKS.HAL & LOIL ->> RIGGED DOWN TANK FARM AND HAULED TANKS TO 3T & PICKED UP LINER FROM THE PAD. JOB COMPLETE & READY FOR SLICKLINE
Prepared By:
Alexander Bentz
James Campbell
Nannook Crew
Intervals 1-9 Kuparuk
Notice: Although the information contained in this report is based on sound engineering practices, the
copyright owner(s) does (do) not accept any responsibility whatsoever, in negligence or otherwise, for any
loss or damage arising from the possession or use of the report whether in terms of correctness or
otherwise. The application, therefore, by the user of this report or any part thereof, is solely at the users
own risk.
3H-36
Conoco Phillips
Harrison Bay County, AK
Post Job Report
Stimulation Treatment
API: 50-103-20838
Prepared for: Dustin Morrow
May 20, 2023
A-Sand Formation
30# Hybor G
299,927 gallons of 30# Hybor G
126,189 gallons of 30# Linear
6,300 gallons of Seawater
5,040 gallons of Calcium Chloride
443,000 pounds of Wanli 20/40 Ceramic
25,915 pounds of 100M
327,984 gallons of 30# Hybor G
254,334 gallons of 30# Linear
17,133 gallons of Seawater
1,547 gallons of Calcium Chloride
476,208 pounds of Wanli 20/40 Ceramic
39,000 pounds of 100M
Thank you,
Halliburton maintains a continuous quality improvement process and appreciates any comments or suggestions that you may
have. Halliburton again thanks you for the opportunity to perform service work on this well. We hope to be your solutions
provider for future projects.
Engineering Executive Summary
On May 17, 2023 a stimulation treatment was performed in the A-Sand formation on the 3H-36 well in Harrison Bay County,
AK. The 3H-36 was a 9 stage Horizontal Sleeve Design. The proposed treatment consisted of:
The actual treatment fully completed 9 of 9 stages. 0 stages were skipped, 0 stage screened out and 0 stages were cut short of
design. The actual treatment consisted of:
A more detailed description of the actual treatment can be found in the attached reports. The following comments were provided
to summarize events and changes to the proposed treatment:
Due to alterations in Pad volumes per CoP Engineer, approximately 12,000 lbs of 100 Mesh was left in the Sand Castle. CoP
Engineer did not want to pump the extra proppant. Only 20 Frac Tanks were delivered, and 1 was used for Brine per CSR. The
bucket test on May 19th was performed, however, due to an error in data collection, it was not recorded.
Halliburton is strongly committed to quality control on location. Before and after each job all chemicals, proppants, and fluid
volumes are measured to assure the highest level of quality control. Tank fluid analysis, crosslink time, and break tests are
performed before each job in order to optimize the performance of the treatment fluids.
Alexander Bentz
Technical Professional
Conoco Phillips - 3H-36 Executive Summary 3
Conoco Phillips Kuparuk3H-3650-103-20838*Exceeds 80% of burst pressure*Description OD (in) ID (in) Wt (#) GradeFUF (gal/ft)MD Top (ft) MD Btm (ft) Volume (gal)Tubular Burst Pressure (psi)Tubing4.5 3.958 12.6 L-80 0.6392 0 11,417 7,298 8,430Tubing4.5 3.958 12.6 L-80 0.6392 11,417 17,215 3,706 8,430Total17,21511,004ft1.45ft146.2ftft1.45ft146.2ftTop MD (ft) Btm MD (ft) Average TVD (ft) Interval # Formation DescriptorAverage Interval Temperature (F)Ball Drop Time (HH:MM)Ball Hit Time (HH:MM)JSV Drop (bbl)JSV Slow Down (bbl)JSV Hit (bbl)Early (bbl)Surface Seat Pressure (psi)Surface Peak Pressure (psi)Surface Differential (psi)BH Seat Pressure (psi)BH Peak Pressure (psi)BH Differential (psi)Rate at Shift (bpm)Toe17,196 17,199 5,9471Kuparuk A Sand146.2NA NA NA NA NA NA NA NA NA NA NA NA NA16,835 16,837 5,9482Kuparuk A Sand146.24:03:00 PM 4:19:00 PM 1,908 2,114 2,15014.22,534 4,797 2,263 4,716 6,725 2,009 15.116,356 16,359 5,9483Kuparuk A Sand146.25:06:00 PM 5:22:00 PM 3,127 3,326 3,35916.92,532 5,174 2,642 4,738 7,049 2,311 15.315,962 15,964 5,9474Kuparuk A Sand146.25:59:00 PM 6:10:00 PM 4,426 4,619 4,686-17.12,868 5,462 2,594 5,012 7,180 2,168 23.415,133 15,136 5,9475Kuparuk A Sand146.29:44:00 AM 10:01:00 AM 0 180 2219.33,596 4,326 730 5,771 6,225 454 15.314,261 14,264 5,9476Kuparuk A Sand146.211:38:00 AM 11:52:00 AM 1,513 1,680 1,71911.02,145 3,651 1,506 4,318 5,809 1,491 15.413,908 13,910 5,9447Kuparuk A Sand146.22:10:00 PM 2:23:00 PM 4,371 4,533 4,57111.72,138 2,894 756 4,325 5,138 813 15.413,472 13,474 5,9478Kuparuk A Sand146.22:55:00 PM 3:02:00 PM 5,435 5,590 5,62713.02,223 2,419 196 4,421 4,728 307 15.4Heel13,034 13,037 5,9409Kuparuk A Sand146.18:32:00 AM 8:45:00 AM 9 157 2043.42,167 4,295 2,128 4,282 5,752 1,470 15.4Temp. Gradient (°F/100 ft)BHST (°F)TVD at Bottom PerfMD at Bottom Perf5,94817,199KOPAvg. TVDTotal MD78923456Sleeve/Perf Depth SleevesInterval #1Max Pressure (psi)9,000Isolation TypeSwell PackersTreatment TubularsCustomerFormationLeaseAPIDateTemperature DataTemp. Gradient (°F/100 ft)BHST (°F)Directional Data5,9462,23717,215Directional Data2,2375/17/2023KOPTemperature Data10,455 248.910,2039,6739,116Displacement to Top Sleeve/Perf (gal)(BBLS)10,992 261.710,761 256.2242.9230.3217.08,8908,6118,332211.7205.0198.4Conoco Phillips - 3H-36 Wellbore Information 4
CUSTOMERConoco Phillips APIBFD (lb/gal)8.54LAT 70.41150064LEASE3H-36SALES ORDEBHST (°F)146LONG-150.0570785FORMATIONKuparukDATE Max Pressure (psi)9000*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant BufferInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In -1-2 Calcium Chloride Prime Up Pressure Test 5.0 1,260 -1-3 Shut-In Shut-In -1-4 Seawater Pump-In 5.0 1,260 2,295 55 55 0.151-5 Seawater Step Rate Test 20.0 5,040 14,838 353 353 0.151-6 Shut-In Shut-In -1-7 Calcium Chloride Prime Up Pressure Test 5.0 1,260 1,547 37 371-8 Shut-In Shut-In -1-9 30# Linear Pump-In 5.0 1,260 1,178 28 28 1.00 30.00 2.00 0.25 0.151-10 30# Hybor G Establish Stable Fluid 15.0 8,400 20,932 498 498 2.00 1.00 0.66 30.00 2.00 0.25 0.151-11 30# Hybor G Minifrac 15.0 6,300 6,259 149 149 2.00 1.00 0.82 30.00 2.00 0.25 0.151-12 30# Linear Flush 30.0 10,992 11,687 278 278 1.00 30.00 2.00 0.25 0.151-13 Shut-In Shut-In -1-14 30# Hybor G Establish Stable Fluid 15.0 8,400 7,373 176 176 2.00 1.00 0.82 30.00 2.00 0.25 0.151-15 30# Hybor G Pad 30.0 5,000 5,079 121 121 2.00 1.00 0.82 30.00 2.00 0.25 0.151-16 30# Hybor G Conditioning Pad 100M 0.50 30.0 5,000 4,998 119 123 2,500 3,448 2.00 1.00 0.82 30.00 2.00 0.25 0.151-17 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 1,716 1,692 40 42 1,716 1,744 2.00 1.00 0.82 30.00 2.00 0.25 0.151-18 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 1,560 1,556 37 41 3,120 3,448 2.00 1.00 0.82 30.00 2.00 0.25 0.151-19 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 1,560 1,643 39 45 4,680 5,271 2.00 1.00 0.82 30.00 2.00 0.25 0.151-20 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 871 3,302 79 88 3,484 9,046 2.00 1.00 0.82 30.00 2.00 0.25 0.151-21 30# Linear Spacer and Dart Drop 30.0 1,260 4,312 103 103 1.00 30.00 2.00 0.25 0.152-1 30# Linear Displacement 30.0 10,761 20,758 494 494 1.00 30.00 2.00 0.152-2 30# Hybor G Establish Stable Fluid 30.0 8,400 5,423 129 129 2.00 1.00 0.82 30.00 2.00 0.25 0.152-3 30# Hybor G Pad 30.0 2,100 2,543 61 61 2.00 1.00 0.82 30.00 2.00 0.25 0.152-4 30# Hybor G Conditioning Pad 100M 0.50 30.0 2,730 4,409 105 107 1,365 1,622 2.00 1.00 0.82 30.00 2.00 0.25 0.152-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 2,640 2,634 63 66 2,640 2,690 2.00 1.00 0.82 30.00 2.00 0.25 0.152-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 2,400 2,398 57 62 4,800 4,917 2.00 1.00 0.82 30.00 2.00 0.25 0.152-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 2,400 2,412 57 65 7,200 7,315 2.00 1.00 0.82 30.00 2.00 0.25 0.152-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 1,340 2,732 65 73 5,360 7,488 2.00 1.00 0.82 30.00 2.00 0.25 0.152-9 30# Linear Spacer and Dart Drop 30.0 1,260 1,722 41 41 1.00 30.00 2.00 0.25 0.153-1 30# Linear Displacement 30.0 10,455 26,958 642 642 1.00 30.00 2.00 0.153-2 30# Hybor G Establish Stable Fluid 30.0 8,400 13,397 319 319 2.00 1.00 0.81 30.00 2.00 0.25 0.153-3 30# Hybor G Pad 30.0 2,100 2,145 51 51 2.00 1.00 0.81 30.00 2.00 0.25 0.153-4 30# Hybor G Conditioning Pad 100M 0.50 30.0 5,250 5,744 137 139 2,625 2,416 2.00 1.00 0.81 30.00 2.00 0.25 0.153-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 5,280 5,324 127 132 5,280 5,163 2.00 1.00 0.81 30.00 2.00 0.25 0.153-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 4,800 4,787 114 124 9,600 9,658 2.00 1.00 0.81 30.00 2.00 0.25 0.153-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 4,800 4,791 114 130 14,400 14,543 2.00 1.00 0.81 30.00 2.00 0.25 0.153-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 2,680 3,948 94 106 10,720 11,559 2.00 1.00 0.81 30.00 2.00 0.25 0.153-9 30# Linear Spacer and Dart Drop 30.0 1,260 1,456 35 35 1.00 30.00 2.00 0.25 0.154-1 30# Linear Displacement 30.0 10,203 17,855 425 425 1.00 30.00 2.00 0.154-2 30# Hybor G Establish Stable Fluid 30.0 8,400 3,669 87 87 2.00 1.00 0.80 30.00 2.00 0.25 0.154-3 30# Hybor G Pad 30.0 2,100 2,366 56 56 2.00 1.00 0.80 30.00 2.00 0.25 0.154-4 30# Hybor G Conditioning Pad 100M 0.50 30.0 5,250 5,244 125 128 2,625 2,564 2.00 1.00 0.80 30.00 2.00 0.25 0.154-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 1,696 1,709 41 43 1,696 1,881 2.00 1.00 0.80 30.00 2.00 0.25 0.154-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 1,749 1,759 42 46 3,498 3,687 2.00 1.00 0.80 30.00 2.00 0.25 0.154-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 2,650 2,628 63 71 7,950 7,988 2.00 1.00 0.80 30.00 2.00 0.25 0.154-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 2,915 2,892 69 81 11,660 11,730 2.00 1.00 0.80 30.00 2.00 0.25 0.154-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30.0 2,650 2,658 63 78 13,250 13,482 2.00 1.00 0.80 30.00 2.00 0.25 0.154-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30.0 2,491 4,311 103 123 14,946 18,885 2.00 1.00 0.80 30.00 2.00 0.25 0.154-11 30# Linear Flush 30.0 10,847 10,917 260 260 1.00 30.00 2.00 0.25 0.154-12 Shut-In Shut-In -5-1 Shut-In Shut-In -5-2 Calcium Chloride Prime Up Pressure Test 5.0 1,260 -5-3 Shut-In Shut-In -5-4 30# Linear Spacer and Dart Drop 15.0 1,260 982 23 23 1.00 30.00 2.00 0.25 0.155-5 30# Linear Displacement 30.0 9,673 12,019 286 286 1.00 30.00 2.00 0.25 0.155-6 30# Hybor G Establish Stable Fluid 30.0 8,400 3,997 95 95 2.00 1.00 0.80 30.00 2.00 0.25 0.155-7 30# Hybor G Pad 30.0 2,100 2,899 69 69 2.00 1.00 0.80 30.00 2.00 0.25 0.155-8 30# Hybor G Conditioning Pad 100M 0.50 30.0 4,200 5,053 120 122 2,100 1,908 2.00 1.00 0.80 30.00 2.00 0.25 0.155-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 3,960 3,985 95 99 3,960 3,757 2.00 1.00 0.80 30.00 2.00 0.25 0.155-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 3,600 3,596 86 93 7,200 7,128 2.00 1.00 0.80 30.00 2.00 0.25 0.155-11 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 3,600 3,576 85 97 10,800 10,728 2.00 1.00 0.80 30.00 2.00 0.25 0.155-12 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 2,010 3,670 87 99 8,040 10,971 2.00 1.00 0.80 30.00 2.00 0.25 0.155-13 30# Linear Spacer and Dart Drop 30.0 1,260 2,241 53 53 1.00 30.00 2.00 0.25 0.15Interval 1Kuparuk A Sand@ 17196.2 - 17198.98 ft 146.2 °FInterval 2Kuparuk A Sand@ 16834.7 - 16837.48 ft 146.2 °FInterval 3Kuparuk A Sand@ 16356 - 16358.78 ft 146.2 °FInterval 4Kuparuk A Sand@ 15961.7 - 15964.48 ft 146.2 °FInterval 5Kuparuk A Sand@ 15133 - 15135.78 ft 146.2 °FLiquid Additives Dry Additives50-103-208380908606139 Conoco Phillips - 3H-36 Actual Design 5
CUSTOMERConoco Phillips APIBFD (lb/gal)8.54LAT 70.41150064LEASE3H-36SALES ORDEBHST (°F)146LONG-150.0570785FORMATIONKuparukDATE Max Pressure (psi)9000*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinker Surfactant BufferInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-208380908606139 6-1 30# Linear Displacement 30.0 9,116 30,440 725 725 1.00 30.00 2.00 0.25 0.156-2 30# Hybor G Establish Stable Fluid 30.0 8,400 4,997 119 119 2.00 1.00 0.80 30.00 2.00 0.25 0.156-3 30# Hybor G Pad 30.0 2,100 3,941 94 94 2.00 1.00 0.80 30.00 2.00 0.25 0.156-4 30# Linear Breakdown 30.0 48,277 1,149 1,149 1.00 30.00 2.00 0.25 0.156-5 30# Hybor G Establish Stable Fluid 30.0 8,400 3,136 75 75 2.00 1.00 0.80 30.00 2.00 0.25 0.156-6 30# Hybor G Pad 30.0 2,100 1,802 43 43 2.00 1.00 0.80 30.00 2.00 0.25 0.156-7 30# Hybor G Conditioning Pad 100M 0.50 30.0 4,620 5,150 123 125 2,310 1,957 2.00 1.00 0.80 30.00 2.00 0.25 0.156-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 1,920 6,792 162 169 1,920 6,850 2.00 1.00 0.80 30.00 2.00 0.25 0.156-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 1,980 4,041 96 105 3,960 8,416 2.00 1.00 0.80 30.00 2.00 0.25 0.156-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 3,000 14,962 356 401 9,000 42,324 2.00 1.00 0.80 30.00 2.00 0.25 0.156-11 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 3,300 - 13,200 2.00 1.00 0.80 30.00 2.00 0.25 0.156-12 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30.0 3,000 - 15,000 2.00 1.00 0.80 30.00 2.00 0.25 0.156-13 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30.0 2,820 - 16,920 2.00 1.00 0.80 30.00 2.00 0.25 0.156-14 30# Linear Spacer and Dart Drop 30.0 1,260 1,629 39 39 1.00 30.00 2.00 0.25 0.157-1 30# Linear Displacement 30.0 8,890 20,784 495 495 1.00 30.00 2.00 0.25 0.157-2 30# Hybor G Establish Stable Fluid 30.0 8,400 3,180 76 76 2.00 1.00 0.80 30.00 2.00 0.25 0.157-3 30# Hybor G Pad 30.0 2,100 2,385 57 57 2.00 1.00 0.80 30.00 2.00 0.25 0.157-4 30# Hybor G Conditioning Pad 100M 0.50 30.0 6,930 7,510 179 182 3,465 3,238 2.00 1.00 0.80 30.00 2.00 0.25 0.157-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 2,144 2,216 53 55 2,144 2,164 2.00 1.00 0.80 30.00 2.00 0.25 0.157-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 2,211 2,249 54 58 4,422 4,339 2.00 1.00 0.80 30.00 2.00 0.25 0.157-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 3,350 3,358 80 91 10,050 9,998 2.00 1.00 0.80 30.00 2.00 0.25 0.157-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 3,685 3,672 87 102 14,740 14,038 2.00 1.00 0.80 30.00 2.00 0.25 0.157-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30.0 3,350 3,389 81 98 16,750 16,695 2.00 1.00 0.80 30.00 2.00 0.25 0.157-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30.0 3,149 3,655 87 105 18,894 16,847 2.00 1.00 0.80 30.00 2.00 0.25 0.157-11 30# Linear Spacer and Dart Drop 30.0 1,260 1,886 45 45 1.00 30.00 2.00 0.25 0.158-1 30# Linear Displacement 30.0 8,611 11,877 283 283 1.00 30.00 2.00 0.25 0.158-2 30# Hybor G Establish Stable Fluid 30.0 8,400 4,041 96 96 2.00 1.00 0.80 30.00 2.00 0.25 0.158-3 30# Hybor G Pad 30.0 2,100 2,768 66 66 2.00 1.00 0.80 30.00 2.00 0.25 0.158-4 30# Hybor G Conditioning Pad 100M 0.50 30.0 8,400 8,760 209 213 4,200 4,102 2.00 1.00 0.80 30.00 2.00 0.25 0.158-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 2,464 2,674 64 66 2,464 2,098 2.00 1.00 0.80 30.00 2.00 0.25 0.158-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 2,541 2,777 66 71 5,082 4,410 2.00 1.00 0.80 30.00 2.00 0.25 0.158-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 3,850 3,874 92 104 11,550 10,752 2.00 1.00 0.80 30.00 2.00 0.25 0.158-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 4,235 4,240 101 118 16,940 16,332 2.00 1.00 0.80 30.00 2.00 0.25 0.158-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30.0 3,850 3,859 92 111 19,250 18,284 2.00 1.00 0.77 30.00 2.00 0.25 0.158-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30.0 3,619 5,363 128 154 21,714 24,327 2.00 1.00 0.77 30.00 2.00 0.25 0.158-11 30# Linear Flush 30.0 9,255 9,234 220 220 1.00 30.00 2.00 0.25 0.158-12 Calcium Chloride Freeze Protect 1,260 -8-13 Shut-In Shut-In -9-1 Shut-In Shut-In -9-2 Calcium Chloride Prime Up Pressure Test 5.0 1,260 -9-3 Shut-In Shut-In -9-4 30# Linear Displacement 30.0 8,332 9,001 214 214 1.00 0.80 30.00 2.00 0.25 0.159-5 30# Hybor G Establish Stable Fluid 30.0 8,400 6,631 158 158 2.00 1.00 0.80 30.00 2.00 0.25 0.159-6 30# Hybor G Pad 30.0 2,100 2,304 55 55 2.00 1.00 0.80 30.00 2.00 0.25 0.159-7 30# Hybor G Conditioning Pad 100M 0.50 30.0 9,450 9,696 231 237 4,725 5,732 2.00 1.00 0.80 30.00 2.00 0.25 0.159-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30.0 2,656 2,756 66 68 2,656 2,022 2.00 1.00 0.80 30.00 2.00 0.25 0.159-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30.0 2,739 2,727 65 71 5,478 5,313 2.00 1.00 0.80 30.00 2.00 0.25 0.159-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30.0 4,150 4,159 99 113 12,450 12,968 2.00 1.00 0.80 30.00 2.00 0.25 0.159-11 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30.0 4,565 4,569 109 129 18,260 18,817 2.00 1.00 0.75 30.00 2.00 0.25 0.159-12 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30.0 4,150 4,129 98 121 20,750 21,666 2.00 1.00 0.75 30.00 2.00 0.25 0.159-13 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30.0 3,901 6,689 159 197 23,406 35,397 2.00 1.00 0.75 30.00 2.00 0.25 0.159-14 30# Linear Flush 30.0 8,976 9,121 217 217 1.00 30.00 2.00 0.25 0.159-15 Shut-In Shut-In -449,216 600,998 14,309 14,835 468,915 494,123Design Total (gal)Actual Total (gal)Design Total (lbs)Calculated Total (lbs)Ticket Total (lbs)CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-6299,927 327,984 443,000 467,136 476,208(gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)126,189 254,334 25,915 26,987 39,000 Initial Design Material Volume 599.9 426.1 224.9 12,783.5 852.2 98.7 64.96,300 17,133 - - - Actual Design Material Volume 656.0 582.3 267.1 17,469.5 1,164.6 129.2 89.95,040 1,547 - - - Physical Material Volume Pumped 676 540 260.1 16897 1,100 135 123- - - - - Physical Material Volume Deviance 3% -7% -3% -3% -6% 4% 37%- -** IFS numbers for proppant are taken from software calculations based on multiple variablesMicroMotion Volume Pumped 653 571 262 16,897 1,155 146 94- -** Proppant is billed from Weight Ticket volumesMicroMotion Volume Deviance 0% -2% -2% -3% -1% 13% 5%- -Interval 6Kuparuk A Sand@ 14261.3 - 14264.08 ft 146.2 °FInterval 7Kuparuk A Sand@ 13907.6 - 13910.38 ft 146.2 °FInterval 8Kuparuk A Sand@ 13471.5 - 13474.28 ft 146.2 °FInterval 9Kuparuk A Sand@ 13034.4 - 13037.18 ft 146.1 °F----Fluid Type30# Hybor G30# LinearSeawaterCalcium Chloride -Proppant TypeWanli 20/40 Ceramic100M--Conoco Phillips - 3H-36 Actual Design 6
5/18/23 12:29
5/18/23 15:35
186 min
NA bpm
NA psi
NA psi
NA bbl
31.6 bpm
4,278 psi
5,871 psi
24.9 bpm
3,417 psi
3,376 psi
5,368 psi
2,084 hhp
206 psi
290 psi
4.14 ppg
28 cP
85.7 F
9.2
19,509 lbs
3,448 lbs
22,957 lbs
22,957 lbs
52,834 gal 1,258 bbls
17,177 gal 409 bbls
17,133 gal 408 bbls
1,547 gal 37 bbls
3,473 gal 83 bbls
5,079 gal 121 bbls
4,998 gal 119 bbls
8,193 gal 195 bbls
4,312 gal 103 bbls
11,687 gal 278 bbls
14,838 gal 353 bbls
28,305 gal 674 bbls
6,259 gal 149 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Flush Volume:
Interval Status:
Nate Brzezinski
James Campbell
Dustin Morrow
Greg Clayton
Alexander Bentz
Pump-In Volume:
100M Pumped:
Proppant in Formation:
30# Hybor G Volume:
30# Linear Volume:
Seawater Volume:
Dart/Ball Early :
Average pH:
Pump Time:
Average Missile HHP:
Initial BH Pressure (Breakdown):
Average BH Pressure:
Max Proppant Concentration:
Step Rate Test Volume:
Establish Stable Fluid Volume:
Pad Volume:
Conditioning Pad Volume:
Total Proppant Pumped* :
Calcium Chloride Volume:
Average Visc:
Average Temp:
Initial Rate (Breakdown):
Initial Surface Pressure (Breakdown):
Max Rate:
Max Surface Pressure:
Max BH Pressure:
Interval Summary
3H-36 - Kuparuk A Sand - Interval 1
Interval Summary
Start Date/Time:
End Date/Time:
Average Missile Pressure:
Initial OA Pressure:
Average Surface Pressure:
Average Rate:
Max OA Pressure:
Minifrac Volume:
Pumped and Completed to design. Additional fluid pumped to establish stable crosslink.
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Wanli 20/40 Ceramic Pumped:
Proppant Summary
Proppant Laden Fluid Volume:
Spacer and Dart Drop Volume:
Conoco Phillips - 3H-36 Interval Summary 7
5/18/23 15:35
5/18/23 16:43
68 min
15.1 bpm
4,797 psi
6,725 psi
14 bbl
29.9 bpm
6,905 psi
8,689 psi
23.5 bpm
4,017 psi
3,979 psi
5,980 psi
2,314 hhp
302 psi
405 psi
3.93 ppg
28 cP
84.7 F
9.3
22,410 lbs
1,622 lbs
24,032 lbs
24,032 lbs
22,551 gal 537 bbls
22,480 gal 535 bbls
2,543 gal 61 bbls
4,409 gal 105 bbls
10,176 gal 242 bbls
20,758 gal 494 bbls
1,722 gal 41 bbls
5,423 gal 129 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Average BH Pressure:
Average Missile HHP:
Initial OA Pressure:
Max OA Pressure:
Max Proppant Concentration:
Interval Summary
Start Date/Time:
End Date/Time:
Pump Time:
Initial Rate (Breakdown):
Initial Surface Pressure (Breakdown):
Initial BH Pressure (Breakdown):
Dart/Ball Early :
Max Rate:
Max Surface Pressure:
Max BH Pressure:
Average Rate:
Average Missile Pressure:
Average Surface Pressure:
Average Temp:
Average pH:
Proppant Summary
Average Visc:
3H-36 - Kuparuk A Sand - Interval 2
Wanli 20/40 Ceramic Pumped:
100M Pumped:
Total Proppant Pumped* :
30# Hybor G Volume:
30# Linear Volume:
Pad Volume:
Conditioning Pad Volume:
Proppant Laden Fluid Volume:
Displacement Volume:
Spacer and Dart Drop Volume:
Establish Stable Fluid Volume:
Proppant in Formation:
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Interval Status:
Dart not initially observed. Shut down to load second dart. Completed with no issues.
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.Greg Clayton
Alexander Bentz
Nate Brzezinski
James Campbell
Dustin Morrow
Conoco Phillips - 3H-36 Interval Summary 8
5/18/23 16:43
5/18/23 17:59
76 min
15.3 bpm
5,174 psi
7,049 psi
17 bbl
30.4 bpm
7,170 psi
8,944 psi
28.9 bpm
4,617 psi
4,574 psi
6,493 psi
3,265 hhp
405 psi
487 psi
3.98 ppg
27 cP
84.7 F
9.3
40,923 lbs
2,416 lbs
43,339 lbs
43,339 lbs
40,136 gal 956 bbls
28,414 gal 677 bbls
2,145 gal 51 bbls
5,744 gal 137 bbls
18,850 gal 449 bbls
26,958 gal 642 bbls
1,456 gal 35 bbls
13,397 gal 319 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Proppant Summary
Total Proppant Pumped* :
Proppant in Formation:
Fluid Summary (by fluid description)
Average Visc:
Wanli 20/40 Ceramic Pumped:
Establish Stable Fluid Volume:
Proppant Laden Fluid Volume:
Displacement Volume:
Spacer and Dart Drop Volume:
Initial OA Pressure:
Conditioning Pad Volume:
Interval Summary
Average Missile HHP:
Average Temp:
Average Missile Pressure:
Average Surface Pressure:
Average BH Pressure:
Average pH:
Max Proppant Concentration:
30# Linear Volume:
100M Pumped:
Max OA Pressure:
Initial Surface Pressure (Breakdown):
Start Date/Time:
Dustin Morrow
Greg Clayton
3H-36 - Kuparuk A Sand - Interval 3
End Date/Time:
Max BH Pressure:
Average Rate:
Initial BH Pressure (Breakdown):
Dart/Ball Early :
Max Rate:
Max Surface Pressure:
Pump Time:
Initial Rate (Breakdown):
Fluid Summary (by stage description)
Pad Volume:
30# Hybor G Volume:
Alexander Bentz
Nate Brzezinski
James Campbell
Interval Status:
Dart not initially observed. Shut down to load second dart. Completed with no issues.
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Conoco Phillips - 3H-36 Interval Summary 9
5/18/23 17:59
5/18/23 18:55
56 min
23.4 bpm
5,462 psi
7,180 psi
-17 bbl
31.4 bpm
5,462 psi
7,180 psi
28.2 bpm
4,084 psi
4,033 psi
6,002 psi
2,823 hhp
491 psi
498 psi
6.34 ppg
28 cP
84 F
9.3
4675 psi
0.786 psi/ft
4340 psi
4319 psi
4308 psi
57,653 lbs
2,564 lbs
60,217 lbs
60,217 lbs
27,236 gal 648 bbls
28,772 gal 685 bbls
2,366 gal 56 bbls
5,244 gal 125 bbls
15,957 gal 380 bbls
17,855 gal 425 bbls
10,917 gal 260 bbls
3,669 gal 87 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Proppant in Formation:
30# Linear Volume:
Initial Rate (Breakdown):
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Displacement Volume:
Establish Stable Fluid Volume:
Dart/Ball Early :
Max Rate:
Average Temp:
Average pH:
30# Hybor G Volume:
Conditioning Pad Volume:
Proppant Laden Fluid Volume:
3H-36 - Kuparuk A Sand - Interval 4
Interval Summary
Start Date/Time:
Initial Surface Pressure (Breakdown):
End Date/Time:
Average Rate:
Average Missile Pressure:
Average BH Pressure:
Average Missile HHP:
Final 10 min:
Final 15 min:
Max Surface Pressure:
Initial BH Pressure (Breakdown):
Pump Time:
Initial OA Pressure:
Max BH Pressure:
Proppant Summary
Wanli 20/40 Ceramic Pumped:
Total Proppant Pumped* :
Average Surface Pressure:
Final Fracture Gradient:
Final 5 min:
100M Pumped:
ISDP:
Max OA Pressure:
Max Proppant Concentration:
Average Visc:
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Flush Volume:
Interval Status:
Dart seat was questionable. Shut down to wait for CoP to make a decision on proceeding.
Continued stage and completed without issues.
James Campbell
Pad Volume:
Dustin Morrow
Greg Clayton
Alexander Bentz
Nate Brzezinski
Conoco Phillips - 3H-36 Interval Summary 10
5/19/23 9:44
5/19/23 10:34
50 min
15.3 bpm
4,326 psi
6,225 psi
9 bbl
30.6 bpm
3,141 psi
4,904 psi
25.8 bpm
2,668 psi
2,640 psi
4,618 psi
1,687 hhp
96 psi
394 psi
3.93 ppg
28 cP
95 F
9.2
32,584 lbs
1,908 lbs
34,492 lbs
34,492 lbs
26,776 gal 638 bbls
15,242 gal 363 bbls
2,899 gal 69 bbls
5,053 gal 120 bbls
14,827 gal 353 bbls
12,019 gal 286 bbls
3,223 gal 77 bbls
3,997 gal 95 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Average Temp:
Average pH:
Total Proppant Pumped* :
Initial Rate (Breakdown):
Spacer and Dart Drop Volume:
Initial Surface Pressure (Breakdown):
Max Rate:
Average Missile Pressure:
Max OA Pressure:
Initial BH Pressure (Breakdown):
Establish Stable Fluid Volume:
30# Hybor G Volume:
Displacement Volume:
Pump Time:
End Date/Time:
Max BH Pressure:
Average Surface Pressure:
Interval Status:
Shut down after seating dart to monitor pressure. Stage completed to design. No issues.
Dart/Ball Early :
Average Missile HHP:
Average Visc:
Max Surface Pressure:
Conditioning Pad Volume:
Proppant Laden Fluid Volume:
Greg Clayton
3H-36 - Kuparuk A Sand - Interval 5
Average BH Pressure:
Initial OA Pressure:
Max Proppant Concentration:
Start Date/Time:
Average Rate:
Proppant in Formation:
Alexander Bentz
Nate Brzezinski
James Campbell
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Dustin Morrow
Interval Summary
Proppant Summary
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Wanli 20/40 Ceramic Pumped:
Pad Volume:
30# Linear Volume:
100M Pumped:
Conoco Phillips - 3H-36 Interval Summary 11
5/19/23 10:34
5/19/23 13:47
193 min
15.4 bpm
3,651 psi
5,809 psi
11 bbl
30.8 bpm
8,062 psi
11,017 psi
15.3 bpm
4,140 psi
4,116 psi
6,277 psi
1,553 hhp
394 psi
585 psi
3.02 ppg
29 cP
93.8 F
9.3
57,590 lbs
1,957 lbs
59,547 lbs
59,547 lbs
44,821 gal 1,067 bbls
80,346 gal 1,913 bbls
48,277 gal 1,149 bbls
5,743 gal 137 bbls
5,150 gal 123 bbls
25,795 gal 614 bbls
30,440 gal 725 bbls
1,629 gal 39 bbls
8,133 gal 194 bbls
48,277 gal 1,149 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
30# Hybor G Volume:
Pad Volume:
Displacement Volume:
Spacer and Dart Drop Volume:
100M Pumped:
Average Visc:
Average Temp:
Total Proppant Pumped* :
Initial OA Pressure:
Dart/Ball Early :
Max Surface Pressure:
Max BH Pressure:
Proppant in Formation:
Average Missile HHP:
Pump Time:
Wanli 20/40 Ceramic Pumped:
Average BH Pressure:
End Date/Time:
Breakdown Volume:
Initial Rate (Breakdown):
Start Date/Time:
Initial Surface Pressure (Breakdown):
Initial BH Pressure (Breakdown):
30# Linear Volume:
Max Proppant Concentration:
Max OA Pressure:
Average Surface Pressure:
Conditioning Pad Volume:
Establish Stable Fluid Volume:
Breakdown Volume:
3H-36 - Kuparuk A Sand - Interval 6
Interval Summary
Average pH:
Proppant Summary
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Proppant Laden Fluid Volume:
Max Rate:
Average Missile Pressure:
Average Rate:
Interval Status:
Launched 3 darts. Pressured out on Pad. Pumped additional linear until 30 bpm was achieved.
Pump Schedule was modified per CSR.
Alexander Bentz
Nate Brzezinski
James Campbell
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Dustin Morrow
Greg Clayton
Conoco Phillips - 3H-36 Interval Summary 12
5/19/23 13:47
5/19/23 14:55
68 min
15.4 bpm
2,894 psi
5,138 psi
12 bbl
30.8 bpm
3,088 psi
4,690 psi
27.9 bpm
2,558 psi
2,515 psi
4,514 psi
1,749 hhp
568 psi
576 psi
7.17 ppg
28 cP
94.8 F
9.3
64,081 lbs
3,238 lbs
67,319 lbs
67,319 lbs
31,614 gal 753 bbls
22,670 gal 540 bbls
2,385 gal 57 bbls
7,510 gal 179 bbls
18,539 gal 441 bbls
20,784 gal 495 bbls
1,886 gal 45 bbls
3,180 gal 76 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Alexander Bentz
Nate Brzezinski
James Campbell
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Wanli 20/40 Ceramic Pumped:
Fluid Summary (by stage description)
Average Visc:
Spacer and Dart Drop Volume:
30# Linear Volume:
30# Hybor G Volume:
Pad Volume:
Conditioning Pad Volume:
Proppant Laden Fluid Volume:
Displacement Volume:
Max OA Pressure:
Average Missile HHP:
Average BH Pressure:
Average Surface Pressure:
Max Rate:
Initial BH Pressure (Breakdown):
Start Date/Time:
Establish Stable Fluid Volume:
Total Proppant Pumped* :
Proppant in Formation:
Interval Status:
Dart did not seat. Launched backup dart. Completed stage without issues.
Fluid Summary (by fluid description)
Initial OA Pressure:
Max Proppant Concentration:
Proppant Summary
100M Pumped:
Interval Summary
3H-36 - Kuparuk A Sand - Interval 7
End Date/Time:
Dart/Ball Early :
Average pH:
Max Surface Pressure:
Max BH Pressure:
Average Rate:
Average Missile Pressure:
Initial Rate (Breakdown):
Initial Surface Pressure (Breakdown):
Average Temp:
Pump Time:
Dustin Morrow
Greg Clayton
Conoco Phillips - 3H-36 Interval Summary 13
5/19/23 14:55
5/19/23 16:00
65 min
15.4 bpm
2,419 psi
4,728 psi
13 bbl
31.1 bpm
2,848 psi
4,657 psi
28.0 bpm
2,535 psi
2,491 psi
4,497 psi
1,740 hhp
557 psi
557 psi
6.04 ppg
26 cP
94.4 F
9.3
4356 psi
0.732 psi/ft
4208 psi
4182 psi
4170 psi
76,203 lbs
4,102 lbs
80,305 lbs
80,305 lbs
38,356 gal 913 bbls
21,111 gal 503 bbls
2,768 gal 66 bbls
8,760 gal 209 bbls
22,787 gal 543 bbls
11,877 gal 283 bbls
9,234 gal 220 bbls
4,041 gal 96 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Average Surface Pressure:
Conditioning Pad Volume:
30# Linear Volume:
Final 5 min:
Final 10 min:
Initial Rate (Breakdown):
Max Surface Pressure:
Max OA Pressure:
Average Visc:
Displacement Volume:
Max BH Pressure:
Dart/Ball Early :
Average Rate:
Max Proppant Concentration:
Interval Status:
Max Rate:
Initial Surface Pressure (Breakdown):
Start Date/Time:
Average pH:
End Date/Time:
Pump Time:
Average Missile HHP:
Proppant Laden Fluid Volume:
Initial BH Pressure (Breakdown):
Pad Volume:
Flush Volume:
Proppant in Formation:
Establish Stable Fluid Volume:
Initial OA Pressure:
Average Missile Pressure:
Stage Completed to design. No issues.Alexander Bentz
Nate Brzezinski
James Campbell
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Dustin Morrow
Greg Clayton
3H-36 - Kuparuk A Sand - Interval 8
Interval Summary
ISDP:
Final Fracture Gradient:
Final 15 min:
Proppant Summary
Wanli 20/40 Ceramic Pumped:
100M Pumped:
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Average Temp:
Total Proppant Pumped* :
Average BH Pressure:
30# Hybor G Volume:
Conoco Phillips - 3H-36 Interval Summary 14
5/20/23 8:29
5/20/23 9:36
67 min
15.4 bpm
4,295 psi
5,752 psi
3 bbl
31.0 bpm
3,027 psi
4,687 psi
27.7 bpm
2,582 psi
2,558 psi
4,523 psi
1,753 hhp
133 psi
436 psi
6.73 ppg
28 cP
93.3 F
9.3
4500 psi
0.758 psi/ft
4228 psi
4127 psi
4081 psi
96,183 lbs
5,732 lbs
101,915 lbs
101,915 lbs
43,660 gal 1,040 bbls
18,122 gal 431 bbls
2,304 gal 55 bbls
9,696 gal 231 bbls
25,029 gal 596 bbls
9,001 gal 214 bbls
9,121 gal 217 bbls
6,631 gal 158 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Dart/Ball Early :
Average Rate:
Average Missile Pressure:
Final Fracture Gradient:
100M Pumped:
Final 15 min:
Max Proppant Concentration:
Proppant in Formation:
Average Temp:
Final 5 min:
Average Missile HHP:
Initial OA Pressure:
Max Surface Pressure:
Max BH Pressure:
Initial Rate (Breakdown):
Max OA Pressure:
Average Surface Pressure:
Final 10 min:
Start Date/Time:
End Date/Time:
Pump Time:
Average BH Pressure:
Initial Surface Pressure (Breakdown):
Initial BH Pressure (Breakdown):
Establish Stable Fluid Volume:
James Campbell
3H-36 - Kuparuk A Sand - Interval 9
Flush Volume:
Pad Volume:
Conditioning Pad Volume:
Interval Status:
Stage completed with no issues. 20/40 Wanli was over-delivered by approximately 33,000 lbs.
Held 6 ppg stage until sand castle was empty. Approximately 12,000 lbs 100 Mesh left in the Sand
Castle due to change in job design by CoP Engineer.
Max Rate:
Total Proppant Pumped* :
Average Visc:
*Values for proppant are taken from software calculations based on multiple variables.
Proppant is billed off of weight ticket volumes and may vary slightly from this number.
Alexander Bentz
Nate Brzezinski
Dustin Morrow
Greg Clayton
Interval Summary
ISDP:
Proppant Summary
Wanli 20/40 Ceramic Pumped:
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Average pH:
Proppant Laden Fluid Volume:
Displacement Volume:
30# Hybor G Volume:
30# Linear Volume:
Conoco Phillips - 3H-36 Interval Summary 15
CustomerFormationLeaseAPIDateWell SummaryWanli 20/40 Ceramic 100M Total ProppantSurface Pressure Rate Visc Temp pH Surface Pressure Rate gal bbl gal bbl gal bbl gal bbl gal bbl lbs lbs lbs13376 24.9 28 85.7 9.2 4278 31.6 52,834 1,258 17,177 409 17,133 408 1,547 37 88,691 2,112 19,509 3,448 22,957 23979 23.5 28 85 9.3 6905 29.9 22,551 537 22,480 535 45,031 1,072 22,410 1,622 24,032 34574 28.9 27 85 9.3 7170 30.4 40,136 956 28,414 677 68,550 1,632 40,923 2,416 43,339 44033 28.2 28 84 9.3 5462 31.4 27,236 648 28,772 685 56,008 1,334 57,653 2,564 60,217 52640 25.8 28 95 9.2 3141 30.6 26,776 638 15,242 363 42,018 1,000 32,584 1,908 34,492 64116 15.3 29 94 9.3 8062 30.8 44,821 1,067 80,346 1,913 125,167 2,980 57,590 1,957 59,547 72515 27.9 28 95 9.3 3088 30.8 31,614 753 22,670 540 54,284 1,292 64,081 3,238 67,319 82491 28.0 26 94 9.3 2848 31.1 38,356 913 21,111 503 59,467 1,416 76,203 4,102 80,305 92558 27.7 28 93 9.3 3027 31.0 43,660 1,040 18,122 431 61,782 1,471 96,183 5,732 101,915 Minimum22551 537 15242 363 17133 408 1547 37 42018 1000 19509 1622 22957 Average36443 868 28259 673 17133 408 1547 37 66778 1590 51904 2999 54903 Maximum52834 1258 80346 1913 17133 408 1547 37 125167 2980 96183 5732 101915 Wanli 20/40 Ceramic 100M Total ProppantPressure Rate Visc Temp pH Pressure Rate gal bbl gal bbl gal bbl gal bbl gal bbl lbs lbs TotalPlanned299,927 7,141 126,189 3,004 6,300 150 5,040 120 437,456 10,416 443,000 25,915 468,915Recorded2524 19.2 21 68 6.96 8062 31.6 327,984 7,809 254,334 6,056 17,133 408 1,547 37 600,998 14,309 467,136 26,987 494,123Weight Tickets476,208 39,000 515,208** Proppant is billed from Weight Ticket volumesMay 17, 202350-103-208383H-36KuparukConoco Phillips IntervalAverage MaxSeawaterAverage MaxSeawater30# Hybor G 30# Linear30# Hybor G 30# LinearvariablesTotal FluidFluids ProppantsFluids ProppantsTotal FluidCalcium Chloride Calcium Chloride Conoco Phillips - 3H-36 Fluid System-Proppant Summary 16
Hydraulic Fracturing Fluid Product Component Information Disclosure
2023-05-18
Alaska
HARRISON BAY
50-103-20838
CONOCOPHILLIPS
3H 36
-150.0570
70.4115
NAD83
none
Oil
5963
599451
Hydraulic Fracturing Fluid Composition:
Trade Name Supplier Purpose Ingredients
Chemical
Abstract
Service
Number
(CAS #)
Maximum Ingredient
Concentration in
Additive (% by mass)**
Maximum
Ingredient
Concentration in
HF Fluid (% by
mass)**
Ingredient Mass
lbs Comments Company First Name Last Name Email Phone
SEAWATER (SG
8.52) Halliburton Base Fluid Water 7732-18-5 100.00%90.51114%5107323 Density = 8.52 Halliburton
BE-6(TM)
Bactericide Halliburton Microbiocide Listed Below Listed Below 0
CL-28M
CROSSLINKER Halliburton Crosslinker Listed Below Listed Below 0
LoSurf-300D Halliburton Non-ionic Surfactant Listed Below Listed Below 0
LVT-200
Baker
Hughes Additive Listed Below Listed Below 0 NA
MO-67 Halliburton pH Control Listed Below Listed Below 0
OPTIFLO-II
DELAYED
RELEASE
BREAKER Halliburton Breaker Listed Below Listed Below 0
OPTIFLO-III
DELAYED
RELEASE
BREAKER Halliburton Breaker Listed Below Listed Below 0
SP BREAKER Halliburton Breaker Listed Below Listed Below 0
WG-36 GELLING
AGENT Halliburton Gelling Agent Listed Below Listed Below 0
Ceramic
Proppant - Wanli Wanli Proppant Listed Below Listed Below 0 NA
SAND, COMMON
BROWN 100
MESH Halliburton Proppant Listed Below Listed Below 0 NA
Calcium Chloride Customer Salt Solution Listed Below Listed Below 0 NA
Ingredients
Listed
Above Listed Above 0.00%0.00000%0
1,2,4 Trimethylbenzene 95-63-6 1.00%0.00073%42
2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00159%90
2-Methyl-4-isothiazolin-3-one 2682-20-4 0.01%0.00001%1
5-Chloro-2-methyl-3(2H)-
Isothaiazolone 26172-55-4 0.01%0.00001%1
Ammonium persulfate 7727-54-0 100.00%0.02189%1235
Borate salts Proprietary 60.00%0.07612%4296
Denise Tuck,
Halliburton, 3000
N. Sam Houston
Pkwy E.,
Houston, TX
77032, 281-871-
6226 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
C.I. pigment Orange 5 3468-63-1 1.00%0.00002%2
Calcium Chloride 10043-52-4 100.00%0.00000%0
Calcium magnesium carbonate 16389-88-1 1.00%0.00127%72
Corundum 1302-74-5 65.00%5.48553%309536
Crystalline silica, quartz 14808-60-7 100.00%0.48447%27338
Distillates (petroleum),
hydrotreated light 64742-47-8 100.00%0.00000%0
Ethanol 64-17-5 60.00%0.04364%2463
Gluteraldehyde 111-30-8 1.00%0.00127%72
Guar gum 9000-30-0 100.00%0.29945%16897
Heavy aromatic petroleum
naphtha 64742-94-5 30.00%0.02182%1232
Inorganic mineral 1317-65-3 5.00%0.00634%358
Inorganic mineral Proprietary 1.00%0.00127%72 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Magensium chloride 7786-30-3 0.01%0.00001%1
Magnesium nitrate 10377-60-3 0.01%0.00001%1
Methanesulfonic acid, 1-hydroxy-,
sodium salt 870-72-4 0.10%0.00013%8
Mullite 1302-93-8 45.00%3.79768%214294
Naphthalene 91-20-3 5.00%0.00364%206
Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.02182%1232 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Oxyalkylated phenolic resin Proprietary 10.00%0.00727%411 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Oxylated phenolic resin Proprietary 30.00%0.00657%371 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Poly(oxy-1,2-ethanediyl), alpha-(4-
nonylphenyl)-omega-hydroxy-,
branched 127087-87-0 5.00%0.00364%206
Polymer Proprietary 1.00%0.00127%72 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Potassium chloride 7447-40-7 5.00%0.00634%358
Sodium bisulfate 7681-38-1 0.10%0.00013%8
Sodium chloride 7647-14-5 5.00%4.52604%255394
Sodium hydroxide 1310-73-2 30.00%0.01464%827
Sodium persulfate 7775-27-1 100.00%0.00000%0
Sodium sulfate 7757-82-6 0.10%0.00000%0
Water 7732-18-5 100.00%0.12492%7049
* Total Water Volume sources may include fresh water, produced water, and/or recycled water _
** Information is based on the maximum potential for concentration and thus the total may be over 100%
Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.Version web 1.3
All component information listed was obtained from the suppliers Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Anyquestions regarding the content of the MSDS should be directed to thesupplier
who provided it. The Occupational Safety and Health Administrations (OSHA) regulations govern the criteria for thedisclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for
how this informationis reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D.
Production Type:
True Vertical Depth (TVD):
Total Water Volume (gal)*:
MSDS and Non-MSDS Ingredients are listed below the green line
Well Name and Number:
Longitude:
Latitude:
Long/Lat Projection:
Indian/Federal:
Fracture Date
State:
County:
API Number:
Operator Name:
t >>ED W/η^ Zs/ KZ Zη&/ >ED ^ Zs/ ^Z/Wd/KE >/s Z> ^Z/Wd/KE ddzW d >K'' K>KZWZ/Ed^ Ɛ3H-36 50-103-20838-00-00 222-014 KRU MWD/LWD/DD VISION SERVICES FINAL FIELD 5-May-23 11ĞůŝǀĞƌLJZĞĐĞŝƉƚͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ yͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺWƌŝŶƚEĂŵĞ ^ŝŐŶĂƚƵƌĞ ĂƚĞWůĞĂƐĞƌĞƚƵƌŶǀŝĂĐŽƵƌŝĞƌŽƌƐŝŐŶͬƐĐĂŶĂŶĚĞŵĂŝůĂĐŽƉLJƚŽ^ĐŚůƵŵďĞƌŐĞƌ͘sdƵŽŶŐΛƐůď͘ĐŽŵ^>ƵĚŝƚŽƌͲĞůŝǀĞƌLJZĞĐĞŝƉƚƐŝŐŶĂƚƵƌĞĐŽŶĨŝƌŵƐƚŚĂƚĂƉĂĐŬĂŐĞ;ďŽdž͕ĞŶǀĞůŽƉĞ͕ĞƚĐ͘ͿŚĂƐďĞĞŶƌĞĐĞŝǀĞĚ͘dŚĞƉĂĐŬĂŐĞǁŝůůďĞŚĂŶĚůĞĚͬĚĞůŝǀĞƌĞĚƉĞƌƐƚĂŶĚĂƌĚĐŽŵƉĂŶLJƌĞĐĞƉƚŝŽŶƉƌŽĐĞĚƵƌĞƐ͘dŚĞƉĂĐŬĂŐĞΖƐĐŽŶƚĞŶƚƐŚĂǀĞŶŽƚďĞĞŶǀĞƌŝĨŝĞĚďƵƚƐŚŽƵůĚďĞĂƐƐƵŵĞĚƚŽĐŽŶƚĂŝŶƚŚĞĂďŽǀĞŶŽƚĞĚŵĞĚŝĂ͘η^ĐŚůƵŵďĞƌŐĞƌͲWƌŝǀĂƚĞPTD: 222-140 T37744Kayla JunkeDigitally signed by Kayla Junke Date: 2023.06.14 09:35:07 -08'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s):
GL: 36.2 BF:
Total Depth: 1633' FNL, 3183 FEL, Sec 33, T13N, R8E 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
20" L-80 119'
10-3/4" L-80 2971'
7-5/8" L-80 5926'
4-1/2" P-110S 5948'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
Lead: 244 bbls of 15.3ppg Class G
Tail: 50.0 bbls of 15.3ppg Class G
Stage 2: Tail: 181 bbls of 15.3ppg
Class G
Sr Res EngSr Pet GeoSr Pet Eng
50/64th
N/A
N/A
Oil-Bbl: Water-Bbl:
2908
12271'MD/5890'TVD
GR, RES, PWD, DIR, AZI, DEN, NEU, CALIPER, POR, SONIC
Water-Bbl:
PRODUCTION TEST
5/30/2023
Date of Test: Oil-Bbl:
7267281307
SIZE DEPTH SET (MD) PACKER SET (MD/TVD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
TUBING RECORD
12452'4.5"
6/2/2023 24
Flow Tubing
726
3634
4013634
Lift gas
Liner @ 12,443'MD/5917'TVD to 17,230'MD/5,948'TVD
2908
Gas-Oil Ratio:Choke Size:
Per 20 AAC 25.283 (i)(2) attach electronic information
45.5 39'
154.34 119'
39' 3201'
17230' 5917'
24"10 Yards
12604'
39'
Lead: 540bbls of 10.7ppg Class G
Tail: 57.8bbls of 15.8ppg Class G
13-1/2"
39'
12.6 12443'
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
Kuparuk River Field/ Kuparuk Oil Pool
N/A
BOTTOM
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
CASING WT. PER
FT.GRADE CEMENTING RECORD
50-103-20838-00-00
KRU 3H-36
931881000, 931882000. 931941000,
931884000
3/25/2023
17,235' MD/5948'TVD
N/A
75.3
P.O. Box 100360 Anchorage, AK 99510-0360
498656 6000206
4808 FNL, 5187 FEL, Sec 34, T13N, R8E
5/2/20231451' FNL, 4998' FEL, Sec 12, T12N, R8E
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
ConocoPhillips Alaska, Inc.
WAG
Gas
5/5/2023 222-014/323-286
6-1/2"
ADL 025524, ADL 025531, ADL 365501,
ADL 025532
29.7 36' 36' 11"
6007413
1897'MD/1881'TVD
SETTING DEPTH TVD
6010592
TOP HOLE SIZE AMOUNT
PULLED
492132
488853
TOP
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 10:46 am, Jun 06, 2023
Completed
5/5/2023
JSB
RBDMS JSB 060823
50 JSB
GDSR-6/21/23
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Surface Surface
1897 1881
12652 5929
17232 5947
(Kuparuk C)
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Shane McCraken
Digital Signature with Date:Contact Email:shane.m.mccracken@conocophillips.com
Contact Phone:907-265-6926
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
Top of Productive Interval
(Kuparuk C)
Authorized Title: Drilling Engineer
Direction Survey, Operations Summary, Cementing Summary, Well Schematic
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
Formation Name at TD:
TPI (Top of Producing Interval).
Authorized Name and
INSTRUCTIONS
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
NAME
Permafrost - Top
Permafrost - Base
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Page 1/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
3/19/2023
06:00
3/19/2023
09:30
3.50 MIRU, MOVE MOB P Transit sub, pits, and rockwasher to
CD2 ice pad and fuel trucks and
coldstarts on the sub and pit complex.
0.0 0.0
3/19/2023
09:30
3/19/2023
10:30
1.00 MIRU, MOVE MOB P Lay down uppper pipe skate section into
the pipeshed.
0.0 0.0
3/19/2023
10:30
3/19/2023
11:00
0.50 MIRU, MOVE MOB P Lay down the beaverslide. Stage into
the pipeshed.
0.0 0.0
3/19/2023
11:00
3/19/2023
11:30
0.50 MIRU, MOVE MOB P Clean out cellar box via super sucker. 0.0 0.0
3/19/2023
11:30
3/19/2023
16:00
4.50 MIRU, MOVE MOB P Break down choke, kill, and cement
lines on the sub. Break down pits/sub,
pits/pump interconnects. Blow down
steam on the sub. Place all mods on
John Deere cold start power. Electrician
unplug electrial connections. Raise all
exterior landings and secure for
transport. Work pre skid checklist.
0.0 0.0
3/19/2023
16:00
3/19/2023
17:00
1.00 MIRU, MOVE MOB P Place pipeshed on suspension, hook up
to sow, and spot on the ice pad. Simops
- install sub tow tongue.
0.0 0.0
3/19/2023
17:00
3/19/2023
17:30
0.50 MIRU, MOVE MOB P Place rockwasher onto a bed truck. 0.0 0.0
3/19/2023
17:30
3/19/2023
18:45
1.25 MIRU, MOVE MOB P Place motor complex onto suspension
and hook up to a sow. Stage at the
lower ice pad. Simops - shuffle mats.
0.0 0.0
3/19/2023
18:45
3/19/2023
19:45
1.00 MIRU, MOVE MOB P Place pump complex on suspension and
hook up to a sow. Stage at lower ice
pad. Simops - contiune to shuffle mats.
0.0 0.0
3/19/2023
19:45
3/19/2023
20:00
0.25 MIRU, MOVE MOB P Place pit complex on suspension and
hook up to a sow. Stage at lower ice
pad.
0.0 0.0
3/19/2023
20:00
3/19/2023
20:30
0.50 MIRU, MOVE MOB P PJSM, skid the rig floor. 0.0 0.0
3/19/2023
20:30
3/19/2023
21:00
0.50 MIRU, MOVE MOB P Raise and secure stompers. 0.0 0.0
3/19/2023
21:00
3/19/2023
21:30
0.50 MIRU, MOVE MOB P Hook sow to sub and set on suspension. 0.0 0.0
3/19/2023
21:30
3/20/2023
00:00
2.50 MIRU, MOVE MOB P Pull sub off of well CD3-128. Hook up
grader to sub.
0.0 0.0
3/20/2023
00:00
3/20/2023
01:00
1.00 MIRU, MOVE MOB P Hook up trucks to pump, power, and
pipeshed modules.
0.0 0.0
3/20/2023
01:00
3/20/2023
07:00
6.00 MIRU, MOVE MOB P Transport sub, pits, rockwasher to the
Colville River ice bridge.
0.0 0.0
3/20/2023
07:00
3/20/2023
07:30
0.50 MIRU, MOVE MOB P Transport sub, pits, rockwasher across
the Colville River ice bridge.
0.0 0.0
3/20/2023
07:30
3/20/2023
09:30
2.00 MIRU, MOVE MOB T Sow pulling pits had axle seal go out.
Wait on NES round trip to CD3 to
replace sow.
0.0 0.0
3/20/2023
09:30
3/20/2023
16:00
6.50 MIRU, MOVE MOB P Continue to transport sub, pits,
rockwasher from Colvillle River ice
bridge to 2L.
0.0 0.0
3/20/2023
16:00
3/20/2023
18:00
2.00 MIRU, MOVE MOB P Fuel trucks, sub, and pits. Transport
back to CD3 from 2L.
0.0 0.0
3/20/2023
18:00
3/20/2023
19:15
1.25 MIRU, MOVE MOB P Transport pump, power, and pipeshed to
CD2 ice pad.
0.0 0.0
3/20/2023
19:15
3/20/2023
21:00
1.75 MIRU, MOVE MOB P Hook up cats to each module and
transport onto the CD2 access road
leaving the ice road to CD3.
0.0 0.0
3/20/2023
21:00
3/20/2023
22:00
1.00 MIRU, MOVE MOB P Transport pump, power, and pipeshed to
re-supply ice road at CD4 access road.
0.0 0.0
3/20/2023
22:00
3/21/2023
00:00
2.00 MIRU, MOVE MOB P Transport pump, power, and pipeshed
on the re-supply ice road at CD4 access
road to the Colville River ice bridge.
0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 2/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
3/21/2023
00:00
3/21/2023
05:30
5.50 MIRU, MOVE MOB P Transport pump, power, and pipeshed
from the Colville River ice bridge to 2L.
0.0 0.0
3/21/2023
05:30
3/21/2023
07:00
1.50 MIRU, MOVE MOB P Fuel all mods and trucks. Complete
crew change out.
0.0 0.0
3/21/2023
07:00
3/21/2023
18:30
11.50 MIRU, MOVE MOB P Transport the sub, pipeshed, and
rockwasher from 2L to 3H.
0.0 0.0
3/21/2023
18:30
3/21/2023
20:45
2.25 MIRU, MOVE MOB P Stage pipeshed, sub, and rockwasher
on pad. Remove grader from sub.
Lower all mods off suspension and
unhook sows.
0.0 0.0
3/21/2023
20:45
3/21/2023
23:00
2.25 MIRU, MOVE MOB P Travel back to 2L. Fuel all complex's
and trucks. Hook up to the pits, pump,
and power complex's.
0.0 0.0
3/21/2023
23:00
3/22/2023
00:00
1.00 MIRU, MOVE MOB P Begin to transport the pits, pump, and
power complex's from 2L to 3H.
0.0 0.0
3/22/2023
00:00
3/22/2023
05:00
5.00 MIRU, MOVE MOB P Continue to transport the pits, pump,
and power modules to 3H.
0.0 0.0
3/22/2023
05:00
3/22/2023
07:00
2.00 MIRU, MOVE MOB P Turn pits, pump, and power modules
around and stage for spotting.
0.0 0.0
3/22/2023
07:00
3/22/2023
14:30
7.50 MIRU, MOVE NUND P Nipple up surface annular, knife valve,
diverter "t", and 16" diverter pipe.
0.0 0.0
3/22/2023
14:30
3/22/2023
15:30
1.00 MIRU, MOVE MOB P Set stomper mats and lay herculite. 0.0 0.0
3/22/2023
15:30
3/22/2023
17:30
2.00 MIRU, MOVE MOB P Hook up sow to sub and pull forward for
mat placement. Set mats.
0.0 0.0
3/22/2023
17:30
3/22/2023
19:00
1.50 MIRU, MOVE MOB P Stage production tree, tree adaptor, and
surface riser in the cellar.
0.0 0.0
3/22/2023
19:00
3/22/2023
20:00
1.00 MIRU, MOVE MOB P Spot the sub. 0.0 0.0
3/22/2023
20:00
3/22/2023
20:30
0.50 MIRU, MOVE MOB P Set stompers. 0.0 0.0
3/22/2023
20:30
3/22/2023
21:30
1.00 MIRU, MOVE MOB P Skid rig floor. Simops - remove sub tow
tongue.
0.0 0.0
3/22/2023
21:30
3/22/2023
23:00
1.50 MIRU, MOVE MOB P Lower rear cellar wind wall. Extend out
side cellar walls. Secure herculite
around cellar. Simops - place rig mats
for power and pipeshed modules.
0.0 0.0
3/22/2023
23:00
3/22/2023
23:45
0.75 MIRU, MOVE MOB P Spot pits module. 0.0 0.0
3/22/2023
23:45
3/23/2023
00:00
0.25 MIRU, MOVE MOB P Spot pump module. 0.0 0.0
3/23/2023
00:00
3/23/2023
00:30
0.50 MIRU, MOVE MOB P Continue to spot pump module and take
off suspension.
0.0 0.0
3/23/2023
00:30
3/23/2023
01:15
0.75 MIRU, MOVE MOB P Spot motor module and take off
suspension.
0.0 0.0
3/23/2023
01:15
3/23/2023
02:00
0.75 MIRU, MOVE MOB P Spot pipeshed module and take off
suspension.
0.0 0.0
3/23/2023
02:00
3/23/2023
02:30
0.50 MIRU, MOVE MOB P Spot rockwasher. Simops - begin
hooking up plumbing at interconnects.
0.0 0.0
3/23/2023
02:30
3/23/2023
06:00
3.50 MIRU, MOVE RURD P Hook up plumbing and electrical
connections at all interconnects.
0.0 0.0
3/23/2023
06:00
3/23/2023
13:00
7.00 MIRU, MOVE RURD P Continue to hook up plumbing and
electrical connections at interconnects.
Bring on steam to pits and the sub.
Secure landings around the rig. Secure
cellar. Work on rig acceptance
checklist. Lay herculite, install cuttings
tank, and berm.
0.0 0.0
3/23/2023
13:00
3/23/2023
14:15
1.25 MIRU, MOVE RURD P Install beaver slide. 0.0 0.0
3/23/2023
14:15
3/23/2023
15:00
0.75 MIRU, MOVE RURD P Install upper skate rail. 0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 3/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
3/23/2023
15:00
3/23/2023
18:00
3.00 MIRU, MOVE RURD P Continue to work on rig acceptance
checklist. Install conductor valves. Plug
all snails on pumps. Check pump line
ups and pit line ups. String up and
operate the pipe skate. Clean and clear
areas from the rig move. Accept rig at
18:00 hrs.
0.0 0.0
3/23/2023
18:00
3/24/2023
00:00
6.00 MIRU, MOVE RURD P Bring on water to the rig. Change out
saver sub to NC-50. Recieve 5" dp and
SLB directional tools. Housekeeping
around the rig. Clean and install mud
pump screens.
0.0 0.0
3/24/2023
00:00
3/24/2023
06:00
6.00 MIRU, MOVE RURD P Install surface risers. Install 90'
mousehole extension. Prep for
upcoming oil chage on the 3512 cat
engine. Put away shaker screens.
Continue to offload 5" DP as it arrives.
Continue with rig housekeeping.
0.0 0.0
3/24/2023
06:00
3/24/2023
12:00
6.00 MIRU, MOVE RURD P Torque up bolts on the starting head and
tee flange. Housekeeping in the
pipeshed. Remove standard mousehole
and test jts used on the RWO program.
Service rig loader. Welder install new
greyloc hub on kill line. Load/strap 5"
HWDP/DP. Complete mp-2 on koomey.
0.0 0.0
3/24/2023
12:00
3/24/2023
18:00
6.00 MIRU, MOVE RURD P Continue with the install of the kill line
greyloc hub. Load short side of the
pipeshed with 5" DP and 5" HWDP.
Check koomey bottles on the TD.
Continue to clean/organize the rig and
pad. Rig up the annular and knife valve
koomey lines. Charge koomey.
0.0 0.0
3/24/2023
18:00
3/25/2023
00:00
6.00 MIRU, MOVE RURD P Finish secondary tie wire on top drive
accumulator bottles. Pick up NC50 floor
valves, dart, and head pin. Mentor new
hands arriving on 142. Load SLB tools
into the pipeshed.
0.0 0.0
3/25/2023
00:00
3/25/2023
06:00
6.00 MIRU, MOVE RURD P Perform pre-spud derrick inspection.
Construct a level working platform in the
cellar. Transfer fluid around in pits to
check pumps, gunlines, and hoper lines.
Dress ST-100 with 5" dies. Make up
stand of 5" hwdp and store in the
mousehole for diverter test. Pick up
short BHA tools via the beaverslide.
0.0 0.0
3/25/2023
06:00
3/25/2023
07:30
1.50 MIRU, MOVE PULD P Rack back std of hwdp in mouse hole.
Continue to build 5 additional std's of
hwdp and rack back.
0.0 0.0
3/25/2023
07:30
3/25/2023
09:30
2.00 MIRU, MOVE PULD P Make up 1 std of 5" dp to be used for
diverter test. Simops - offload spud mud
to pits. Load shortside of the pipeshed
with 5" dp.
0.0 0.0
3/25/2023
09:30
3/25/2023
10:30
1.00 MIRU, MOVE BOPE P Perform diverter test and koomey draw
down test - accumulator psi - 3000, after
function - 1950 psi, 8 seconds for 200
psi build up with 2 electric pumps. 47
seconds for full system build with 2
electric pumps and 2 air pumps.
Nitrogen backup bottles ave. - 2000 psi.
Annular closing time - 19 seconds, knife
valve opening time - 3 sec. Test pvt
gain/loss and flow out alarms, test LEL
and H2S alarms. Tests witnessed by
AOGCC rep Adam Earl.
0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 4/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
3/25/2023
10:30
3/25/2023
11:30
1.00 MIRU, MOVE RURD P Pick up 5" handling equipment and
change out master bushings. Simops -
offload 2nd load of spud mud into the
pits.
0.0 0.0
3/25/2023
11:30
3/25/2023
12:00
0.50 MIRU, MOVE SFTY P Pre-spud meeting with all hands. 0.0 0.0
3/25/2023
12:00
3/25/2023
13:30
1.50 MIRU, MOVE SEQP P Make up std of 5" dp. Flood lines and
conductor. Pressue test surface lines to
4,000 psi. (good)
0.0 0.0
3/25/2023
13:30
3/25/2023
16:15
2.75 MIRU, MOVE BHAH P PJSM, Make up 13½" surface BHA as
per dd to 42' md.
0.0 42.0
3/25/2023
16:15
3/25/2023
17:15
1.00 MIRU, MOVE DRLG P Drill out conductor from 42' md to 159'
md with 360 gpm, 480 psi, 30 rpm, 3k
tq, 4k wob.
42.0 159.0
3/25/2023
17:15
3/25/2023
18:00
0.75 SURFAC, DRILL DDRL P Drill 13½" surface hole from 159' md to
224' md with 400 gpm, 400 psi, 40% f/o,
40 rpm, 3k tq, 3k wob. Up wt 50k, s/o
wt - 50k, rot wt - 57k
159.0 224.0
3/25/2023
18:00
3/25/2023
20:00
2.00 SURFAC, DRILL PMPO P Pump out of the hole from 224' md to
40' md with 212 gpm, 107 psi, 25% f/o,
50k up wt.
224.0 40.0
3/25/2023
20:00
3/26/2023
00:00
4.00 SURFAC, DRILL BHAH P Make up remaining 13½ surface bha as
per slb dd to 189' md, s/o wt - 60k
40.0 189.0
3/26/2023
00:00
3/26/2023
00:30
0.50 SURFAC, DRILL DHEQ P RIH from 189' MD to 224' MD. Kelly up
and test mwd with 480 gpm, 640 psi,
44% f/o. (good)
189.0 224.0
3/26/2023
00:30
3/26/2023
02:30
2.00 SURFAC, DRILL DDRL P Drill 13½" surface hole from 250' MD to
350' MD with 480 gpm, 740 psi, 45% f/o,
10.48 ecd, 30 rpm, 3k tq, 3k wob. Up wt
78k, s/o wt - 70k, rot wt - 75k
224.0 350.0
3/26/2023
02:30
3/26/2023
03:00
0.50 SURFAC, DRILL SVRG P Service/troubleshoot drag chain.
Remove cuttings from drag chain. -
Simops POOH to 158' MD, up wt - 67k
350.0 158.0
3/26/2023
03:00
3/26/2023
04:00
1.00 SURFAC, DRILL RGRP T Remove overloaded cuttings from drag
chain. Reset electrical drive motor.
Simops - rih from 158' MD to 350' MD.
158.0 350.0
3/26/2023
04:00
3/26/2023
12:00
8.00 SURFAC, DRILL DDRL P Drill 13½" surface hole from 350' MD to
847' MD 844' tvd, with 480 gpm, 980
psi, 55% f/o, 10.73 ecd, 50 rpm, 3k tq,
4k wob. Up wt 84k, s/o wt - 90k, rot wt -
85k
350.0 847.0
3/26/2023
12:00
3/26/2023
18:00
6.00 SURFAC, DRILL DDRL P Drill 13½" surface hole from 847' MD to
1,218' MD, 1,211' tvd, with 480 gpm,
1115 psi, 50% f/o, 10.85 ecd, 50 rpm, 4k
tq, 7k wob. Up wt 88k, s/o wt - 93k, rot
wt - 88k
847.0 1,218.0
3/26/2023
18:00
3/27/2023
00:00
6.00 SURFAC, DRILL DDRL P Drill 13½" surface hole from 1,218' MD
to 1,596' MD, 1,589' tvd, with 420 gpm,
873 psi, 42% f/o, 9.96 ecd, 50 rpm, 5k
tq, 10k wob. Up wt 99k, s/o wt - 100k,
rot wt - 99k
1,218.0 1,596.0
3/27/2023
00:00
3/27/2023
11:30
11.50 SURFAC, DRILL DDRL P Drill 13½" surface hole from 1,596 MD
to 2,220' MD, 2,176' tvd, with 480 gpm,
1125 psi, 48% f/o, 10.05 ecd, 50 rpm, 5k
tq, 5k wob. Up wt 112k, s/o wt - 105k,
rot wt - 104k. Pump LCM pill at 1,857'
MD and 2,097' MD (10 ppb ea nut plug,
Mix II medium, Mix II fine)
1,596.0 2,261.0
3/27/2023
11:30
3/27/2023
17:30
6.00 SURFAC, DRILL CLEN T Observe Ugnu formation returns at
surface blinding off shaker screens.
Attempt to mitigate with large mesh size
screens (failed). Mitigate fluid loss over
the shakers by pumping mud back from
the rock.
2,261.0 2,261.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 5/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
3/27/2023
17:30
3/28/2023
00:00
6.50 SURFAC, DRILL CLEN T Shut down pumps. Converse with rig
team in town and develop plan forward.
Clean rock washer and pits. Dress all
shakers with 60 mesh screens and treat
with ScreenKleen®. Build 40 bbls
DeepClean® pill. Order 870 bbls of
9.3ppg, 150 vis, 2% ScreenKleen® spud
mud. Build surface volume in the pits to
same recipe. Order 580 bbls 9.3ppg,
250 vis, 2% DrilZone®, 1%
ScreenKleen® to add to system once
we pass the Ugnu.
2,261.0 2,261.0
3/28/2023
00:00
3/28/2023
10:00
10.00 SURFAC, DRILL CLEN T While waiting on arrival of 870 bbls of
9.3ppg, 150 vis, 2% screenkleen® spud
mud, continue to clean rock washer and
pits. Stock pits with dry product.
Complete BWM on BOPE.
2,261.0 2,261.0
3/28/2023
10:00
3/28/2023
13:15
3.25 SURFAC, DRILL DDRL P Drill 13½" surface hole from 2,261' MD
to 2,440' MD, 2,348' tvd, with 450 gpm,
1250 psi, 43% f/o, 10.60 ecd, 50 rpm, 6k
tq, 8k wob. Up wt 127k, s/o wt - 115k,
rot wt - 111k. Pump 35 bbl deepkleen®
pill.
2,261.0 2,440.0
3/28/2023
13:15
3/28/2023
14:00
0.75 SURFAC, DRILL CLEN T Suspend drilling to clean shaker
screens, due to Ugnu formation.
Offload rock washer and cuttings box.
Take on new spud mud to the pits.
2,440.0 2,440.0
3/28/2023
14:00
3/28/2023
15:00
1.00 SURFAC, DRILL DDRL P Drill 13½" surface hole from 2,440' MD
to 2,540' MD, 2,489' tvd, with 450 gpm,
1266 psi, 43% f/o, 10.66 ecd, 50 rpm, 6k
tq, 8k wob. Up wt 117k, s/o wt - 112k,
rot wt - 111k.
2,440.0 2,540.0
3/28/2023
15:00
3/28/2023
16:45
1.75 SURFAC, DRILL CLEN T Suspend drilling to clean shaker
screens, due to Ugnu formation.
Offload rock washer and cuttings box.
Take on new spud mud to the pits.
2,540.0 2,540.0
3/28/2023
16:45
3/29/2023
00:00
7.25 SURFAC, DRILL DDRL P Drill 13½" surface hole from 2,540' MD
to 2,918' MD, 2,765' tvd, with 465 gpm,
1435 psi, 43% f/o, 10.45 ecd, 50 rpm, 8k
tq,218k wob. Up wt 131k, s/o wt - 114k,
rot wt - 111k. Increases mud wt to 9.5
@ 2,825' MD.
2,540.0 2,918.0
3/29/2023
00:00
3/29/2023
05:30
5.50 SURFAC, DRILL DDRL P Drill 13½" surface hole from 2,918' MD
to 3,205' MD, 2,975' tvd, with 500 gpm,
1741 psi, 43% f/o, 11.11 ecd, 50 rpm, 7k
tq, 23k wob. Up wt 127k, s/o wt - 117k,
rot wt - 120k. Increased mud wt to 9.6
@ 2,825' MD.
2,918.0 3,205.0
3/29/2023
05:30
3/29/2023
06:00
0.50 SURFAC, CASING SRVY P Obtain final survey, and tq/drag values.
Up wt - 127k, s/o wt - 117k, rot wt - 120k
w/ 6k tq.
3,205.0 3,205.0
3/29/2023
06:00
3/29/2023
07:00
1.00 SURFAC, CASING BKRM P Circulate 1 b/u while reaming stand up
from 3,205' md to 3,110' MD w/ 500
gpm, 1525 psi, 40 rpm, 5.5k tq, 10.89
ecd. Simops - pump 40 bbl nut plug
sweep s/s at same rate.
3,205.0 3,110.0
3/29/2023
07:00
3/29/2023
07:15
0.25 SURFAC, CASING OWFF P OWFF (static) 3,110.0 3,110.0
3/29/2023
07:15
3/29/2023
17:30
10.25 SURFAC, CASING BKRM P BROOH f/ 3,110' md to 1,700' md w/
625 gpm, icp - 1700, fcp - 1660, 49%
f/o, 40 rpm, 4k tq, ecd - 10.45. Up wt
while rot - 107k
3,110.0 1,700.0
3/29/2023
17:30
3/29/2023
21:30
4.00 SURFAC, CASING PMPO P Pump out of the hole f/ 1,700' MD to
752' md w/ 100 gpm, 175 psi, 18% f/o.
Up wt while pulling - 100k.
1,700.0 752.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 6/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
3/29/2023
21:30
3/29/2023
21:45
0.25 SURFAC, CASING OWFF P B/D TD and OWFF (static) 752.0 752.0
3/29/2023
21:45
3/29/2023
23:00
1.25 SURFAC, CASING TRIP P Continue to pooh on elevators f/ 752'
md to 189' md racking back 5" hwdp
and jar stand. Monitor disp via trip tank.
752.0 189.0
3/29/2023
23:00
3/30/2023
00:00
1.00 SURFAC, CASING BHAH P L/D surface BHA f/ 189' to 75' md as per
SLB dd. Monitor disp via trip tank.
189.0 75.0
3/30/2023
00:00
3/30/2023
01:45
1.75 SURFAC, CASING BHAH P Cont. T/ L/D BHA as Per SLB REP.
Monitor Disp Via Pit #1.
75.0 0.0
3/30/2023
01:45
3/30/2023
03:00
1.25 SURFAC, CASING BHAH P Clean/Clear Rig Floor, L/D BHA tools
Via Beaver slide, P/U casing tools Via
Beaver slide.
0.0 0.0
3/30/2023
03:00
3/30/2023
04:00
1.00 SURFAC, CASING RURD P R/U Volant Tool and Doyon casing
handling equipment, SIMOPS clean
suctions manifolds and suction pots on
#1 and #2 mud pumps.
0.0 0.0
3/30/2023
04:00
3/30/2023
05:00
1.00 SURFAC, CASING RURD P P/U Landing Jt. M/U Hanger, Drain
stack, Perform Dummy run w/ Hanger
as Per Cameron hand.
0.0 0.0
3/30/2023
05:00
3/30/2023
05:30
0.50 SURFAC, CASING RURD P M/U Swedge for FOSV, Install spider
slips, M/U strap tongs. Refill hole post
Dummy run w/ hanger.
0.0 0.0
3/30/2023
05:30
3/30/2023
06:15
0.75 SURFAC, CASING RURD P Cont. R/U t/ Run 10 3/4" Surface
Casing. Install air manifold t/ 350T
spider slips
0.0 0.0
3/30/2023
06:15
3/30/2023
07:45
1.50 SURFAC, CASING PUTB P M/U 10 3/4" 45# L-80 Baker Lok Shoe
track Joint 1-4. Pump to verify floats are
clear and holding @ 3.5 BPM 40 psi
Cont. RIH t/ 270'MD.
0.0 270.0
3/30/2023
07:45
3/30/2023
12:00
4.25 SURFAC, CASING WASH T Started Taking weight @ 270', Begin
Washing and Reaming w/ CRT Volant
F/270' MD, T/470' MD 4BPM, 95 PSI,
6RPM, 3K TQ.
270.0 470.0
3/30/2023
12:00
3/30/2023
14:30
2.50 SURFAC, CASING WASH T Cont. Washing/Reaming @ 470' MD
With No Forward Progress @ 4 BPM 90
psi.
470.0 470.0
3/30/2023
14:30
3/30/2023
17:30
3.00 SURFAC, CASING PULD T Decision made to POOH L/D 10 3/4"
45# L-80 Hyd563 csg F/ 470' MD to 127'
MD @ 1.5 BPM 60 PSI P/U 55K
470.0 127.0
3/30/2023
17:30
3/30/2023
19:30
2.00 SURFAC, CASING PULD T Attempt to back out Bakerlok Jts with
Strap tongs and Volant with no success,
Cut and L/D BakerLok joints f/ 127' MD
to Surface. P/U 47K Inspected shoe,
Found nose piece of shoe was missing
and left in hole.
127.0 0.0
3/30/2023
19:30
3/30/2023
22:00
2.50 SURFAC, CASING RURD T Clean/Clear Rig Floor, R/D Volant tool
and Casing Equipment. Stage BHA #2
to Rig Floor PJSM
0.0 0.0
3/30/2023
22:00
3/31/2023
00:00
2.00 SURFAC, CASING BHAH T Make up BHA as Per SLB REPS F/
Surface to 118' S/O 65K
0.0 118.0
3/31/2023
00:00
3/31/2023
00:45
0.75 SURFAC, CASING BHAH T Make up BHA as Per SLB REPS F/
Surface to 118' t/ 190' S/O 72K
118.0 190.0
3/31/2023
00:45
3/31/2023
01:15
0.50 SURFAC, CASING TRIP T TIH F/ 190‘ MD - T/ 480‘ MD, W/ 5”
HWDP, From derrick, Monitor Disp. On
Pit #5 S/O WT= 78K
190.0 480.0
3/31/2023
01:15
3/31/2023
04:15
3.00 SURFAC, CASING REAM T Tag 20K @ 480' MD, Kelly up,
Wash/Ream F/ 480' MD T/ 1,125' MD,
@ 100 GPM, 15 RPM, 18% F/O, 2K
WOB, 2-3K TQ, S/O WT=90K
480.0 1,125.0
3/31/2023
04:15
3/31/2023
05:30
1.25 SURFAC, CASING TRIP T TIH on Elevators F/ 1125' T/ 1700' MD,
W/ 5" DP F/ Derrick S/O 91K Monitor
disp. Pit #5
1,125.0 1,700.0
3/31/2023
05:30
3/31/2023
07:15
1.75 SURFAC, CASING TRIP T Cont. RIH on Elevators F/1,700' T/
3,200'. SOW=104K, PUW=117K.
1,700.0 3,200.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 7/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
3/31/2023
07:15
3/31/2023
12:00
4.75 SURFAC, CASING CIRC T Circ/Cond Mud Stage Up Pumps T/600
GPM, 2100PSI, 60RPM, 4.5K TQ.
RT=126K. Pumped 30BBL 9.6PPG Nut
Plug Pill. Followed by 290BBL Dilution .
3,200.0 3,200.0
3/31/2023
12:00
3/31/2023
18:00
6.00 SURFAC, CASING BKRM T BROOH F/ 3,200‘ MD - T/ 1,500‘ MD,
W/ GPM = 450, PSI = 1013, RPM = 60,
TQ = 5K. F/O = 43%, ECD = 9.95PPG,
P/U RT WT = 94K,
3,200.0 1,500.0
3/31/2023
18:00
4/1/2023
00:00
6.00 SURFAC, CASING BKRM T From/ 1500' T/ 190' BROOH W/ 450
GPM , 750 PSI , 60-40 RPM , 5-2K TQ,
(F/ 282' T/ 189' Pump 30 BBL Nut Plug
Sweep , W/ 450 GPM , 750 PSI , 40
RPM , 2-4K TQ.) 20% Incr. in Cuttings.
1,500.0 190.0
4/1/2023
00:00
4/1/2023
00:15
0.25 SURFAC, CASING OWFF T @ 190' MD OWFF F/ 165 Min Well
Static, PJSM L/D BHA #2.
190.0 190.0
4/1/2023
00:15
4/1/2023
03:00
2.75 SURFAC, CASING BHAH T F/ 190' MD L/D BHA #2 as per SLB DD. 190.0 0.0
4/1/2023
03:00
4/1/2023
06:00
3.00 SURFAC, CASING CLEN T Clean/Clear rig floor to run 10 3/4"
casing.
0.0 0.0
4/1/2023
06:00
4/1/2023
08:30
2.50 SURFAC, CASING PUTB T P/U/ M/U and Baker lok First 4 jts of 10
3/4" casing( Shoe Jt, Float Collar and 2
Jts, as per Doyon and COP casing
program Run 10-3/4" casing to 470'
0.0 470.0
4/1/2023
08:30
4/1/2023
12:00
3.50 SURFAC, CASING PUTB P RIH w/ 10 3/4" casing F/ 470'' MD T/
1288' MD Filling Via Volant tool, Monitor
displacement at pit #5 S/O 80K
470.0 1,288.0
4/1/2023
12:00
4/1/2023
13:45
1.75 SURFAC, CASING PUTB P RIH w/ 10 3/4" casing F/ 1288' MD T/
1803' MD filling w/ Volant tool,
Monitoring Displacement at pit #5.
1,288.0 1,803.0
4/1/2023
13:45
4/1/2023
14:30
0.75 SURFAC, CASING CIRC P Circulate, Recip F/ 1803' MD T/ 1763'
MD W/ 330 GPM, 169 PSI, P/U 125K
S/O 90K.
1,803.0 1,763.0
4/1/2023
14:30
4/1/2023
17:30
3.00 SURFAC, CASING PUTB P RIH W/ 10 3/4" casing F/ 1803' MD T/
2759' MD filling w/ volant tool,
Monitoring Dispalcement @ pit #5 S/O
104K.
1,803.0 2,759.0
4/1/2023
17:30
4/1/2023
19:00
1.50 SURFAC, CASING PUTB P F/ 2759' MD T/ 3161' MD RIH w/ 10 3/4"
Casing P/U 175K S/O 118K.
2,759.0 3,161.0
4/1/2023
19:00
4/1/2023
19:15
0.25 SURFAC, CASING PUTB P F/ 3161' MD T/ 3200' MD M/U Hanger
and Landing Jt. as per Cameron hand
and land out 3200' MD.
3,161.0 3,200.0
4/1/2023
19:15
4/2/2023
00:00
4.75 SURFAC, CEMENT CIRC P Circulate and Condition mud for surface
cement. Stage rate up to 8 BPM, 136
PSI.
3,200.0 3,175.0
4/2/2023
00:00
4/2/2023
00:30
0.50 SURFAC, CEMENT CIRC P Circulate and condition mud for surface
cement w/7.5 bpm / 150 psi. PU wt 185
k, SO wt 122 k. Reciprocate pipe 10'
3,200.0 3,200.0
4/2/2023
00:30
4/2/2023
01:00
0.50 SURFAC, CEMENT RURD P OWFF (static) B/D top drive. R/U for
cementing. Line up thru cement hose.
3,200.0 3,200.0
4/2/2023
01:00
4/2/2023
02:45
1.75 SURFAC, CEMENT CIRC P Circulate and condition thru cement
hose w/8 bpm / 350 psi. PU wt 185 k,
SO wt 130 k. Reciprocate pipe 10'.
SIMOPS - PJSM on cementing.
3,200.0 3,200.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 8/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/2/2023
02:45
4/2/2023
07:45
5.00 SURFAC, CEMENT CMNT P Pump primary cement job. Rig pump 60
bbls Nut Plug/Red Dye spacer.
Halliburton pump 5 bbls H2O and PT
lines to 1000/3500 psi (good).
Halliburton pump 60 bbls 10.2 ppg Mud
Push at 3 bpm/180 psi. Drop bottom
plug. 540 bbls 10.7 ppg lead cmnt at 4.5
bpm/500 psi. 57.8 bbls 15.8 ppg tail
cmnt at 2.5 bpm/280 psi. Drop top plug.
20 bbls H2O at 6 bpm/300 psi. Rig
displace with 279 bbls / 2755 stks mud
at 6 bpm.Slow down to 3 bpm last 10
bbls. FCP 650 psi. Bump plug and
pressure up 500 psi over to 1180 psi
hold for 5 minutes. Bleed off pressure
and check floats (good). Reciprocate
pipe 10' with full returns during cement
job. Observed cement to surface 50 bbls
into pumping tail cmnt. 307 bbls total
good cement to surface. CIP @ 07:41
Hrs.
3,200.0 3,200.0
4/2/2023
07:45
4/2/2023
08:45
1.00 SURFAC, CEMENT RURD P Flush cement cement out of riser and 4"
conductor valves. Back out landing joint
from hanger and L/D same.
0.0 0.0
4/2/2023
08:45
4/2/2023
12:00
3.25 SURFAC, CEMENT CLEN P Post cement clean up. Disconnect
Koomey lines to knife valve. M/U stack
washer and flush diverter and riser.
Function annular. Drain stack thru 4"
outlets and clean out cellar box. L/D
casing tools and equipment clean out
cement manifold lines. Clean and flush
out cement from under shakers and in
rock washer. Open hatches on flow line
and clean and clear of cement.
0.0 0.0
4/2/2023
12:00
4/2/2023
17:30
5.50 SURFAC, WHDBOP NUND P L/D mouse hole , R/D-L/D surface
risers, R/D injection lines from 4" valves.
Nipple down surface annular and L/D
via BOP deck cranes.
0.0 0.0
4/2/2023
17:30
4/2/2023
20:30
3.00 SURFAC, WHDBOP NUND P N/D and L/D diverter tee, stage 11"x 3" x
13" adapter, 2' spool and 1' DSA in BOP
deck.
0.0 0.0
4/2/2023
20:30
4/2/2023
23:30
3.00 SURFAC, WHDBOP NUND P Pull starting head adapter/install 11" well
head as per Cameron Reps. Test well
head seals t/ 5K F/ 15 Mins (good). Bolt
up 13" DSA Spool and 11" x 13"
adapter. Note Pad Operator Verified
orientation.
0.0 0.0
4/2/2023
23:30
4/3/2023
00:00
0.50 SURFAC, WHDBOP NUND P Nipple up 11" x 13" adapter, DSA &
spool, Set BOP stack/ Torque up
connection .
0.0 0.0
4/3/2023
00:00
4/3/2023
07:30
7.50 SURFAC, WHDBOP NUND P Torque stack bolts. N/U RCD head, kill
line, choke line, Install mouse hole,
Install RCD katch kan, R/U injection and
return line to MPD manifold, R/U 1502
flanges. SIMOPS - Take on FWP mud to
pits. Load 75 joints 5" DP to pipe shed.
0.0 0.0
4/3/2023
07:30
4/3/2023
11:00
3.50 SURFAC, WHDBOP MPDA P Set test plug as per Cameron rep. Install
RCD cap. Test MPD equip to 250/1250
psi (good). Remove RCD cap and install
trip nipple.
0.0 0.0
4/3/2023
11:00
4/3/2023
12:00
1.00 SURFAC, WHDBOP RURD P R/U to test BO. M/U 5" test joint. Fill
stack with H2O and purge air from
system. Perform shell test.
0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 9/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/3/2023
12:00
4/3/2023
16:30
4.50 SURFAC, WHDBOP BOPE P Test BOP's w/5" test joint. 250/3500 psi
and chart for 5 min. Annular, upper and
lower 3-1/2" X 6" VBR's, blind/shear
rams, Choke valves 1 - 15, two FOSV
and one dart valve, manual and super
choke, maunual/HCR choke kill lines.
Test gas alarms and PVT sensors.
Perform koomey draw down. 8 sec first
200 psi, 57 sec to full system pressure.
AOGCC Kam StJohn waive witness of
test.
0.0 0.0
4/3/2023
16:30
4/3/2023
18:30
2.00 SURFAC, WHDBOP RURD P R/D testing equipment. Blow down
choke /kill lines. Set wear ring as per
Cameron rep. (length 2.55', OD 10-3/4",
ID 10-1/16")
0.0 0.0
4/3/2023
18:30
4/3/2023
20:00
1.50 SURFAC, DRILLOUT PULD P L/D 2 stands 5" HWDP from derrick in
preperation for next hole section.
SIMOPS - BHA tools and equip.
0.0 0.0
4/3/2023
20:00
4/4/2023
00:00
4.00 SURFAC, DRILLOUT BHAH P M/U 9-7/8" X 11" Intermediate BHA as
per SLB reps t/638'
0.0 638.0
4/4/2023
00:00
4/4/2023
04:00
4.00 SURFAC, DRILLOUT PULD P RIH W/5" DP from pipe shed F/638' to
2900'. PUWT = 124K, SOWT = 106K
638.0 2,900.0
4/4/2023
04:00
4/4/2023
06:30
2.50 SURFAC, DRILLOUT CIRC P Perform shallow hole test at 2900'.
Stage up to 500 GPM = 1350 PSI.
Circulate B/U 3X
2,900.0 2,900.0
4/4/2023
06:30
4/4/2023
08:30
2.00 SURFAC, DRILLOUT PRTS P R/U to test Surface Casing. Test 10 3/4"
45.5# L80 Surface casing to 3500 PSI,
30 min, Charted. Good Test. R/D test
equip.
2,900.0 2,900.0
4/4/2023
08:30
4/4/2023
14:00
5.50 SURFAC, DRILLOUT MPDA P PJSM with MPD Rep's to install MPD
bearing. Drain stack and pull MPD trip
nipple. Install bearing. Pump thru
chokes and attempt to establish ramp
schedule with MPD Rep. Adjust set
points, troubleshoot choke sensors and
ramp mode.
2,900.0 2,900.0
4/4/2023
14:00
4/4/2023
19:45
5.75 SURFAC, DRILLOUT MPDA T Continue to adjust/tune and
troubleshoot MPD system. Simulate
trapping pressure on connections with
ramping dynamics. Open chokes and
inspect = Good. Attempt different flow
rates.
Able to maintain manageable control at
500 GPM = 1350 PSI.
2,900.0 2,900.0
4/4/2023
19:45
4/4/2023
22:00
2.25 SURFAC, DRILLOUT MPDA P Blow down MPD and TD. Pull bearing
and install trip nipple.
2,900.0 2,900.0
4/4/2023
22:00
4/4/2023
23:00
1.00 SURFAC, DRILLOUT WASH P Wash down 500 GPM = 1320 PSI,
F/2900' to 3096'. Tag cement at 3096'
MD. Set down 5K - 2X.
2,900.0 3,096.0
4/4/2023
23:00
4/5/2023
00:00
1.00 SURFAC, DRILLOUT COCF P Drill cement F/3096' to 3111' MD. 500
GPM = 1320 PSI. 60 -80 RPM = 6-8K
TQ. 5-10K WOB. PUWT = 126, SOWT =
108K, ROTW = 120K.
3,096.0 3,111.0
4/5/2023
00:00
4/5/2023
03:30
3.50 SURFAC, DRILLOUT DRLG P F/ 3111' MD t/ 3205' MD Drill shoe track
and rat hole, as SLB. GPM=500, PSI=
1310, RPM=80 TQ=8K F/O=43%
WOB=1-10K, P/U 128K S/O 108K RT/W
120K
Tag shoe and float on depth.
3,111.0 3,205.0
4/5/2023
03:30
4/5/2023
04:00
0.50 SURFAC, DRILLOUT DDRL P Drill 9.875" x11" intermediate hole f/
3205' MD t/ 3225' MD GPM=500, PSI=
1340, RPM=80, TQ=8K, F/O=43%,
WOB=6K, P/U 128K, S/O 108K, RT/W
120K
ADT=.33, Total Bit Hrs= .33, Total Jar
Hrs= 30.96
3,205.0 3,225.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 10/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/5/2023
04:00
4/5/2023
06:00
2.00 SURFAC, DRILLOUT CIRC P F/ 3225' MD to 3189' MD Circulate and
condition mud for LOT.
GPM=500, PSI= 1340, RPM=80,
TQ=8K, F/O=43%, WOB=6K, P/U 128K,
S/O 108K, RT/W 120K
Drift Shoe no over pull observed.
3,225.0 3,189.0
4/5/2023
06:00
4/5/2023
08:00
2.00 SURFAC, DRILLOUT FIT P R/U to Perform LOT, Pressure up 976
w/L/O to 862 psi 15.2 ppg @ 5 SPM 15
Strokes Total (1.5 BBLS pumped .6
BBLS bled back) R/D and blow down
testing equipment
3,189.0 3,189.0
4/5/2023
08:00
4/5/2023
08:45
0.75 INTRM1, DRILL CIRC P @ 3220' MD displace t/ 9.5 PPG FWP
@ 500=GPM, 963=PSI, 47%=F/O, 3052
Strokes pumped
3,189.0 3,220.0
4/5/2023
08:45
4/5/2023
09:00
0.25 INTRM1, DRILL CIRC P Obtain New SPR's with new mud weight
@ 3220' MD
3,220.0 3,220.0
4/5/2023
09:00
4/5/2023
11:30
2.50 INTRM1, DRILL DDRL P Drill 9.875" x11" intermediate hole f/
3225' MD t/ 3398' MD GPM=500, PSI=
1340, RPM=80, TQ=5K, F/O=48%
ECD=10.29, WOB=6K, P/U 128K, S/O
108K, RT/W 120K
ADT=.1.64, Total Bit Hrs= .1.64, Total
Jar Hrs=32.99
3,225.0 3,398.0
4/5/2023
11:30
4/5/2023
12:00
0.50 INTRM1, DRILL UREM P @ 3398' MD Drop 1.25" ball pump down
string @ 50 GPM, 30 RPM, Shear @
1262 PSi, 66 strokes pumped, Drill 3' to
3402' MD @ 700= GPM 1470=PSI, 53%
= F/O, 100 =RPM 4K=TQ, with under
reamer open, Pick up with no rotary @
700=GPM and confirm blades are open
(10K over pull) DD Witness charted on
Totco.
3,398.0 3,398.0
4/5/2023
12:00
4/5/2023
18:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" x11" intermediate hole f/
3398' MD t/ 3847 ' MD GPM=500,
PSI= 1340, RPM=130, TQ=6K,
F/O=51% ECD=10.3 ppg, WOB=12K,
P/U 123K, S/O 122K, RT/W 119K
Pumped 20 bbl Hi-Vis sweep at 3840'
MD, See 25% increase in cuttings at
sweep return
3,398.0 3,847.0
4/5/2023
18:00
4/6/2023
00:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/3847' to 4313' MD. 730 GPM = 1785
PSI. 130 RPM = 6.5K TQ-on. 10.62
ECD. PUWT = 124K, SOWT = 119K.
ROTW = 120K.
Est. SPR's
ADT = 8.81 hrs., Total Bit Hrs = 10.45.
Total Jar Hrs = 39.44
Pumped 20 bbl Hi-Vis sweep at 4318'
MD, See 20% increase in cuttings at
sweep return
3,847.0 4,313.0
4/6/2023
00:00
4/6/2023
06:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/4313' to 4730' MD. 730 GPM = 1840
PSI. 150 RPM = 6.5K TQ-on. WOB =
20K. ECD 10.62 ppg. PUWT = 124K,
SOWT = 119K. ROTW = 120K. 54%
flow. Pump 20 bbl Hi-Vis sweep every
500', See 50% increase in cuttings at
sweep return
4,313.0 4,730.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 11/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/6/2023
06:00
4/6/2023
12:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/4730' to 5264' MD. 730 GPM = 1977
PSI. 150 RPM = 7K TQ-on. WOB = 20K.
ECD = 10.75 ppg. PUWT = 127K,
SOWT = 122K. ROTW = 124K. 54%
flow. Pump 25 bbl Hi-Vis sweep at 5075'
MD = 20% increase in cuttings
ADT = 8.89 hrs., Total Bit Hrs = 19.34.
Total Jar Hrs = 50.69
4,730.0 5,264.0
4/6/2023
12:00
4/6/2023
18:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/5264' to 5908' MD. 730 GPM = 2019
PSI. 150 RPM = 7K TQ-on. WOB = 20K.
ECD = 11.22 ppg. PUWT = 130K,
SOWT = 121K. ROTW = 124K. 54%
flow. Pump 20 bbl Hi-Vis sweep at 5686'
MD = 10% increase in cuttings.
5,264.0 5,908.0
4/6/2023
18:00
4/7/2023
00:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/5908' to 6200' MD. 730 GPM = 2142
PSI. 150 RPM = 7K TQ-on. WOB = 20K.
ECD = 10.99 ppg. PUWT = 135K,
SOWT = 125K. ROTW = 129K. 54%
flow. Pump 20 bbl Hi-Vis sweep at 6110'
MD = 10% increase in cuttings.
ADT = 9.47 hrs., Total Bit Hrs = 28.81.
Total Jar Hrs = 59.44
5,908.0 6,200.0
4/7/2023
00:00
4/7/2023
03:30
3.50 INTRM1, DRILL RGRP T Reciprocate pipe while repairing mud
pump #1 suction pot drain valve.
Dump and Dilute 290 bbls 9.5 ppg
LSND mud at 6203' MD - due to
elevated MBT.
6,200.0 6,200.0
4/7/2023
03:30
4/7/2023
06:00
2.50 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/6200' to 6393' MD. 730 GPM = 2034
PSI. 150 RPM = 7K TQ-on. WOB = 18K.
ECD = 10.78 ppg. PUWT = 135K,
SOWT = 129K. ROTW = 133K. 54%
flow.
6,200.0 6,393.0
4/7/2023
06:00
4/7/2023
12:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/6393' to 6866' MD. 730 GPM = 2092
PSI. 150 RPM = 8K TQ-on. WOB = 20K.
ECD = 10.85 ppg. PUWT = 135K,
SOWT = 125K. ROTW = 129K. 52%
flow.
ADT = 5.87 hrs., Total Bit Hrs = 34.56.
Total Jar Hrs = 65.19
6,393.0 6,866.0
4/7/2023
12:00
4/7/2023
18:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/6866' to 7374' MD. 730 GPM = 2303
PSI. 160 RPM = 8K TQ-on. WOB = 18K.
ECD = 11.05 ppg. PUWT = 144K,
SOWT = 130K. ROTW = 132K. 53%
flow. Pump 20 bbl Hi-Vis sweep at 6866'
MD = minimal increase in cuttings.
6,866.0 7,374.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 12/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/7/2023
18:00
4/8/2023
00:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/7374' to 7905' MD. 730 GPM = 2293
PSI. 160 RPM = 9K TQ-on. WOB = 20K.
ECD = 10.94 ppg. PUWT = 135K,
SOWT = 125K. ROTW = 129K. 54%
flow.
Dump and Dilute 290 bbls 9.5 ppg
LSND mud at 7750' MD - due to
elevated MBT.
ADT = 8.9 hrs., Total Bit Hrs = 43.46.
Total Jar Hrs = 74.09
7,374.0 7,905.0
4/8/2023
00:00
4/8/2023
06:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/7905' to 8470' MD. 730 GPM = 2359
PSI. 160 RPM = 10K TQ-on. WOB =
19K. ECD = 10.95 ppg. PUWT = 149K,
SOWT = 142K. ROTW = 141K. 53%
flow.
7,905.0 8,470.0
4/8/2023
06:00
4/8/2023
12:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/8470' to 9053' MD. 730 GPM = 2420
PSI. 160 RPM = 10K TQ-on. WOB =
12K. ECD = 10.94 ppg. PUWT = 153K,
SOWT = 143K. ROTW = 141K. 52%
flow.
Pump weighted nut plug sweep = 10%
increase in cuttings on return
ADT = 8.64 hrs. Total Bit Hrs = 52.10.
Total Jar Hrs = 82.73
8,470.0 9,053.0
4/8/2023
12:00
4/8/2023
18:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/9053' to 9416' MD. 730 GPM = 2330
PSI. 160 RPM = 10 - 16K TQ-on. WOB
= 10-20K. ECD = 10.90 ppg. PUWT =
154K, SOWT = 141K. ROTW = 143K.
53% flow.
Pump weighted nut plug sweep at 500 ft
interval = 10% increase in cuttings on
return
9,053.0 9,416.0
4/8/2023
18:00
4/9/2023
00:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/9416' to 9886' MD. 730 GPM = 2499
PSI. 160 RPM = 11K TQ-on. WOB =
16K. ECD = 10.90 ppg. PUWT = 161K,
SOWT = 144K. ROTW = 141K. 51%
flow.
ADT = 8.55 hrs., Total Bit Hrs = 60.65.
Total Jar Hrs = 91.28
9,416.0 9,886.0
4/9/2023
00:00
4/9/2023
04:15
4.25 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/9886' to 10264' MD. 730 GPM = 2667
PSI. 150 RPM = 12K TQ-on. WOB =
17K. ECD = 11.46 ppg. PUWT = 163K,
SOWT = 143K. ROTW = 138K. 51%
flow.
9,886.0 10,264.0
4/9/2023
04:15
4/9/2023
04:45
0.50 INTRM1, DRILL CIRC P R&R DP and circulate in prep to install
MPD RCD. 730 GPM = 2652 PSI. 100
RPM = 7K TQ-on. ROTW = 141K.
10,264.0 10,264.0
4/9/2023
04:45
4/9/2023
05:15
0.50 INTRM1, DRILL OWFF P Blow down TD. OWFF 15 min. 10,264.0 10,264.0
4/9/2023
05:15
4/9/2023
07:00
1.75 INTRM1, DRILL MPDA P Remove Trip nipple. Install MPD RCD
bearing. SOWT=140K
10,264.0 10,264.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 13/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/9/2023
07:00
4/9/2023
12:00
5.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/10264' to 10642' MD. 730 GPM =
2790 PSI. 160 RPM = 12K TQ-on. WOB
= 17K. ECD = 11.52 ppg. PUWT =
170K, SOWT = 140K. ROTW = 153K.
53% flow.
ADT = 6.89 hrs., Total Bit Hrs = 67.54.
Total Jar Hrs = 98.17
10,264.0 10,642.0
4/9/2023
12:00
4/9/2023
18:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/10642' to 11000' MD. 730 GPM =
2910 PSI. 160 RPM = 12K TQ-on. WOB
= 17K. ECD = 11.45 ppg. PUWT =
175K, SOWT = 140K. ROTW = 163K.
53% flow. MW = 10.2 ppg
10,642.0 11,000.0
4/9/2023
18:00
4/9/2023
23:00
5.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/11000' to 11398' MD. 730 GPM =
3028 PSI. 160 RPM = 13.5K TQ-on.
WOB = 13K. ECD = 11.62 ppg. PUWT =
176K, SOWT = 134K. ROTW = 155K.
53% flow.
Observe HRZ top at 11214' MD
ADT = 8.27 hrs., Total Bit Hrs = 75.81.
Total Jar Hrs = 106.44
11,000.0 11,398.0
4/9/2023
23:00
4/10/2023
00:00
1.00 INTRM1, DRILL CIRC P R&R DP. Circulate and Condition mud to
ensure proper Black product percentage
in mud.
11,398.0 11,398.0
4/10/2023
00:00
4/10/2023
06:00
6.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/11398' to 11680' MD. 730. GPM =
3092 PSI. 140 RPM = 9K TQ-on. WOB
= 14K. ECD = 11.79 ppg. PUWT =
181K, SOWT = 128K. ROTW = 157K.
57% flow. MW = 10.1 ppg
11,398.0 11,680.0
4/10/2023
06:00
4/10/2023
11:30
5.50 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/11690' to 12003' MD. 730 GPM =
2980 PSI. 160 RPM = 14K TQ-on. WOB
= 10K. ECD = 11.77 ppg. PUWT =
192K, SOWT = 128K. ROTW = 155K.
53% flow
ADT = 8.23 hrs., Total Bit Hrs = 84.04.
Total Jar Hrs = 110.67
11,680.0 12,003.0
4/10/2023
11:30
4/10/2023
12:00
0.50 INTRM1, DRILL CIRC P Circulate and Condition mud due to
loosing mud over shakers. Screen
down. 550 GPM = 2100 PSI. 120 RPM
= 11K TQ. ECD = 11.75. MW = 10.2 ppg
12,003.0 12,030.0
4/10/2023
12:00
4/10/2023
16:15
4.25 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/12030' to 12117' MD. Hold MPD 11.6,
down from 11.8 to mitigate losses. 650.
GPM = 2639 PSI. 140 RPM = 9K TQ-
on. WOB = 14K. ECD = 11.63 ppg.
PUWT = 181K, SOWT = 128K. ROTW =
157K. 57% flow. MW = 10.1 ppg
12,030.0 12,117.0
4/10/2023
16:15
4/10/2023
21:00
4.75 INTRM1, DRILL CIRC T Circulate and condition mud. Reduce
rate to manage losses over blinded off
shakers.Pump at 400 GPM = 1200 PSI.
67 RPM = 10.5K TQ. MPD HOLDING
11.6 ppg EMW. Increases rate to 600
GPM = 2816 PSI. R&R stand at 100
RPM = 11K TQ. Add 290 bbls of 10.2
ppg new mud to active system.
12,117.0 12,117.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 14/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/10/2023
21:00
4/11/2023
00:00
3.00 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/12117' to 12270' MD. 730 GPM =
3117 PSI. 160 RPM = 13K TQ-on. WOB
= 9K. ECD = 11.66 ppg. PUWT = 186K,
SOWT = 138K. ROTW = 152K. 53%
flow
ADT = 4.97 hrs., Total Bit Hrs = 89.01.
Total Jar Hrs = 119.64
Total 24 hr fluid loss = 344 bbls
12,117.0 12,270.0
4/11/2023
00:00
4/11/2023
02:45
2.75 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/12270' to 12435' MD. 730 GPM =
3096 PSI. 160 RPM = 13K TQ-on. WOB
= 16K. ECD = 11.69 ppg. PUWT =
186K, SOWT = 138K. ROTW = 152K.
59% flow
Pump 30 bbl of 30 ppb LCM pill due to
loss circulation.
ADT = 2.14 hrs., Total Bit Hrs = 91.15.
Total Jar Hrs = 121.78
12,270.0 12,435.0
4/11/2023
02:45
4/11/2023
12:00
9.25 INTRM1, DRILL CIRC T Circulate and condition mud. R&R DP.
600 GPM = 2349 PSI. 60 RPM = 11K
TQ. Hold 11.6 ppg EMW on MPD.
Pump 60 bbl of 30 ppb LCM pill to
mitigate fluid losses.
Decrease flow rate to 400 GPM = 1350
PSI. Observe loss rate increase.Line up
to pump down back side. 200 GPM
holding 11.00 ppg EMW with MPD.
Rotate at 15-20 RPM = 10-11K TQ.
Build mud volume.
12 hr mud loss = 470 bbls
12,435.0 12,435.0
4/11/2023
12:00
4/11/2023
16:30
4.50 INTRM1, DRILL CIRC T Continue to pump down back side and
hold 11.1 ppg with MPD while building
mud volume. Screen down shakers.
PUWT = 180K, SOWT = 160K, ROTW =
125K.
Line up and pump down DP. Pump 70
bbl of 50 ppb LCM pill. 220 GPM = 540
PSI. 20RPM = 11K TQ. After LCM was
clear of the bit, staged pumps up to 730
GPM = 2950 PSI. 140 RPM = 15K TQ.
Hold 11.5 EMW with MPD. Observed a
decrease in loss rate.
12,435.0 12,435.0
4/11/2023
16:30
4/12/2023
00:00
7.50 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/12435' to 12586' MD. 730 GPM =
2950 PSI. 140 RPM = 14K TQ-on. WOB
= 21K. ECD = 11.56 ppg. PUWT =
188K, SOWT = 160K. ROTW = 125K.
59% flow
ADT = 5.61 hrs., Total Bit Hrs = 96.76.
Total Jar Hrs = 127.39
12 hr mud loss = 68 bbls
12,435.0 12,586.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 15/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/12/2023
00:00
4/12/2023
01:30
1.50 INTRM1, DRILL DDRL P Drill 9.875" X 11" Intermediate hole
F/12586' to TD at12611' MD. 730 GPM
= 2960 PSI. 140 RPM = 14K TQ-on.
WOB = 21K. ECD = 11.56 ppg. PUWT =
186K, SOWT = 138K. ROTW = 152K.
59% flow
Obtain final Survey, T&D, and SPR's.at
TD
ADT = 1.34 hrs., Total Bit Hrs = 98.10.
Total Jar Hrs = 128.73
12,586.0 12,611.0
4/12/2023
01:30
4/12/2023
03:30
2.00 INTRM1, CASING CIRC P Break connection and Drop 1.625 ball to
close Reamer. Pump ball down at 250
GPM = 821 PSI for 10 min. Reduce rate
to 100 GPM = 575 PSI for 20 min.
Observe pressure spike to 2100 psi
when ball seated. Confirmed Reamer
closed viaTurbine speed change from
4350 RPM to 4700 RPM.
Continue to hold 11.6 ppg EMW with
MPD.
12,611.0 12,611.0
4/12/2023
03:30
4/12/2023
06:00
2.50 INTRM1, CASING CIRC P Pump 70 bbls of 50 ppb LCM pill at 225
GPM = 813 PSI. until LCM passed thru
the bit. Increase pump rate to 730 GPM
= 3115 PSI. Pull slow F/ 12611' to
12533' MD until BU and LCM is out of
hole. ROTW = 156K, 40-80 RPM = 11K
TQ. Rack stand back.
12,611.0 12,533.0
4/12/2023
06:00
4/12/2023
12:00
6.00 INTRM1, CASING BKRM P BROOH F/ 12533' to 11680' MD. 500
GPM = 1780 PSI, 40 RPM = 10.5K TQ,
ROTW = 155K. 48% flow. Hold 11.6 ppg
EMW with MPD
12,533.0 11,680.0
4/12/2023
12:00
4/12/2023
16:00
4.00 INTRM1, CASING BKRM P BROOH F/ 11680' to 11212' MD. 500
GPM = 1680 PSI, 40 RPM = 10.5K TQ,
ROTW = 155K. 48% flow. Hold 11.6 ppg
EMW with MPD
11,680.0 11,212.0
4/12/2023
16:00
4/12/2023
18:45
2.75 INTRM1, CASING CIRC P Pump 40 bbls of 50 ppb LCM pill. 220 -
500 GPM = 670 - 1650 PS, 40 RPM =
10K TQ. ROTW = 155K. BROOH slow
F/ 11212' to 11014' as LCM clears the
bit.Hold 11.4 ppg EMW with MPD
11,212.0 11,014.0
4/12/2023
18:45
4/12/2023
21:30
2.75 INTRM1, CASING COND P PJSM. Condition mud and prep pits to
weight up to 11.4 ppg with 3 circulations.
11,014.0 11,014.0
4/12/2023
21:30
4/13/2023
00:00
2.50 INTRM1, CASING DISP P Begin to weight up mud in .4 ppg
increments from 10.2 ppg to 10.6 ppg in
first circulation. Pump at 500-450 GPM
= 1650 - 1426 PSI. Holding 11.4 ppg
with MPD. Rotate and Pull slowly at 30'
per hour. ROTW = 150K = 11K TQ, 40
RP[M while pump surface to surface.
12 hr mud loss = 55 bbls
11,014.0 11,014.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 16/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/13/2023
00:00
4/13/2023
06:00
6.00 INTRM1, CASING DISP P At 11014' MD, Continue to weight up
mud system from 10.6 ppg to 11.0 ppg.
Stage pumps per MPD schedule. 450 -
200 GPM = 1650 - 587 PSI. MPD
holding 11.4 - 11.6 ppg EMW. Pull
slowly at 30 fph, while circulating STS.
ROTW = 150K. 40 RPM = 11K TQ.
F/11014' to 10928' MD, circ at 275 GPM
= 650 PSI. Shut down and trap 130 psi
to check MPD rollover schedule. Back
pressure stable at 87 psi with chokes
closed. Pump 100 - 200 GPM = 350 -
533 PSI while waiting on MPD schedule.
Pump at 400 gpm to gain ECD
detection. ECD = 11.9 ppg. Continue to
weight up mud to 11.2 ppg, 400 GPM =
1140 PSI. 20 - 50 RPM = 11K TQ.
ROTW = 150K. ECD = 11.71 ppg
11,014.0 10,928.0
4/13/2023
06:00
4/13/2023
09:30
3.50 INTRM1, CASING DISP P Continue to weight up mud to 11.4 ppg.
500 - 175 GPM = 1130 - 370 PSI. 50
RPM = 10K TQ. PUWT = 180K, SOWT
= 130K, ROTW = 153K
10,928.0 10,928.0
4/13/2023
09:30
4/13/2023
14:00
4.50 INTRM1, CASING OWFF P OWFF. Observe flow out @ 4.25 BPH
reduce down to .39 BPH. Rotate at 7
RPM = 7K, ROTW = 148K
12 hr mud loss = 82 bbls
10,928.0 10,928.0
4/13/2023
14:00
4/13/2023
15:30
1.50 INTRM1, CASING BKRM P BROOH. F/10928' to 10739' MD. 275 -
160 GPM = 650 - 400 PSI. 40 RPM =
10.5K TQ. ROTW = 155K. Hold 11.4
ppg EMW W/ MPD. LDDP
10,928.0 10,739.0
4/13/2023
15:30
4/13/2023
18:15
2.75 INTRM1, CASING SMPD P SOOH F/10739' to 10135' MD. PUWT =
185K, SOWT = 120K. Tight spots at
10679', 10171', 10160'. Pulling tight
10,739.0 10,135.0
4/13/2023
18:15
4/14/2023
00:00
5.75 INTRM1, CASING BKRM P BROOH F/10135' to 9472' MD. Stage
pumps up slowly, 84 - 170 GPM = 294 -
333 PSI. ROTW = 149K, 30 - 40 RPM =
11K TQ.
Attempt to SOOH at 10175'. See 30K
over pulls. BROOH T/9890'. Attempt to
SOOH again. See 30K over pulls again.
BROOH T/9795' MD. Attempt SOOH,
see 30K over pull. Decide to BROOH
out until further notice.
12 hr mud loss = 343 bbls
10,135.0 9,472.0
4/14/2023
00:00
4/14/2023
04:00
4.00 INTRM1, CASING BKRM P BROOH F/9472' to 8480' MD. 170 GPM
= 388 PSI. 40 RPM = 9K. ECD = 11.4
ppg. PUWT=162K, SOWT = 121K,
ROTW = 136K. Hold 11.4 EMW with
MPD
9,472.0 8,480.0
4/14/2023
04:00
4/14/2023
09:00
5.00 INTRM1, CASING SMPD P SOOH F/8480' to 7100' MD. PUWT =
162K, SOWT = 121K, ROTW = 136K.
See 30K over pull 2X. Drop down to
7148' MD
8,480.0 7,148.0
4/14/2023
09:00
4/14/2023
10:00
1.00 INTRM1, CASING BKRM P BROOH F/7148' to 7089' MD. CBU and
Ream thru tight spots. 275 GPM = 580
PSI. 40 RPM = 7K TQ. PUWT = 140K,
SOWT = 120K, ROTW = 130K.
7,148.0 7,089.0
4/14/2023
10:00
4/14/2023
13:15
3.25 INTRM1, CASING SMPD P SOOH F/7089' to 6586' MD. PUWT =
151K, SOWT = 117K, Hold 11.4 EMW
per MPD.
12 hr mud loss = 663 bbls
7,089.0 6,586.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 17/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/14/2023
13:15
4/14/2023
18:00
4.75 INTRM1, CASING BKRM P BROOH F/6586' to 6098' MD. 275 GPM
= 492 PSI. 65 RPM = 6K TQ. PUWT =
152K, SOWT = 161K, ROTW = 127K.
6,586.0 6,098.0
4/14/2023
18:00
4/15/2023
00:00
6.00 INTRM1, CASING BKRM P BROOH F/6098' to 5544' MD. 280 GPM
= 500 PSI, 70 RPM = 6K TQ, PUWT =
148K, SOWT = 158K, ROTW = 117K.
Trapping 60 psi with MPD beginning at
5928' MD
12 hr mud loss = 384 bbls
6,098.0 5,544.0
4/15/2023
00:00
4/15/2023
12:00
12.00 INTRM1, CASING BKRM P BROOH F/5544' to 3940' MD. 280/400
GPM = 515/838 PSI. 80 RPM = 4/6K
TQ. Hold 60 psi/11.7 EMW with MPD on
connections. PUWT = 148K, SOWT =
158K, ROTW = 121K. At 4789' MD,
stage pumps up from 280 to 400 GPM.
Observe losses increase. Decrease
pump rate to 275 GPM and monitor
losses. LDDP.
12 hr mud loss = 698 bbls
5,544.0 3,940.0
4/15/2023
12:00
4/15/2023
18:45
6.75 INTRM1, CASING BKRM P BROOH F/3940' to 3185' MD. 300 GPM
= 425 PSI, 80 RPM = 3K TQ. Hold 60
psi/11.7 EMW with MPD on
connections. PUWT = 148K, SOWT =
158K, ROTW = 110K. Pull bit into 10
3/4" casing shoe smooth. Reduce to 40
RPM inside casing.
3,940.0 3,185.0
4/15/2023
18:45
4/15/2023
21:00
2.25 INTRM1, CASING CIRC P Pump up survey for Directional Driller
Pump nut plug sweep surface to
surface.
Rotate and Reciprocate F/3185' to 3095'
MD. 300 GPM = 425 PSI, 40 RPM = 3K
TQ, ROTW = 110K.
3,185.0 3,095.0
4/15/2023
21:00
4/16/2023
00:00
3.00 INTRM1, CASING OWFF P Blow down TD. OWFF. Observe
decreasing flow from well. Initial flow of
60 bph and 47 psi with shut in MPD
chokes. Perform bleed/shut in cycles to
establish fingerprint.
12 hr mud loss = 16 bbls
Total 24 hour loss = 714 bbls
3,095.0 3,095.0
4/16/2023
00:00
4/16/2023
01:00
1.00 INTRM1, CASING OWFF P OWFF. Observed decreasing flow rate.
Decreased to 33 BPH at 33 BPH and 40
psi shut in pressure. Inications of
balloning.
Checked MW in = 11.4 ppg, MW out =
11.2 ppg.
Discuss options with town.
3,095.0 3,095.0
4/16/2023
01:00
4/16/2023
03:30
2.50 INTRM1, CASING BKRM P Back Ream out to more vertical section
of hole. F/3185' to 2902' MD. 300 GPM
= 2200 PSI. 40 RPM = 2K TQ. ROTW =
109K. Close MPD chokes on
connection.
Pumped a high vis sweep with nut plug.
Observed sweep to surface, no real
increase in cuttings.
3,095.0 2,902.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 18/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/16/2023
03:30
4/16/2023
16:15
12.75 INTRM1, CASING OWFF P OWFF. Monitor for wellbore breathing
thru MPD equipment at timed intervals.
Observe initial flow out of 47 gpm with
MPD chokes open. Initial 50 psi build up
with MPD chokes closed. Final MPD
flow out = 5 gpm. Final MPD closed
pressure = 22.psi. Final volume returned
to pits = 128 bbls
Monitor flow back at RCD head. Open
2" port and measure flow with Vis-cup.
Initial return flow rate = 2.5 sec / 8.6
BPH. MW out = 11.1+ ppg.
Decide to CBU and condition mud.
2,902.0 2,902.0
4/16/2023
16:15
4/16/2023
18:15
2.00 INTRM1, CASING CIRC P Circulate and condition mud until
constant MW is 11.4 ppg in and out.
174 GPM = 184 PSI. ROTW = 109K.
Note, no observations on BU. No gas.
Mud coming out 11.25 - 11.4 before BU
with good properties.
2,902.0 2,902.0
4/16/2023
18:15
4/16/2023
20:30
2.25 INTRM1, CASING OWFF P OWFF. Monitor well bore breathing at
RCD head using Vis-cup. Initial flow rate
= 12 BPH. Final flow rate = 1 BPH. MW
IN/OUt= 11.4+ ppg
2,902.0 2,902.0
4/16/2023
20:30
4/16/2023
22:00
1.50 INTRM1, CASING CIRC P CBU 1X. MW in = 11.4 ppg, MW out =
11.4 ppg. Bottoms up = 11.4 ppg. 175
GPM = 188 PSI
Note, no observation on BU. No gas.
2,902.0 2,902.0
4/16/2023
22:00
4/17/2023
00:00
2.00 INTRM1, CASING OWFF P OWFF. Monitor well bore breathing at
RCD head using Vis-cup. Initial flow rate
= 10.2 BPH. Flow rate at midnight =
3.35 BPH. MW = 11.4+ ppg
2,902.0 2,902.0
4/17/2023
00:00
4/17/2023
04:30
4.50 INTRM1, CASING OWFF P OWFF. Continue to monitor well bore
breathing at RCD head using Vis-cup.
Initial flow rate at midnight = 3.35 BPH.
Flow rate at 04:30 = 1.74 BPH. MW out
= 11.3 ppg
Service top drive, C/O suction and
discharge screens on mud pumps.
Verify casing tally in pipe shed, Service
drag chain.
2,902.0 2,902.0
4/17/2023
04:30
4/17/2023
06:30
2.00 INTRM1, CASING OWFF P Shut well in and monitor for pressure via
MPD. Well built 10 psi in 15 min.
Weight up mud in active system to 11.4+
ppg.
2,902.0 2,902.0
4/17/2023
06:30
4/17/2023
08:15
1.75 INTRM1, CASING CIRC P Circulate and condition mud to 11.4+
ppg in and out. Rotate and reciprocate
DP. 150 GPM = 144 PSI. ROTW =
109K. 10RPM = 2K TQ.
Weight up pit to 12 ppg to circulate over
the top of hole and to fill displacement.
2,902.0 2,902.0
4/17/2023
08:15
4/17/2023
08:45
0.50 INTRM1, CASING OWFF P Blow down TD. OWFF at RCD head.
Initial flow rate = 1,6 bph. MW = 11.4+
ppg. Final flow rate = .12 bph.
2,902.0 2,902.0
4/17/2023
08:45
4/17/2023
10:15
1.50 INTRM1, CASING MPDA P PJSM. Remove MPD RCD and replace
with New element per MPD reps.
PUWT = 115K, SOWT = 109K
2,902.0 2,902.0
4/17/2023
10:15
4/17/2023
14:45
4.50 INTRM1, CASING SMPD P SOOH F/2902' to 741' MD. Hold 25 psi
with MPD on connections. PUWT = 99K,
2,902.0 741.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 19/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/17/2023
14:45
4/17/2023
15:15
0.50 INTRM1, CASING OWFF P OWFF. Prep tools and equipment to pull
MPD RCD. Perform weekly BOP
function test.
741.0 741.0
4/17/2023
15:15
4/17/2023
17:00
1.75 INTRM1, CASING SMPD P SOOH F/741 to 634' MD. PJSM. Pull
MPD RCD with stand and rack back in
derrick. Install trip nipples.Line up on trip
tank to monitor displacement.
741.0 634.0
4/17/2023
17:00
4/17/2023
17:15
0.25 INTRM1, CASING OWFF P OWFF before pulling BHA. Well is static.
Line up trip tank on 12.0 ppg mud to fill
back side.
634.0 634.0
4/17/2023
17:15
4/17/2023
18:00
0.75 INTRM1, CASING BHAH P POOH W/BHA. Stand back HWDP,
F/634' to 262' MD.
634.0 262.0
4/17/2023
18:00
4/17/2023
22:00
4.00 INTRM1, CASING BHAH P L/D BHA F/262' to surface. Clean
stabilizers, bit and BHA as needed.
262.0 0.0
4/17/2023
22:00
4/17/2023
23:15
1.25 INTRM1, CASING BHAH P Clean and clear rig floor. L/D all tools
and equipment. Demob from rig floor.
SIMOPS = OWFF for 30 min. Well is on
a slight losses.
0.0 0.0
4/17/2023
23:15
4/18/2023
00:00
0.75 INTRM1, CASING WWWH P R/U to wash interior of BOP stack with
stack washing tool.
0.0 0.0
4/18/2023
00:00
4/18/2023
01:00
1.00 INTRM1, CASING RURD P Blow down TD. M/U running tool. Pull
wear bushing per Cameron Rep.
0.0 0.0
4/18/2023
01:00
4/18/2023
02:00
1.00 INTRM1, CASING WWWH P Flush/wash BOP stack. 750 GPM = 125
PSI. R/D Stack washer, Blow down TD.
0.0 0.0
4/18/2023
02:00
4/18/2023
05:45
3.75 INTRM1, CASING NUND P C/O upper pipe rams to 7 5/8" solid
body rams.
SIMOPS: Clean out MP#2 settling
chambers, discharge and suction
screens. C/O liners to 6" ceramic.
0.0 0.0
4/18/2023
05:45
4/18/2023
06:45
1.00 INTRM1, CASING NUND P Install test plug and 7 5/8" test joint per
Cameron Rep. Fill stack with water and
bleed air from system. R/U test
equipment.
0.0 0.0
4/18/2023
06:45
4/18/2023
07:45
1.00 INTRM1, CASING BOPE P Test annular and upper 7 5/8" pipe rams
with 7 5/8" test joint. 250 psi low, 3500
psi high, 5 min each, Charted. Good
test.
0.0 0.0
4/18/2023
07:45
4/18/2023
08:15
0.50 INTRM1, CASING RURD P R/D test equip. Drain stack of water. Pull
test plug and L/D test joint. Blow down
kill and mud lines to pumps.
0.0 0.0
4/18/2023
08:15
4/18/2023
10:15
2.00 INTRM1, CASING RURD P R/U 7 5/8" Casing running equip.
Mobilize casing tools to rig floor. M/U
Volant tools to TD. Install bale
extensions. Install Master bushings. M/U
floor valves to crossovers.
Monitor well on trip tank.
0.0 0.0
4/18/2023
10:15
4/18/2023
10:45
0.50 INTRM1, CASING WWSP P Perform Dummy run with 7 5/8" casing
hanger and landing joint.
0.0 0.0
4/18/2023
10:45
4/18/2023
11:30
0.75 INTRM1, CASING RURD P Continue to R/U 7 5/8" casing equip.
R/U 350 ton slips in table Stage
centralizers on rig floor. Prep pipe shed
to run casing.
0.0 0.0
4/18/2023
11:30
4/18/2023
12:00
0.50 INTRM1, CASING SFTY P PJSM to run 7 5/8" casing per tally. Pick
up shoe joint and prep to run.
0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 20/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/18/2023
12:00
4/18/2023
16:30
4.50 INTRM1, CASING PUTB P M/U 7 5/8" 29.7# L80 HYD 563 Shoe
track and HES Baffle Collar adapter.
Baker-loc Shoe track connections.
Check Floats = Good.
Run 20 jts of 7 5/8" 39# TN-110SS HYD
563 Casing. C/O Volant pressure cup.
Run 7 5/8" 29.7# L80 HYD 563 Casing
to 1000' MD per running tally. PU/SO
WT = 73K
Install 1 free floating 7 5/8" X 9 3/8"
Hydroform centralizer from joint #4 thru
joint #78.
0.0 1,000.0
4/18/2023
16:30
4/18/2023
18:00
1.50 INTRM1, CASING CIRC P Circulate and condition mud to displace
12 ppg mud cap in hole. Circulate to
11.4 ppg MW in and out. Stage pumps
up to 5 BPM = 79 PSI.
1,000.0 1,000.0
4/18/2023
18:00
4/18/2023
21:15
3.25 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/1000' to 2440' MD. Torque to
10.3K ft/lb. Fill on the fly. Top off every
10 joints. Monitor displacement in pit #5.
Use BOL 2000 pipe dope.
1,000.0 2,440.0
4/18/2023
21:15
4/18/2023
22:15
1.00 INTRM1, CASING CIRC P Circulate and condition mud, due to loss
of displacement returns. Stage pumps
up to 170 GPM = 100 PSI. PU/SO WT =
104K.
Loss while circ = 68 bbls.
2,440.0 2,440.0
4/18/2023
22:15
4/18/2023
23:45
1.50 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/2440' to 2800' MD. PUWT =
117K, SOWT = 115K.
Loss for trip = 30 bbls
2,440.0 2,800.0
4/18/2023
23:45
4/19/2023
00:00
0.25 INTRM1, CASING OWFF P OWFF. Observe slight flow at bell
nipple. Note10 bbls returned over
calculated displacement after filling pipe.
24 hour fluid loss = 130 bbls
2,800.0 2,800.0
4/19/2023
00:00
4/19/2023
00:45
0.75 INTRM1, CASING CIRC P Circulate at 2800' MD. 170 GPM = 120
PSI. PU/SO WT = 117K/115K., Pumped
2020 stks, 203 bbls, Lost 59 bbls. MW in
= 11.4ppg, MW out = 11.3 ppg
2,800.0 2,800.0
4/19/2023
00:45
4/19/2023
01:00
0.25 INTRM1, CASING OWFF P OWFF, 2.5 bbls from well breathing
returned to pits.
2,800.0 2,800.0
4/19/2023
01:00
4/19/2023
02:00
1.00 INTRM1, CASING CIRC P Circulate and condition mud to 11.4 ppg
in and out. 170 GPM = 105 PSI.
Pumped 3500 stks, 350 bbls, lost 30
bbls on circ.
2,800.0 2,800.0
4/19/2023
02:00
4/19/2023
02:30
0.50 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/2800' to 3200' MD, Torque to
10.3K ft/lb. Fill on the fly. Top off every
10 joints.
2,800.0 3,200.0
4/19/2023
02:30
4/19/2023
03:15
0.75 INTRM1, CASING CIRC P Circulate at the shoe, 3200' MD. 100
GPM = 90 PSI. 10 RPM = 3K TQ.
PUWT = 119K, SOWT = 123K, ROTW =
120K. Pumped 600 stks, 60 bbls
3,200.0 3,200.0
4/19/2023
03:15
4/19/2023
07:15
4.00 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/3200' to 4974' MD,
3,200.0 4,974.0
4/19/2023
07:15
4/19/2023
09:00
1.75 INTRM1, CASING CIRC P Circulate and condition mud at 4974'
MD.
Stage pumps up to 2 BPM = 114 PSI.
MW in = 11.4+ ppg. MW out = 11.2+
ppg. PUWT = 143K, SOWT = 133K,
ROTW = 139K. 10 RPM = 5K TQ. Flow
out = 8%. Pumped 1459 stks, 147 bbls,
Lost 96 bbls.
4,974.0 4,974.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 21/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/19/2023
09:00
4/19/2023
12:00
3.00 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/4974' to 5790' MD, Install
HES cementing stage tool between joint
#129 & 130. Wash down every joint at .5
bpm = 114 psi Install centralizer 5'
above and 5' below stage tool. Install
one 7 5/8" X 9 3/8" centralizer from joint
130 thru joint 174.
4,974.0 5,790.0
4/19/2023
12:00
4/19/2023
15:00
3.00 INTRM1, CASING PUTB P RIH F/5790' to 6287' MD. SOWT =
137K. Continue to wash down every
joint at .5 bpm = 112 psi.
5,790.0 6,287.0
4/19/2023
15:00
4/19/2023
17:30
2.50 INTRM1, CASING CIRC P Circulate and condition mud. Stage
pumps up to 3 BPM = 177 PSI. Observe
minimal returns. MW in/out = 11.4 ppg.
PUWT = 152K, SOWT = 131K, ROTW =
141K, 20 RPM = 8K TQ. Pumped 2914
stks, 293 bbls, 195 bbls lost on
circulation.
6,287.0 6,287.0
4/19/2023
17:30
4/20/2023
00:00
6.50 INTRM1, CASING PUTB P RIH F/6287' to 8452' MD. SOWT =
137K. Fill on the fly. Wash down every
5th joint at 84 GPM = 230 PSI. When
casing is full, pump 2.5 extra bbls to
move mud in the annulus
At 8000' MD PUWT = 148K, SOWT =
135K, ROTW = 146K. 10 RPM = 12K
TQ
Total 24 hr mud loss = 820 bbls
6,287.0 8,452.0
4/20/2023
00:00
4/20/2023
07:00
7.00 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/8452' to 11078' MD. Torque
pipe to 10.3K ft/lbs. Fill on the fly. Wash
down every 5th joint at 84 GPM = 230
PSI. When casing is full, pump 2.5 extra
bbls to move mud in the annulus
8,452.0 11,078.0
4/20/2023
07:00
4/20/2023
08:30
1.50 INTRM1, CASING CIRC P Circulate and condition mud above HRZ
at 11078' MD. Stage pump rate up F/.5
bpm - 5 bpm. 363 - 370 psi. Rotate and
reciprocate casing at 5 - 20 RPM = 12 -
14K TQ. PUWT = 217K, SOWT = 141K,
ROTW = 151K. Flow out = 0 - 7%. MW
in = 11.45, out = 11.4 ppg. Pumped 302
bbls, lost 226 bbls on circulation.
11,078.0 11,078.0
4/20/2023
08:30
4/20/2023
12:00
3.50 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/11078'' to 12470' MD. Fill on
the fly. Wash down every 5th joint at 84
GPM = 230 PSI. When casing is full,
pump 2.5 extra bbls to move mud in the
annulus
At 12470', experienced tight hole
conditions. PUWT = 270K, SOWT =
117K. Work thru tight spots slowly and
wash down at 1 - 2 bpm = 333 - 348 psi
11,078.0 12,470.0
4/20/2023
12:00
4/20/2023
14:00
2.00 INTRM1, CASING PUTB P RIH W/7 5/8" 29.7# L80 HYD 563
Casing F/12470'' to 12561' MD. Wash
down slowly at 2 BPM = 353 PSI. PUWT
= 270K, SOWT = 140K. At 12470', pump
35 bbl LCM pill at 2 BPM, chase with
11.4 ppg mud.
12,470.0 12,561.0
4/20/2023
14:00
4/20/2023
14:30
0.50 INTRM1, CASING PULD P RIH F/12561' to 12604' MD. M/U 7 5/8"
casing hanger and landing joint. M/U to
Volant tool and wash down at 2 BPM =
367 PSI. Land 7 5/8" casing on
wellhead per Cameron Rep.
12,561.0 12,604.0
4/20/2023
14:30
4/20/2023
16:00
1.50 INTRM1, CEMENT CIRC P Circulate and condition mud. Stage rate
up F/1 - 5 BPM = 360 - 461 PSI. MW =
11.4 ppg in/out. Planned circulation is
6500 stks to prep for cement job.
12,604.0 12,604.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 22/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/20/2023
16:00
4/20/2023
16:45
0.75 INTRM1, CEMENT RURD P Blow down Volant tool and Top drive
and isolate thru IBOP. R/U cement line,
low torque valves and chart recorder to
Volant CRT
12,604.0 12,604.0
4/20/2023
16:45
4/20/2023
18:15
1.50 INTRM1, CEMENT CIRC P Continue to circulate and condition mud
thru cement line. 3 BPM = 381 PSI.
Pump 6500 stks total. Monitor losses in
pits.
12,604.0 12,604.0
4/20/2023
18:15
4/20/2023
22:30
4.25 INTRM1, CEMENT CMNT P Cement 7 5/8" intermediate casing in
place at 12604' MD as per Halliburton
Schedule.
Fill lines with 5 bbls H2O. 3.5 bpm = 430
psi.
PT lines to 4500 psi
Pump 80 bbls of 12.5 ppg Tuned Prime
spacer with BM2 LCM. 4bpm = 510 psi.
Pump 244 bbls 15.3 ppg Lead cement
with BM2, 3.5 bpm = 340 psi.
Pump 50 bbls Tail cement without BM2,
3.5 bmp = 250 psi.
Drop plug. Pump 10 bbls of H2O 4 bpm
= 90 psi.
Chase with rig pumps. ICP/ 8 bpm =
300 psi, FCP/ 3 bpm = 775 psi. Bump
plug at 5620 strokes. Pressure up to
1275 psi and hold 5 min. Check floats =
Good. Pressure up to 3500 psi and
open HES stage tool.
Cement in place at 22:15 hours
12,604.0 12,604.0
4/20/2023
22:30
4/21/2023
00:00
1.50 INTRM1, CEMENT WOC P Attempt to CBU thru stage tool with
minimal returns. Stop pumping.
Wait on cement to reach 100 psi
compressive strength. Pump 5 strokes
at 1 spm every 30 min to maintain
circulation thru stage tool.
Total 24 hour mud loss = 1934 bbls
12,604.0 12,604.0
4/21/2023
00:00
4/21/2023
06:00
6.00 INTRM1, CEMENT WOC P Wait on cement to reach 100 psi
compressive strength. Pump 5 strokes
every 30 min at 1 spm to ensure stage
tool ports are open.
Load and process 4" DP to pipe shed.
12,604.0 12,604.0
4/21/2023
06:00
4/21/2023
09:00
3.00 INTRM1, CEMENT WOC P Wait on cement to reach 100 psi
compressive strength. Pump 5 strokes
every 30 min at 1 spm to ensure stage
tool ports are open.Prep tools and
equipment for 2nd stage cement job.
Blow air thru hard line to cement truck.
PJSM for cement job.
Load and process 4" DP to pipe shed.
12,604.0 12,604.0
4/21/2023
09:00
4/21/2023
10:00
1.00 INTRM1, CEMENT CIRC P Circulate thru stage tool at .5 bpm
increments from .5 - 1.7 BPM = 273 -
376 PSI. Pump a total of 332 stks. Cut
mud weight to 11 ppg for circulation.
MW = 11.0 in, 11.4 ppg out.Observe
high loss rates. Shut down pumps.
12,604.0 12,604.0
4/21/2023
10:00
4/21/2023
18:00
8.00 INTRM1, CEMENT WOC P Continue to Wait on cement to reach
100 psi compressive strength. Pump 5
strokes every 30 min at 1 spm to ensure
stage tool ports are open.
12,604.0 12,604.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 23/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/21/2023
18:00
4/21/2023
21:00
3.00 INTRM1, CEMENT CIRC P Stage up pumps in 1/2 bbls increments
to 5bbls min and circulate 2 bottoms up
volume, 6367 strokes, 539 bbls loss.
.5 bbls/min = 290 psi
1 bbls/min = 360 psi
1.5 bbls/min = 390 psi
2 bbls/min = 420 psi
2.5 bbls/min = 440 psi
3 bbls/min = 460 psi
3.5 bbls/min = 490 psi, 1% f/o
4 bbls/min = 490 psi, 4% f/o initially,
increased to 11% after holding for 40
min
4.5 bbls/min = 480 psi, 14% f/o
5 bbls/min = 530 psi, 17% f/o
12,604.0 12,604.0
4/22/2023
00:00
4/22/2023
01:00
1.00 INTRM1, CEMENT CIRC P Continue to circulate thru stage collar at
7299' MD. 4 bpm = 446 psi. 14% f/o. 68
bbls loss from midnight.
Total strokes pumped = 7958.
Total pumped = 800 bbls
Total mud loss = 607 bbls
12,604.0 12,604.0
4/22/2023
01:00
4/22/2023
04:00
3.00 INTRM1, CEMENT CMNT P PJSM, Pump 2nd stage cement job as
per HES schedule. HES fill lines with
fresh water and test to 2500 psi.
Pump 80 bbls of 12.5 tuned prime
spacer. 3.5 bpm = 350 psi.
Pump 181 bbls of 15.3 ppg Class G
cement, 3.75 bpm = 280 psi. Yield 1.237
ft3/sk, WR 5.57 gal/sk
Drop plug
HES pump 10 bbls water at 3 bpm.
Swap to rig pumps:
Pump 326 bbls 11.4 ppg mud. ICP - 6
bpm = 542 psi, FCP - 3 bpm = 450 psi.
Bump plug at 3214 strokes. Pressure up
to 1600 psi and hold 5 min. Bleed off
and check floats/closing port = Good
CIP @ 04:00
12,604.0 12,604.0
4/22/2023
04:00
4/22/2023
06:00
2.00 INTRM1, CEMENT RURD P Well breathing/balooning was observed.
Closed upper pipe rams to ensure
cement is static until cured.
Blow down cement lines and clean
valves;
12,604.0 12,604.0
4/22/2023
06:00
4/22/2023
13:00
7.00 INTRM1, CEMENT WOC P Wait on cement.
L/D 5" DP from derrick with single joint
elevators. Clean mud pits.
12,604.0 12,604.0
4/22/2023
13:00
4/22/2023
15:15
2.25 INTRM1, CEMENT WWSP P Check for pressure on well = 0 psi.
Open upper pipe rams. OWFF = Static
M/U pack-off running tool. Set 7 5/8"
Pack-off in well head per Cameron Rep.
Test pack-off to 5000 psi F/10 min. =
Good test
12,604.0 12,604.0
4/22/2023
15:15
4/22/2023
16:00
0.75 INTRM1, CEMENT RURD P R/D Volant CRT. Remove all casing
equipment from rig floor.
12,604.0 12,604.0
4/22/2023
16:00
4/22/2023
19:30
3.50 INTRM1, CEMENT PULD P L/D 5" DP from derrick with single joint
elevators.
C/O upper pipe rams to 3 1/2" X 6"
VBR's
12,604.0 12,604.0
4/22/2023
19:30
4/22/2023
21:30
2.00 INTRM1, CEMENT RURD P C/O Top Drive Saver sub to XT-39. C/O
ST100 dies to 4"
12,604.0 12,604.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 24/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/22/2023
21:30
4/23/2023
00:00
2.50 INTRM1, WHDBOP RURD P R/U BOP testing equipment. Install test
plug with Cameron Rep. M/U floor
valves. Fill stack with fresh water. Flood
lines and bleed air from system. Perform
BOP shell test.
12,604.0 12,604.0
4/23/2023
00:00
4/23/2023
06:00
6.00 INTRM1, WHDBOP BOPE P Test BOPE.
Test annular to 250 psi low, 2500 psi
high, 5 min, Charted.
Test upper and lower 3-1/2" X 6" VBR's,
Blind rams, 2 floor valves, upper and
lower IBOP's, 15 choke manifold valves,
2 HCR's and 2 manual valves on stack
to 250 psi low, 4000 psi high, 5 min,
Charted.
Test manual and Super chokes to 250
psi low and 2000 psi high.
Test with 4" and 4-1/2" test joints. Test
with water.
Perform Koomey draw down test. Test
PVT gain/loss and Flow out alarms. Test
LEL and H2S gas alarms.
All tests witnessed by AOGCC state
inspector Kam St John
0.0 0.0
4/23/2023
06:00
4/23/2023
06:30
0.50 INTRM1, WHDBOP RURD P R/D test equipment. Blow down all lines
and choke manifold.
0.0 0.0
4/23/2023
06:30
4/23/2023
07:15
0.75 INTRM1, DRILLOUT WWSP P Install wear bushing per Cameron rep.
ID = 10", OD = 10.75", Length = 13".
0.0 0.0
4/23/2023
07:15
4/23/2023
08:15
1.00 INTRM1, DRILLOUT RURD P Mobilize Production BHA to rig floor. 0.0 0.0
4/23/2023
08:15
4/23/2023
12:00
3.75 INTRM1, DRILLOUT BHAH P PJSM, M/U 6-1/2" Production BHA as
per SLB DD's. to 388'
6-1/2" PDC bit, Motor, PenScope,
DigiScope, SonicScope, ADN, Stabilizer,
Well Commander, HWDP, Jars.
09:00 - SIMOPS: R/U Little Red
Services to OA for freeze protect.
0.0 388.0
4/23/2023
12:00
4/23/2023
17:00
5.00 INTRM1, DRILLOUT PULD P Pick up 4" DP and RIH F/ 388' to 3808'
MD. SOWT = 92K
Continue attempt to inject freeze protect
OA with LRS
388.0 3,808.0
4/23/2023
17:00
4/23/2023
19:00
2.00 INTRM1, DRILLOUT SRVY P Shallow test MWD tools. 245 gpm =
1550 psi. Unable to esablish
communication with tools. Blow down
TD.
18:30 - Unable to inject freeze protect
within pressure limitations. Maximum
pressure pumped = 685 psi. Volume
injected = 1.19 bbls 10.4 ppg NaBr
Brine. R/D LRS.
3,808.0 3,808.0
4/23/2023
19:00
4/23/2023
21:30
2.50 INTRM1, DRILLOUT TRIP T POOH and stand back DP from 3808' to
BHA @ 388' MD
3,808.0 388.0
4/23/2023
21:30
4/23/2023
21:45
0.25 INTRM1, DRILLOUT OWFF T OWFF, PJSM to C/O MWD tools. 388.0 388.0
4/23/2023
21:45
4/24/2023
00:00
2.25 INTRM1, DRILLOUT BHAH T Stand back HWDP. C/O DigiScope,
SonicScope, and ADN in BHA. Monitor
hole fill on trip tank
388.0 110.0
4/24/2023
00:00
4/24/2023
00:45
0.75 INTRM1, DRILLOUT TRIP T RIH from derrick F/110' to 1500' MD. 110.0 1,500.0
4/24/2023
00:45
4/24/2023
01:15
0.50 INTRM1, DRILLOUT SRVY T Perform MWD shallow test per SLB DD.
230 gpm = 1320 psi. Good test.
1,500.0 1,500.0
4/24/2023
01:15
4/24/2023
03:00
1.75 INTRM1, DRILLOUT TRIP T RIH F/1500' to 3987' MD. SOWT = 85K 1,500.0 3,987.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 25/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/24/2023
03:00
4/24/2023
03:30
0.50 INTRM1, DRILLOUT SRVY P Establish pump rate for logging tool
operation. Send downlink for tool
configuration. 230 gpm = 1450 psi.
3,987.0 3,987.0
4/24/2023
03:30
4/24/2023
05:00
1.50 INTRM1, DRILLOUT DLOG P Log 2nd stage cement F/3987' to 4361'
MD. 230 gpm = 1450 psi. Log down at
450 fph. SOWT = 88K.
3,987.0 4,361.0
4/24/2023
05:00
4/24/2023
05:30
0.50 INTRM1, DRILLOUT TRIP P POOH F/4361' to 3987' MD in search of
cement free/ringing pipe. PUWT = 88K
4,361.0 3,987.0
4/24/2023
05:30
4/24/2023
08:15
2.75 INTRM1, DRILLOUT DLOG P Log up hole F/3987' to 3320' MD. 230
gpm = 1479 psi.
3,987.0 3,320.0
4/24/2023
08:15
4/24/2023
09:00
0.75 INTRM1, DRILLOUT TRIP P RIH F/3320' to 4270' MD. 3,320.0 4,270.0
4/24/2023
09:00
4/24/2023
12:00
3.00 INTRM1, DRILLOUT DLOG P Log 2nd stage cement at 450 fph,
F/4270' to 5075' MD. 225 gpm = 1590
psi.. SOWT = 90K.
4,270.0 5,075.0
4/24/2023
12:00
4/24/2023
19:30
7.50 INTRM1, DRILLOUT DLOG P Log 2nd stage cement at 800 fph,
F/5075' to 7205' MD. 225 gpm = 1590
psi.. SOWT = 90K.
5,075.0 7,205.0
4/24/2023
19:30
4/24/2023
20:30
1.00 INTRM1, DRILLOUT PRTS P R/U to test Stage tool integrity. Close
pipe rams and test casing and stage tool
to 1600 psi, 10 min, charted = Good
test. R/D test equipment
7,205.0 7,205.0
4/24/2023
20:30
4/24/2023
21:00
0.50 INTRM1, DRILLOUT WASH P Wash down F/7205' and tag top of
Stage collar plug at 7299' MD.
7,205.0 7,299.0
4/24/2023
21:00
4/24/2023
21:30
0.50 INTRM1, DRILLOUT DRLG P Drill out Stage collar cement plug
F/7299' to 7302' MD. per SLB DD. 230
gpm = 1950 psi. WOB = 10K, 40 RPM =
4 - 14K TQ. PUWT = 106K, SOWT =
93K, ROTW = 100K
7,299.0 7,302.0
4/24/2023
21:30
4/24/2023
22:30
1.00 INTRM1, DRILLOUT CIRC P CBU 1X R&R DP thru collar to ensure
clean. 230 gpm = 1760 psi. See rubber
and clabbered cement at shakers on
BU.
7,302.0 7,302.0
4/24/2023
22:30
4/25/2023
00:00
1.50 INTRM1, DRILLOUT DLOG P Log 1st stage cement at 450 fph,
F/7302' to 7582' MD. 225 gpm = 1590
psi.. SOWT = 90K. Unable to wash
down due to cement stringers. ROTW =
101K, 20 RPM = 5 - 6K TQ
7,302.0 7,582.0
4/25/2023
00:00
4/25/2023
12:00
12.00 INTRM1, DRILLOUT DLOG P Log 1st stage cement at 450 fph, F/
7852' MD to 11,280' MD @ 700 fph. 230
gpm - 2300 psi. 25% f/o, SOWT - 84K.
Unable to wash down due to cement
stringers.
7,852.0 11,280.0
4/25/2023
12:00
4/25/2023
17:00
5.00 INTRM1, DRILLOUT REAM P Ream in the hole f/ 11,280' MD to
12,476' MD w/ 230 gpm, 2,450 psi, 25%
f/o, 25 rpm, 6.5k tq, rot wt - 118k. Tag
baffle collar at 12,476' md w/ 5k dn wt.
11,280.0 12,476.0
4/25/2023
17:00
4/25/2023
18:00
1.00 INTRM1, DRILLOUT TRIP P POOH f/ 12,476' MD to 11,275' MD.
Monitor disp via tt, up wt - 151k.
12,476.0 11,275.0
4/25/2023
18:00
4/25/2023
23:00
5.00 INTRM1, DRILLOUT DLOG P Log 1st stage cement at 700 fph, F/
11,275' MD to 12,474' MD w/ 230 gpm -
2253 psi, 25% f/o. PUWT - 150K SOWT
- 86K.
11,275.0 12,474.0
4/25/2023
23:00
4/26/2023
00:00
1.00 INTRM1, DRILLOUT SLPC P Cut and slip 88' of 1.375" drill line.
Simops - circ @ 230 gpm, 2175 psi,
25% f/o. Total bbls pumped - 277.
12,474.0 12,474.0
4/26/2023
00:00
4/26/2023
00:30
0.50 INTRM1, DRILLOUT SLPC P Continue to cut and slip 88' of 1.375"
drill line. Simops - circ @ 230 gpm,
2175 psi, 25% f/o. Total bbls pumped -
233.
12,474.0 12,474.0
4/26/2023
00:30
4/26/2023
03:00
2.50 INTRM1, DRILLOUT PRTS P B/D TD. R/U to test csg. Test csg to
4,000 psi for 30 charted min (good). 8
bbls to pressure up and 8 bbls bled
back.
12,474.0 12,474.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 26/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/26/2023
03:00
4/26/2023
03:45
0.75 INTRM1, DRILLOUT DRLG P Drill out baffle collar f/ 12,476' MD to
12,479' MD w/ 230 gpm, 2252 psi, 9k tq,
4k wob, 40 rpm, 27% f/o.
12,474.0 12,479.0
4/26/2023
03:45
4/26/2023
04:30
0.75 INTRM1, DRILLOUT DRLG P Drill cement and float collar f/ 12,479'
MD to 12,521' MD w/ 230 gpm, 2248
psi, 27% f/o, 40 rpm, 9k tq, 5k wob.
12,479.0 12,521.0
4/26/2023
04:30
4/26/2023
06:00
1.50 INTRM1, DRILLOUT DRLG P Drill cement, shoe and rat hole f/ 12,521'
MD to 12,611' MD w/ 230 gpm, 2207
psi, 80 rpm, 9-10k tq, 2-6k wob. Work
through shoe at 12,604' md 3x. Up wt -
110k, s/o wt - 116k
12,521.0 12,611.0
4/26/2023
06:00
4/26/2023
06:30
0.50 INTRM1, DRILLOUT DDRL P Drill 6½ production hole f/ 12,611' MD to
12,631' MD w/ 250 gpm, 2490 psi, 28%
f/o, 80 rpm, 10k tq, 3k wob, 12.14 ecd.
Up wt - 110k, s/o wt - 116k, rot wt - 110k.
12,611.0 12,631.0
4/26/2023
06:30
4/26/2023
09:45
3.25 INTRM1, DRILLOUT CIRC P Rot and recip pipe f/ 12,631' MD to
12,595' MD and condition mud for FIT.
Circ at 250 gpm, 2410 psi, 30% f/o, 20
rpm, 9k tq, 12.06 ecd. Pump hi vis
sweep s/s. Total bbls pumped - 1060.
12,631.0 12,595.0
4/26/2023
09:45
4/26/2023
11:15
1.50 INTRM1, DRILLOUT FIT P Rig up and FIT to 14.5 ppg emw.
Pressure up to 1080 psi w/ 2.4 bbls
pumped. Test w/ 11.0 ppg mud. 2 bbls
bled back.
12,595.0 12,595.0
4/26/2023
11:15
4/26/2023
11:30
0.25 INTRM1, DRILLOUT RURD P B/D and R/D test equipment. 12,595.0 12,595.0
4/26/2023
11:30
4/26/2023
12:45
1.25 PROD1, DRILL MPDA P PJSM, pull trip nipple and install 4" mpd
bearing.
12,595.0 12,595.0
4/26/2023
12:45
4/26/2023
16:15
3.50 PROD1, DRILL DISP P Displace well to 9.5 ppg FloPro.
Maintain 11.0 emw per MPD. ICP at
230 gpm w/ 2700 psi. FCP - 230 gpm,
2141 psi. Rot and recip pipe f/ 12,595'
MD to 12,631' MD.
12,595.0 12,595.0
4/26/2023
16:15
4/26/2023
17:15
1.00 PROD1, DRILL OWFF P OWFF per MPD drawdown procedure.
Observe well to be static w/ 9.5 ppg.
12,595.0 12,595.0
4/26/2023
17:15
4/26/2023
18:00
0.75 PROD1, DRILL REAM P Wash and ream to btm f/ 12,595' MD to
12,631' MD sending downlinks per DDX
w/ 250 gpm, 2450 psi, 30% f/o, 10.94
ecd, 60 rpm, 9k tq,
12,595.0 12,631.0
4/26/2023
18:00
4/27/2023
00:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 12,631' MD to
12,985' MD, 5,938' TVD w/ 270 gpm,
2722 psi, 29% f/o, 11.15 ecd, 120 rpm,
11k tq, Up wt - 152k, s/o wt - 87k, rot wt
- 111k
12,631.0 12,985.0
4/27/2023
00:00
4/27/2023
06:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 12,985' MD to
12,986' MD, 5,938' TVD w/ 230 gpm,
2034 psi, 5k wob, 31% f/o, 10.85 ecd,
100 rpm, 10k tq, Up wt - 152k, s/o wt -
87k, rot wt - 111k
12,985.0 12,986.0
4/27/2023
06:00
4/27/2023
08:30
2.50 PROD1, DRILL DDRL P Drill 6½ production hole f/ 12,986' MD to
13,075' MD, 5,947' TVD w/ 270 gpm,
2600 psi, 31% f/o, 4k wob, 10.95 ecd,
120 rpm, 11k tq, Up wt - 133k, s/o wt -
92k, rot wt - 113k
12,986.0 13,075.0
4/27/2023
08:30
4/27/2023
09:30
1.00 PROD1, DRILL BKRM P BROOH to wipe 8.44° DLS f/ 13,075'
MD to 12,880' MD w/ 270 gpm, 2560
psi, 31% f/o, 100 rpm, 10.5k tq, 10.83
ecd, 114k rot wt. 8.44° DLS @ 12,909'
MD.
13,075.0 12,880.0
4/27/2023
09:30
4/27/2023
10:15
0.75 PROD1, DRILL REAM P Wash and ream f/ 12,288' MD to 13,075'
md w/ 270 gpm, 2590 psi, 33% f/o, 90
rpm, 10k tq, 115k s/o wt.
12,880.0 13,075.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 27/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/27/2023
10:15
4/27/2023
12:00
1.75 PROD1, DRILL DDRL P Drill 6½ production hole f/ 13,075 MD to
13,165' MD, 5,944' TVD w/ 270 gpm,
2600 psi, 31% f/o, 6k wob, 10.97 ecd,
100 rpm, 11k tq, Up wt - 136k, s/o wt -
104k, rot wt - 115k
13,075.0 13,165.0
4/27/2023
12:00
4/27/2023
18:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 13,165 MD to
13,635' MD, 5,951' TVD w/ 270 gpm,
2740 psi, 31% f/o, 8k wob, 11.24 ecd,
120 rpm, 11k tq, Up wt - 154k, s/o wt -
90k, rot wt - 125k
13,165.0 13,635.0
4/27/2023
18:00
4/28/2023
00:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 13,635 MD to
14,110' MD, 5,946' TVD w/ 270 gpm,
2798 psi, 33% f/o, 8k wob, 11.33 ecd,
120 rpm, 12k tq, Up wt - 156k, s/o wt -
85k, rot wt - 120k
13,635.0 14,110.0
4/28/2023
00:00
4/28/2023
06:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 14,110' MD to
14,398' MD, 5,953' TVD w/ 270 gpm,
2887 psi, 30% f/o, 8k wob, 11.15 ecd,
120 rpm, 11k tq, Up wt - 150k, s/o wt -
89k, rot wt - 117k
14,110.0 14,398.0
4/28/2023
06:00
4/28/2023
12:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 14,398' MD to
14,656' MD, 5,953 TVD w/ 270 gpm,
2770 psi, 30% f/o, 8k wob, 11.15 ecd,
80 rpm, 11k tq, Up wt - 155k, s/o wt -
81k, rot wt - 122k.
Simops. Freeze protect 10.75 x 7.625
OA via LRS @ 06:00 hrs. Pt lines to
2500 psi (good) Pressure up to 1000
psi @ .25 bpm, 1.35 bbls pumped.
Pressure up to 1300 psi @ .25 bpm
additional .97 bbls pumped. Pressure
up to 1350 and observe formation
injection. Observe psi drop to 635 in 3
min. Pump 69 bbls of 10.4 ppg brine
from vac truck. ICP - 800 at .25 bpm,
FCP - 825 @ 1.5 bpm. Pump 20 bbls of
diesel ICP - 780 @ 1.5 bpm, FCP - 847
@ 1.5 bpm. Shut OA in at 07:36 hrs.
Exceeded surface casing shoe LOT as
per risk assessment.
Post freeze protect, pressure bleed off
and stabalized at 533 psi on OA.
EMW @ surface casing shoe 13.65
PPG
EMW @ tabasco 10.1 PPG
14,398.0 14,656.0
4/28/2023
12:00
4/28/2023
18:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 14,656' MD to
14,905' MD, 5,954' TVD w/ 240 gpm,
2324 psi, 22% f/o, 8k wob, 11.06 ecd,
100 rpm, 11k tq, Up wt - 167k, s/o wt -
67k, rot wt - 118k
Encounter fault @ 14,736' MD and
observe 100% losses. Losses
decreased to ~70 bph. Begin to pump
30 bbl 35 ppb LCM sweeps every stand.
14,656.0 14,905.0
4/28/2023
18:00
4/29/2023
00:00
6.00 PROD1, DRILL DDRL P Continue to drill 6½ production hole w/
~70 pbh losses f/ 14,905' MD to 15,310'
MD, 5,950' TVD w/ 240 gpm, 2400 psi,
25% f/o, 7k wob, 11.13 ecd, 100 rpm,
11k tq, Up wt - 171k, s/o wt - N/A, rot wt
- 111k. Continue to pump 30 bbl 35 ppb
LCM sweeps every stand.
Total formation losses in the last 24
hours - 897 bbls
14,905.0 15,310.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 28/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/29/2023
00:00
4/29/2023
06:00
6.00 PROD1, DRILL DDRL P Drill 6½ production hole f/ 15,310' MD to
15,600' MD, 5,954 TVD w/ 240 gpm,
2380 psi, 27% f/o, 6k wob, 11.02 ecd,
100 rpm, 12k tq, Up wt - 172k, s/o wt -
n/a, rot wt - 118k. Continue to pump 40
bbl 35 ppb LCM sweeps every stand w/
loss rate of ~70 bph.
15,310.0 15,600.0
4/29/2023
06:00
4/29/2023
09:45
3.75 PROD1, DRILL DDRL P Drill 6½ production hole f/ 15,600' MD to
15,814' MD, 5,952 TVD w/ 240 gpm,
2457 psi, 25% f/o, 9k wob, 11.15 ecd,
100 rpm, 12k tq, Up wt - 171k, s/o wt -
n/a, rot wt - 120k. Continue to pump 40
bbl 35 ppb LCM sweeps every stand w/
loss rate of ~70 bph.
15,600.0 15,814.0
4/29/2023
09:45
4/29/2023
10:15
0.50 PROD1, DRILL BKRM T Decision to BROOH and open well
commander to pump ProCor LCM pill to
help heal losses. BROOH f/ 15,814' MD
to 15,716' MD w/ 240 gpm, 2470 psi,
25% f/o, 100 rpm, 10k tq, 11.15 ecd,
117k up wt.
15,814.0 15,716.0
4/29/2023
10:15
4/29/2023
13:00
2.75 PROD1, DRILL CIRC T Drop 1.75 OD ball to open well
commander. Rot and recip pipe w/ 20
rpm, 8k tq, f/ 15,716' MD to 15,622' MD
and pump ball down down w/ 85 gpm,
780 psi, 21% f/o. Ball on seat @ 1135
stks. Pressure up in 500 psi increments
to shear open well commander. Observe
open at 2,500 psi. Drop 1.698" OD BHA
isolation ball. Pump ball at 85 gpm, 590
psi, 20% f/o. No indication of ball on
seat. Only indication of BHA isolation
was loss of communication w/ BHA at
higher flow rate of 271 gpm and 1445
psi.
15,716.0 15,716.0
4/29/2023
13:00
4/29/2023
15:30
2.50 PROD1, DRILL CIRC T Pump 70 bbls of 50 ppb ProCor LCM pill
while rot and recip f/ 15,716' MD to
15,622' MD w/ 210 gpm, 1200 psi, 33%
f/o, 20 rpm, 9k tq, Up wt - 124k, s/o wt -
114k, rot wt - 122k. No improvment wtih
first ProCor pill sweeping across the
hole. Loss rate contimued at ~70bph.
Decision made to pump 2nd pill and
squeeze into loss zone.
15,716.0 15,716.0
4/29/2023
15:30
4/29/2023
17:30
2.00 PROD1, DRILL CIRC T Pump 2nd ProCor pill same size and
rate. Spot in open hole from TD to inside
7-5/8" csg shoe. Line up MPD to
Dynamically squeeze across top hole.
Stage up EMW to 10.7 ppg with no
losses. Stage up to 11,2 ppg EMW with
no losses. Stage up to 11.6 ppg EMW
with slight losses. Stage up to 12.0 ppg
EMW and losses increased significantly.
Decrease back pressure back to 10.7
ppg EMW and observe well bore
balanced. No losses and no signs of
ballooning. Monitor well for 5 minutes
and no changes. Repeat staging up
EMW to 11.6 ppg EMW and observe
minimal losses. Decision made to
resume drilling ahead with 10.7 ppg
EMW on connections and 11.6 ppg ECD
while drilling ahead. Squeezed total of
36 bbls ProCore into loss zone.
15,716.0 15,716.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 29/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/29/2023
17:30
4/29/2023
18:00
0.50 PROD1, DRILL CIRC T Drop 1.75" OD ball and close well
commander and open bypass to BHA.
Continue to rot and recip and pump ball
down at 85 gpm, 595 psi, 27% f/o, 20
rpm, 8k tq. Ball on seat @ 1241 stks.
Pressure up to 2340 psi and observe
shift close and pressure reduce to 585.
Confirm w/ 233 gpm, 2180 psi, 29% f/o
and obsesrve coms with BHA.
15,716.0 15,716.0
4/29/2023
18:00
4/29/2023
18:15
0.25 PROD1, DRILL REAM T Wash and ream f/ 15,716' MD to 15,814'
MD w/ 230 gpm, 2240 psi, 255 f/o,
10.85 ecd, 50 rpm, 8k tq, rot wt - 117k
15,716.0 15,814.0
4/29/2023
18:15
4/30/2023
00:00
5.75 PROD1, DRILL DDRL P Drill 6½ production hole f/ 15,814' MD to
15,975' MD, 5,958 TVD w/ 270 gpm,
2840 psi, 30% f/o, 3k wob, 11.15 ecd,
80 rpm, 9.5k tq, Up wt - 163k, s/o wt -
n/a, rot wt - 118k. MPD holding 10.7
emw at connections. Continue to pump
40 bbl 35 ppb LCM sweeps every stand
w/ loss rate of ~60 bph.
Total formation losses in the last 24
hours = 1,314 bbls
15,814.0 15,975.0
4/30/2023
00:00
4/30/2023
06:00
6.00 PROD1, DRILL DDRL P Time drill 6½ production hole attempting
to build inclination from 88° to 90.5° f/
15,975' MD to 16,050' MD, 5,963 TVD
w/ 230 gpm, 2360 psi, 23% f/o, 2-4k
wob, 11.15 ecd, 80 rpm, 9.5k tq, Up wt -
163k, s/o wt - n/a, rot wt - 118k. MPD
holding 10.7 emw(300 psi) at
connections. Pump 1ea 40 bbl 35 ppb
LCM sweep at top of stand(15,911' MD)
w/ loss rate of ~60 bph.
15,975.0 16,050.0
4/30/2023
06:00
4/30/2023
12:00
6.00 PROD1, DRILL DDRL P Time drill 6½ production hole attempting
to build inclination from 88° to 90.5° f/
16,050' MD to 16,063' MD, 5,953 TVD
w/ 250 gpm, 2653 psi, 30% f/o, 4-6k
wob, 11.28 ecd, 100 rpm, 9k tq, Up wt -
163k, s/o wt - n/a, rot wt - 118k. MPD
holding 10.7 emw(300 psi) at
connections. Loss rate at interval is 38
hr.
16,050.0 16,063.0
4/30/2023
12:00
4/30/2023
18:00
6.00 PROD1, DRILL DDRL P Time drill 6½ production hole attempting
to build inclination from 88° to 90.5° f/
16,063' MD to 16,083' MD, 5,960 TVD
w/ 250 gpm, 2680 psi, 30% f/o, 4k wob,
11.42 ecd, 100 rpm, 10k tq, Up wt -
163k, s/o wt - n/a, rot wt - 118k. MPD
holding 10.7 emw(300 psi) at
connections. Loss rate at interval is 38
hr.
16,063.0 16,083.0
4/30/2023
18:00
5/1/2023
00:00
6.00 PROD1, DRILL DDRL P Time drill 6½ production hole attempting
to build inclination from 88° to 90.5° f/
16,083' MD to 16,095' MD, 5,961 TVD
w/ 250 gpm, 2650 psi, 30% f/o, 4k wob,
11.43 ecd, 100 rpm, 10k tq, Up wt -
163k, s/o wt - n/a, rot wt - 118k. MPD
holding 10.7 emw(300 psi) at
connections. Loss rate at interval is 46
hr.
Total formation losses in the last 24
hours = 1070 bbls
16,083.0 16,095.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 30/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/1/2023
00:00
5/1/2023
06:00
6.00 PROD1, DRILL DDRL P Time drill 6½" production hole
attempting to build inclination from 88°
to 90.5° f/ 16,095' MD to 16,098' MD,
5,961 TVD w/ 250 gpm, 2670 psi, 30%
f/o, 2k wob, 11.37 ecd, 80 rpm, 8k tq, Up
wt - 163k, s/o wt - n/a, rot wt - 118k.
MPD holding 10.7 emw(300 psi) at
connections. Loss rate at interval is 30
hr.
16,095.0 16,098.0
5/1/2023
06:00
5/1/2023
11:30
5.50 PROD1, DRILL DDRL P Drill 6½" production hole f/ 16,098 MD
to 16,186' MD, 5,968 TVD w/ increased
gpm @292, 3369 psi, 30% f/o, 12k wob,
11.45 ecd, 80 rpm, 11k tq, Up wt - 163k,
s/o wt - n/a, rot wt - 118k. Oobserve
inclination build f/ 87.74° to 89.88°.
Decision made to conduct a drawdown
via MPD procedure.
16,098.0 16,186.0
5/1/2023
11:30
5/1/2023
12:00
0.50 PROD1, DRILL OWFF P Conduct a wellbore drawwdown via
MPD procedure. Targeting 14,736' MD /
5,952' MD. Line up MPD across the top
of the hole and trap 10.7 ppg emw.
Bleed off pressure for 30 sec, shut in
MPD chokes, and monitor pressure
build for 5 min. Repeat 5x. Observe
pressure build to 300 psi and bleed to
282 psi after 5 min at each cycle. Bled
back 7.3 bbls of 9.7 ppg floPro,
confirming 10.7 emw is kwf.
16,186.0 16,186.0
5/1/2023
12:00
5/1/2023
14:30
2.50 PROD1, DRILL CIRC P Circ b/u and pump 35 bbls of 35 ppb
LCM sweep. Rot and recip f/ 16,186'
MD to 16,089' MD, w/ 230 gpm, 2400
psi, 29% f/o, 80 rpm, 9k tq, 11.33 ecd,
rot wt while circ - 114k. Observe 9200
usits max gas on b/u.
16,186.0 16,186.0
5/1/2023
14:30
5/1/2023
18:00
3.50 PROD1, DRILL DDRL P Drill 6½" production hole f/ 16,186 MD
to 16,403' MD, 5,964 TVD w/ 290 gpm,
3253 psi, 30% f/o, 11k wob, 11.58 ecd,
100 rpm, 11k tq, Up wt - 165k, s/o wt -
n/a, rot wt - 116k. MPD holding 10.7
emw(300 psi) at connections. Loss rate
at interval - 80hr
16,186.0 16,403.0
5/1/2023
18:00
5/2/2023
00:00
6.00 PROD1, DRILL DDRL P Drill 6½" production hole geosteering f/
16,403' MD to 16,792' MD, 5,964 TVD
w/ 250 gpm, 2780 psi, 30% f/o, 2-4k
wob, 11.54 ecd, 100 rpm, 12.5k tq, Up
wt - 175k, s/o wt - n/a, rot wt - 119k.
MPD holding 10.7 emw(300 psi) at
connections.Drill 6½" production hole f/
16,186 MD to 16,403' MD, 5,964 TVD w/
290 gpm, 3253 psi, 30% f/o, 11k wob,
11.58 ecd, 100 rpm, 11k tq, Up wt -
165k, s/o wt - n/a, rot wt - 116k. Loss
rate at interval - 80hr Loss rate at
interval is 20-40 hr.
Total formation losses in the last 24
hours = 630 bbls
16,403.0 16,792.0
5/2/2023
00:00
5/2/2023
06:00
6.00 PROD1, DRILL DDRL P Drill 6½" production hole f/ 16,403' MD
to 17,020' MD, 5,942 TVD w/ 250 gpm,
2780 psi, 30% f/o, 12k wob, 11.54 ecd,
100 rpm, 13k tq, Up wt - 181k, s/o wt -
n/a, rot wt - 122k. MPD holding 10.7
emw(300 psi) at connections. Loss rate
at interval - 25hr
16,792.0 17,070.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 31/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/2/2023
06:00
5/2/2023
11:30
5.50 PROD1, DRILL DDRL P Drill 6½" production hole f/ 17,020' MD
to 17,235' MD, 5,952 TVD w/ 250 gpm,
2817 psi, 30% f/o, 12k wob, 11.65 ecd,
100 rpm, 13k tq, Up wt - 193k, s/o wt -
n/a, rot wt - 123k. MPD holding 10.7
emw(300 psi) at connections. Loss rate
at interval - 25hr
17,020.0 17,235.0
5/2/2023
11:30
5/2/2023
12:00
0.50 PROD1, DRILL DDRL T Observe tools out of sync. Cycle pumps
as per SLB reps and failed to regain
coms. Observe total loss of coms with
DigiScope. Decision made to call TD @
17,235' MD and come out of the hole.
17,235.0 17,235.0
5/2/2023
12:00
5/2/2023
16:00
4.00 PROD1, TRIPCAS BKRM P Circulate and condition hole for trip out.
BROOH f/ 17,235' MD to 16,737' MD
standing back 1 std per bottoms up.
Circ at 230 gpm, icp - 2319, fcp - 2288,
30% f/o, 80 rpm, 12k tq. SIMOPS -
Build 27 stds 4" HWDP via 90'
mousehole.
17,235.0 16,737.0
5/2/2023
16:00
5/2/2023
17:00
1.00 PROD1, TRIPCAS BKRM P Cont to circ and cond while BROOH f/
16,737' MD to 16,645' MD and spot 70
bbls 35 ppb LCM pill in the open hole
across the fault at 14,736' w/ 230 gpm,
2319 psi, 30% f/o, 80 rpm, 12k tq. B/D
the top drive.
16,737.0 16,645.0
5/2/2023
17:00
5/3/2023
00:00
7.00 PROD1, TRIPCAS SMPD P Strip out of the hole f/ 16,645' MD to
14,390' MD following MPD stripping
schedule. Keeping 10.9 emw.(610 psi
dynamic and 380 static). p/u wt - 173k
Total formation losses in the last 24
hours = 416bbls
16,645.0 14,390.0
5/3/2023
00:00
5/3/2023
02:45
2.75 PROD1, TRIPCAS SMPD P Strip out of the hole f/ 14,390' MD to
13,072' MD following MPD stripping
schedule. Keeping 10.9 emw.(610 psi
dynamic and 380 static). p/u wt - 164k.
14,390.0 13,072.0
5/3/2023
02:45
5/3/2023
04:00
1.25 PROD1, TRIPCAS PMPO P Observe erratic choke swings. Decision
made to pump out of the hole up into the
7 5/8" csg shoe f/ 13,072' MD t/ 12,598'
MD. Pump OOH w/ 230, 1820 psi, 30%
f/o, up wt - 164k
13,072.0 12,598.0
5/3/2023
04:00
5/3/2023
07:00
3.00 PROD1, TRIPCAS CIRC P Circulate 7 5/8" cgs clean by rot and
recipe pipe f/ 12,598' MD to 12,503' MD
w/ 245 gpm, 2090 psi, 30% f/o, 20 rpm,
6k tq, rot wt - 115k. Total stks - 11,405
(1149 bbls). SIMOPS - open MPD
chokes and find hard rubber piece
(possibly from shoe track).
12,598.0 12,598.0
5/3/2023
07:00
5/3/2023
12:00
5.00 PROD1, TRIPCAS DISP P Cont to rot and recip pipe and displace
well bore to 10.9 ppg tripping brine.
Pump 70 bbls of 9.7 ppg FloPro hi-vis
spacer, chased by 618 bbls of 10.9 ppg
brine w/ 200 pm, 1350 psi, 30% f/o, 10
rpm, 5k tq, rot up wt - 119k, rot w/owt -
110k. Pump additional s/s to ensure
even mw in/out. Total stks pumped -
6,861(691 bbls)
12,598.0 12,598.0
5/3/2023
12:00
5/3/2023
12:30
0.50 PROD1, TRIPCAS OWFF P OWFF (static). B/D the top drive. Line
up on the MPD system for stripping.
Drop 2.37" OD steel rabbit on 102' steel
line.
12,598.0 12,598.0
5/3/2023
12:30
5/3/2023
14:30
2.00 PROD1, TRIPCAS SMPD P Strip OOH f/ 12,598' MD to 10,945' MD.
Up wt - 150k. Monitor disp via pit #1.
Circ across top of the hole @ 106 gpm,
with MPD chokes 100% open.
12,598.0 10,945.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 32/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/3/2023
14:30
5/3/2023
15:00
0.50 PROD1, TRIPCAS SFTY P BOP drill - Kick while tripping CRT - 96
sec. Conduct safety stand down to
inspect 4" handling equipment.
10,945.0 10,945.0
5/3/2023
15:00
5/3/2023
23:15
8.25 PROD1, TRIPCAS SMPD P Strip OOH f/ 10,945' MD to 867' MD.
Up wt - 70k. Monitor disp via pit #1. Circ
across top of the hole @ 106 gpm, with
MPD chokes 100% open. Recover
2.37" OD rabbit
10,945.0 897.0
5/3/2023
23:15
5/3/2023
23:45
0.50 PROD1, TRIPCAS OWFF P OWFF (static) - SIMOPS - PJSM on
pulling MPD bearing and install strip
nipple.
897.0 897.0
5/3/2023
23:45
5/4/2023
00:00
0.25 PROD1, TRIPCAS MPDA P Pull MPD Bearing.
Total formation losses in the last 24
hours = 353 bbls
897.0 897.0
5/4/2023
00:00
5/4/2023
01:00
1.00 PROD1, TRIPCAS MPDA P Continue to pull MPD bearing and install
trip nipple.
897.0 897.0
5/4/2023
01:00
5/4/2023
04:00
3.00 PROD1, TRIPCAS BHAH P PJSM, L/D production BHA as per
DD/MWD. Std back 2 stds of 4" HWDP.
Observe a smooth lower stabilizer on
the SonicScope and a chip out of the
SonicScope receiver. Pics located in
Maxwell JOB1@2022_DRL > 10report >
D142 files > Pictures > Production BHA
897.0 0.0
5/4/2023
04:00
5/4/2023
04:45
0.75 PROD1, TRIPCAS BHAH P Clean and clear rig floor. Monitor
wellbore via TT.
0.0 0.0
5/4/2023
04:45
5/4/2023
06:00
1.25 PROD1, WHDBOP WWWH P Flush BOP stack w/ 730 gpm, 120 psi.
B/D the top drive.
0.0 0.0
5/4/2023
06:00
5/4/2023
07:30
1.50 PROD1, WHDBOP RURD P Pull wear bushing and install test plug
via CIW reps. SIMOPS - R/U to fill 7
5/8" below test plug during BOPE test.
0.0 0.0
5/4/2023
07:30
5/4/2023
09:00
1.50 PROD1, WHDBOP RURD P Flush lines and rig up to test BOPE.
Shell test BOPE (good).
0.0 0.0
5/4/2023
09:00
5/4/2023
15:00
6.00 PROD1, WHDBOP BOPE P Test BOPEto 250 low, 4,000 high for 5/5
charted min. w/ the exception of the
manual operated & super choke tested
to 2,500 psi, and the annular to 250 low,
2,500 high for 5/5 charted min. With the
4" test jt, test annular, 3½" x 6" upr and
lpr. With the 4½ " test jt test,4" test jt,
test annular, 3½" x 6" upr and lpr, choke
valves 1-15, manual operated and super
choke, choke & kill manuals and HCR's,
4" kill line, 4" FOSV (x2), 4" dart valve.
Perform koomey drawdown - acc - 3000
psi, manifold - 1600 psi, acc - 1750 after
all functions, 9 sec for 200 psi build w/ 2
elec pumps, 59 sec to build full system
psi w/ 2 elec pumps and 2 air pumps.
Closing times for annular - 9 sec, upr - 7
sec, blind / shears - 10 sec, lpr - 7 sec,
choke HCR - 2 sec, kill HCR - 2 sec. 6
bottle nitrogen backup ave. - 1991 psi.
Test PVTgain/loss and flow out alarms.
Test LEL and H2S alarms. AOGCC rep
Austin McLeod waived witness to the
test.
0.0 0.0
5/4/2023
15:00
5/4/2023
17:00
2.00 PROD1, WHDBOP RURD P Rig down and blow down test
equipment / lines. SIMOPS - p/u frac
sleeves, 125 ea arsenal centralizers,
and xo for liner run.
0.0 0.0
5/4/2023
17:00
5/4/2023
17:30
0.50 PROD1, WHDBOP RURD P Pull tst plug and install wear ring per
CIW. ID - 10", OD - 10¾", length - 13".
0.0 0.0
5/4/2023
17:30
5/4/2023
18:30
1.00 COMPZN, CASING RURD P Rig up to run 4½" 12.6# P-110S Hyd563
lower completion.
0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 33/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/4/2023
18:30
5/5/2023
00:00
5.50 COMPZN, CASING PUTB P P/U 4½" 12.6# P-110S Hyd563 lower
completion as per detail to 2,500' MD.
Tq to 5600 ft/lbs. Top fill pipe on the fly
and top off every 10 jts. Monitor disp via
pit #6. s/o wt - 78k.
0.0 2,500.0
5/5/2023
00:00
5/5/2023
03:00
3.00 COMPZN, CASING PUTB P P/U 4½" 12.6# P-110S Hyd563 lower
completion as per detail to 4,753 MD.
Tq to 5600 ft/lbs. Top fill pipe on the fly
and top off every 10 jts. Monitor disp via
pit #6. Up wt - 84 s/o wt - 71k.
2,500.0 4,753.0
5/5/2023
03:00
5/5/2023
04:00
1.00 COMPZN, CASING OTHR P Pick up liner hanger/pkr assy as per
Baker rep. Fill w/ PalMix. Kelly up to
std #1 of 4" DP and RIH to 4,802' MD.
SIMOPS - R/D Doyon Csg equipment.
4,753.0 4,802.0
5/5/2023
04:00
5/5/2023
05:30
1.50 COMPZN, CASING MPDA P Pull trip nipple and install MPD bearing. 4,802.0 4,802.0
5/5/2023
05:30
5/5/2023
06:30
1.00 COMPZN, CASING CIRC P Break circ to insure clear fluid path
through MPD chokes and liner string.
SIMOPS - Obtain T&D values - Up wt -
85k, s/o wt - 65k, rot wt - 84k w/2k tq @
20 rpm. B/D TD.
4,802.0 4,802.0
5/5/2023
06:30
5/5/2023
12:00
5.50 COMPZN, CASING RUNL P Strip in the hole maintaining 10.7 ppg
EMW as per Beyond w/ 4½" 12.6# P-
110S Hyd563 lower completion on 4"
DP f/ 4,802' MD to 12,570' MD. Fill
every 20 stds, s/o wt - 78k. Monitor
disp on pit #6.
4,802.0 12,570.0
5/5/2023
12:00
5/5/2023
20:00
8.00 COMPZN, CASING DISP P Displace wellbore from 10.7 ppg brine to
9.7 ppg FloPro at 12,570' MD.
Displaced with 110 gpm, 738-650 psi,
17% f/o. Take T&D with 144k up wt, 88k
s/o wt, 116k rot wt @ 20 rpm w/ 5k tq.
Total bbls pumped - 686. Save 450 bbls
10.9 in pits. Observe 140 bbls of
interface, losing 96 bbls to formation.
12,570.0 12,570.0
5/5/2023
20:00
5/6/2023
00:00
4.00 COMPZN, CASING RUNL P Continue to strip in the hole maintaining
10.7 ppg EMW as per Beyond w/ 4½"
12.6# P-110S Hyd563 lower completion
on 4" DP and 4" HWDP f/ 12,570' MD to
17,000' MD, FIll pipe every 20 stds, s/o
wt - 80k Monitor disp on pit #6.
12,570.0 17,000.0
5/6/2023
00:00
5/6/2023
00:30
0.50 COMPZN, CASING RUNL P Continue to strip in the hole maintaining
10.7 ppg EMW as per Beyond w/ 4½"
12.6# P-110S Hyd563 lower completion
on 4" DP and 4" HWDP f/ 17,000' MD to
17,181' MD, FIll pipe every 20 stds, s/o
wt - 80k Monitor disp on pit #6.
17,000.0 17,181.0
5/6/2023
00:30
5/6/2023
01:00
0.50 COMPZN, CASING RUNL P P/U 15' pup. Wash down f/ 17,181' MD
to 17,235' MD at 50 gpm, 350 psi, 12%
f/o. Tag btm w/ 10k dn wt to confirm on
bottom.
17,181.0 17,235.0
5/6/2023
01:00
5/6/2023
03:30
2.50 COMPZN, CASING CIRC P P/U to 17,230' MD and circ b/u. Pump
10 bbl hi/vis sweep. Stage pumps up to
3 bpm, icp - 650 w/ 50 gpm, fcp - 990 w/
125 gpm. Total bbls pumped - 474.
17,235.0 17,230.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 34/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/6/2023
03:30
5/6/2023
05:30
2.00 COMPZN, CASING PACK P Drop 1.25" WIV ball followed by 10 bbl
hi-vis pill. Tag btm, p/u to break over
(189K), plus 5' to 17,230' MD. Pump
ball - hi-vis pill w/ 130 gpm, 965 psi,
1700 stks (144 bbls), reduce rate to 62
gpm, 685 psi, observe ball on seat at
2131 stks (180 bbls). Verify WIV shift
closed @ 1000 psi. Shut in and trap
210 psi via MPD. Pressure up to 2830
psi to set the pusher tool. Wait 5 min
and slack off to 44k. Pressure up to
4125 psi to release running tool. Bleed
off pressure. P/U to 182k to verify liner
released. P/U 1' above liner top. Liner
top set at 12,442' MD
17,230.0 12,441.0
5/6/2023
05:30
5/6/2023
06:00
0.50 COMPZN, CASING PRTS P R/U to test liner top packer to 3850 psi f/
15 min (good). Flood kill line. Close
upper rams. 87 stk, 7.3 bbls to pressure
up. 7.3 bbls bled back.
12,441.0 12,441.0
5/6/2023
06:00
5/6/2023
06:45
0.75 COMPZN, WELLPR RURD P P/U 45' to clear runnings tools from liner
top pkr to 12,398' MD. B/D test
equipment.
12,441.0 12,398.0
5/6/2023
06:45
5/6/2023
09:00
2.25 COMPZN, WELLPR COND P Condition 10.9 ppg NaC/NaBr CI brine
in the pits. SIMOPS - POOH to 12,347'
MD and rack back stand. Service top
drive, grease wash pipe and blocks.
Expidite HES tech wire spool to the rig
floor for upcoming completion run.
12,398.0 12,347.0
5/6/2023
09:00
5/6/2023
11:00
2.00 COMPZN, WELLPR DISP P Displace wellbore from 9.7 ppg FloPro
to 10.9 ppg NaCl/NaBr. Pump at 250
gpm, icp - 1345, fcp - 1400, 29% f/o.
Total stks pumped - 7439 (630 bbls)
12,347.0 12,347.0
5/6/2023
11:00
5/6/2023
11:30
0.50 COMPZN, WELLPR OWFF P OWFF (static). B/D top drive. 12,347.0 12,347.0
5/6/2023
11:30
5/6/2023
13:30
2.00 COMPZN, WELLPR MPDA P Pull MPD bearing and install trip nipple.
SIMOPS - L/D working dbl to 12,282'
MD. Up wt - 178k, s/o wt - 146k
12,347.0 12,282.0
5/6/2023
13:30
5/6/2023
20:00
6.50 COMPZN, WELLPR PULD P POOH L/D 4" HWDP f/ 12,282' MD to
8,369' MD. (43 stds) Monitor disp via tt.
130k up wt.
12,282.0 8,336.0
5/6/2023
20:00
5/7/2023
00:00
4.00 COMPZN, WELLPR PULD P Cont to POOH L/D 4" DP f/ 8,369' MD t/
4,800' MD (38 stds). Up wt - 95k.
Monitor disp via tt.
8,336.0 4,800.0
5/7/2023
00:00
5/7/2023
05:00
5.00 COMPZN, WELLPR PULD P Cont to POOH L/D 4" DP f/ 4,800' MD
(51 stds). Up wt - 94k. Monitor disp via
tt.
4,800.0 0.0
5/7/2023
05:00
5/7/2023
05:45
0.75 COMPZN, WELLPR PULD P L/D Baker running tool. 0.0 0.0
5/7/2023
05:45
5/7/2023
16:30
10.75 COMPZN, WELLPR PULD P L/D 75 stds of 4" DP via mousehole. 0.0 0.0
5/7/2023
16:30
5/7/2023
16:45
0.25 COMPZN, WELLPR RURD P Pull wear bushing as per CIW. 0.0 0.0
5/7/2023
16:45
5/7/2023
19:30
2.75 COMPZN, RPCOMP RURD P R/U to run 4½ 12.6# L-80 Hyd563 upper
completion.
0.0 0.0
5/7/2023
19:30
5/7/2023
19:45
0.25 COMPZN, RPCOMP SFTY P PJSM w/ all parties running upper
completion.
0.0 0.0
5/7/2023
19:45
5/7/2023
20:45
1.00 COMPZN, RPCOMP PUTB P Run 4½ 12.6# L-80 Hyd563 upper
completion as per detail to 245' MD.
Monitor disp via pit #6. Tq connections
to 3800 ft/lbs. Top fill on the fly.
0.0 245.0
5/7/2023
20:45
5/7/2023
21:30
0.75 COMPZN, RPCOMP OTHR P Install TEC wire to HES OPSIS gauge
as per HES. Test connections to 5000
psi f/ 5 min (good).
245.0 245.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 35/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/7/2023
21:30
5/8/2023
00:00
2.50 COMPZN, RPCOMP PUTB P Run 4½ 12.6# L-80 Hyd563 upper
completion as per detail f/ 245' MD to
1,507' MD. Monitor disp via pit #6. Top
fill on the fly. Tq connections to 3800
ft/lbs. Test OPSIS gauge/tec wire evey
1000'.
245.0 1,507.0
5/8/2023
00:00
5/8/2023
02:30
2.50 COMPZN, RPCOMP OTHR T Reconstruct splice on TEC wire. Find
splice on spool 6' up on jt #35. Location
of splice on btm will be 10,913' MD.
1,507.0 1,507.0
5/8/2023
02:30
5/8/2023
17:30
15.00 COMPZN, RPCOMP PUTB P Run 4½ 12.6# L-80 Hyd563 upper
completion as per detail f/ 1,507' MD to
1,507' MD. Monitor disp via pit #6. Top
fill on the fly. Tq connections to 3800
ft/lbs. Test OPSIS gauge/tec wire every
1000'.
1,507.0 12,354.0
5/8/2023
17:30
5/8/2023
18:00
0.50 COMPZN, RPCOMP PUTB P Fill pipe jt #297, 12,354' MD and obtain
parameters, up wt - 130k, s/o wt - 81k.
RIH and fully locate no go at top of liner
at 12,443' MD. Mule shoe depth of
12451' MD.
12,354.0 12,451.0
5/8/2023
18:00
5/8/2023
18:45
0.75 COMPZN, RPCOMP THGR P Space out. P/U pups 5.88 and 7.85, Jt
#298. Make up to hanger.
12,451.0 12,403.0
5/8/2023
18:45
5/8/2023
19:45
1.00 COMPZN, RPCOMP THGR P Make up TEC wire though ports of
hanger. Test ports to 5000 psi for 5 min
(good).
12,403.0 12,403.0
5/8/2023
19:45
5/8/2023
20:15
0.50 COMPZN, RPCOMP THGR P RIH and land hanger, setting NOGO 2'
off from fully located. RILDS.
12,403.0 12,443.0
5/8/2023
20:15
5/8/2023
20:45
0.50 COMPZN, RPCOMP THGR P Test hanger seals to 5000 psi for 15 min
as per CIW. Test witnessed by CPAI
rep.
12,443.0 12,443.0
5/8/2023
20:45
5/8/2023
23:00
2.25 COMPZN, RPCOMP PRTS P R/U and test tbg to 4550 psi for 15
charted min(good). Bleed psi to 2650.
Pressure up the IA to 3850 and hold for
30 charted min(good). Dump tbg psi
and observe SOV shear and
communication between IA and tbg.
12,443.0 12,443.0
5/8/2023
23:00
5/8/2023
23:15
0.25 COMPZN, RPCOMP OWFF P OWFF (static) 12,443.0 12,443.0
5/8/2023
23:15
5/8/2023
23:45
0.50 COMPZN, RPCOMP RURD P B/D and R/D test equipment. L/D
landing jt.
12,443.0 0.0
5/8/2023
23:45
5/9/2023
00:00
0.25 COMPZN, RPCOMP MPSP P Install HP-BPV as per CIW. 0.0 0.0
5/9/2023
00:00
5/9/2023
00:45
0.75 COMPZN, RPCOMP PRTS P R/U t/test BPV, Test Hp-BPV t/ 2500 psi
f/ 10 min on chart ( Good Test)
0.0 0.0
5/9/2023
00:45
5/9/2023
02:00
1.25 COMPZN, RPCOMP RURD P R/D down excess tools/equip. f/
completion run, clean and clear rig floor,
prep
MPD equip. t/ nipple down BOP.
0.0 0.0
5/9/2023
02:00
5/9/2023
06:00
4.00 COMPZN, WHDBOP NUND P Nipple down Bop's, l/d Mouse Hole t/
shed, remove MPD, RCD , orbit valve,
2" MPD manifold,
all associated MPD service lines, trip
nipples, Katch Kan assy., b/d and
remove
kill line, b/d and disconnect choke lines,
bleed down Koomey sys., break Lower
rams t/ DSA spool flange connection.,
Disconnect. injection line and MPD
return line, ready
Bop's t/ rack back t/ pedestal
0.0 0.0
5/9/2023
06:00
5/9/2023
06:30
0.50 COMPZN, WHDBOP OTHR P Off high line power, transfer to Gen
power
0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
Page 36/36
3H-36
Report Printed: 6/5/2023
Operations Summary (with Timelog Depths)
Job: DRILLING ORIGINAL
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/9/2023
06:30
5/9/2023
08:30
2.00 COMPZN, WHDBOP NUND P Vac out Bop, N/D Bop f/ DSA. rack back
on to pedestal, N/D DSA, secured on
Bop deck.
0.0 0.0
5/9/2023
08:30
5/9/2023
12:00
3.50 COMPZN, WHDBOP NUND P Prep N/U TBG adapter as per Cameron
rep. torque bolts to 3800 ft/lbs, make up
tech
wire t/ feed through block as per HES
rep. Simops: flush mud pumps, cement
pumps
w/ H20, blow down.
0.0 0.0
5/9/2023
12:00
5/9/2023
13:30
1.50 COMPZN, WHDBOP THGR P Break inner connects, Cmt line, M/U
injection return line, while waiting on
HES. Rep to terminate tech wire.
0.0 0.0
5/9/2023
13:30
5/9/2023
14:00
0.50 COMPZN, WHDBOP THGR P PT TBG Adapter flange as per Cameron
Rep. Observe leak, Bleed off pressure
and tighten bolts, Pressure back up to
5K Hold for 5Min as per Cameron and
HES Rep. Terminate Tech Wire final
Readings, BHP=3372 PSI , TEMP= 143
0.0 0.0
5/9/2023
14:00
5/9/2023
15:00
1.00 COMPZN, WHDBOP NUND P N/U orient 10K frac tree, M/U to Tubing
adapter, torque bolts 2500 ft/lbs
0.0 0.0
5/9/2023
15:00
5/9/2023
17:00
2.00 COMPZN, WHDBOP FRZP P R/U LRS and fill frac tree w/ diesel and
Pressure test to 250 psi for 5 min
10,000 psi for 15 min. charted as per
LRS, Pressure test packoffs to 250/5000
psi, bleed off check for pressure.
Simops: R/D skate trough, prep for rig
move. clean pits, disconnect
interconnects
0.0 0.0
5/9/2023
17:00
5/9/2023
19:00
2.00 COMPZN, WHDBOP NUND P Observed leak between Master and
Swab flange. Re-torque bolts, attempt to
pressure test.w/ LRS to 10K (Good Test)
0.0 0.0
5/9/2023
19:00
5/9/2023
19:45
0.75 COMPZN, WHDBOP WWSP P Verify all pressure was bled off prior to
pulling 2 way test dart/HP BVP w/ dry
rod as per Cameron Rep. SIMOPS
ready all areas for rig move secure
Skate to be Moved and Beaver Slide
removal.
0.0 0.0
5/9/2023
19:45
5/9/2023
20:00
0.25 COMPZN, WHDBOP RURD P R/D LRS Frac tree testing equip and
Hardline, R/U Freeze protect lines and
equipment. Mump 90 BBLS diesel
freeze protect w/ LRS truck.
0.0 0.0
5/9/2023
20:00
5/9/2023
23:00
3.00 COMPZN, WHDBOP FRZP P PJSM pressure test Service lines t/
2500 psi, Pump 90 BBLS diesel freeze
protect through IA taking returns
through production tubing to mud pits.
Lined up to IA from production tubing for
u-tubing @ 21:50 hrs total volume
pumped 91bbls, Total returns 88 bbls.
Simops ready all areas of rig for rig
move.
0.0 0.0
5/9/2023
23:00
5/9/2023
23:45
0.75 COMPZN, WHDBOP WWSP P Set HP/BPV and Secure well Tag well
that BPV was installed on 5-9-23 23:30
Hrs Well secure at 23:45 hrs. Final well
pressures: Tbg 40 psi, IA 0 psi, OA 0
psi.
0.0 0.0
5/9/2023
23:45
5/10/2023
00:00
0.25 DEMOB, MOVE MOB P Prep rig for move to 1C. Rig Released
at 00:00 Hrs on 5/10/23
0.0 0.0
Rig: DOYON 142
RIG RELEASE DATE 5/10/2023
!"
#$
#% &
Digitally signed by Vincent Osara
DN: C=US, OU=Schlumberger, O=Schlumberger,
CN=Vincent Osara, E=vosara@slb.com
Reason: I am the author of this document
Location: your signing location here
Date: 2023.05.10 13:51:00-08'00'
Foxit PhantomPDF Version: 10.1.4
Vincent
Osara
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Page 1/1
3H-36
Report Printed: 6/5/2023
Cement
Cement Details
Description
Surface String Cement
Cementing Start Date
4/2/2023 02:45
Cementing End Date
4/2/2023 07:45
Wellbore Name
3H-36
Comment
Cement Stages
Stage # 1
Description
Primary – Full Bore
Objective Top Depth (ftKB)
39.0
Bottom Depth (ftKB)
3,200.6
Full Return?
Yes
Vol Cement …
307.0
Top Plug?
Yes
Btm Plug?
Yes
Q Pump Init (bbl/m…
6
Q Pump Final (bbl/…
3
Q Pump Avg (bbl/…
5
P Pump Final (psi)
650.0
P Plug Bump (psi)
1,180.0
Recip?
Yes
Stroke (ft)
10.00
Rotated?
No
Pipe RPM (rpm)
Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in)
Comment
Pumped 540 bbls 10.7 ppg lead cement and 57.8 bbls 15.8 ppg tail cement.
Cement Fluids & Additives
Fluid
Fluid Type
Lead Cement
Fluid Description Estimated Top (ftKB)
39.0
Est Btm (ftKB)
2,700.0
Amount (sacks)
1,038
Class Volume Pumped (bbl)
540.0
Yield (ft³/sack)
2.92
Mix H20 Ratio (gal/sack)
14.94
Free Water (%) Density (lb/gal)
10.70
Plastic Viscosity (cP)
26.9
Thickening Time (hr)
6.50
CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
Fluid
Fluid Type
Tail Cement
Fluid Description Estimated Top (ftKB)
2,700.0
Est Btm (ftKB)
3,200.6
Amount (sacks)
278
Class Volume Pumped (bbl)
57.8
Yield (ft³/sack)
1.17
Mix H20 Ratio (gal/sack)
5.07
Free Water (%) Density (lb/gal)
15.80
Plastic Viscosity (cP)
107.0
Thickening Time (hr)
1.00
CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
Surface String Cement
Page 1/1
3H-36
Report Printed: 6/5/2023
Cement
Cement Details
Description
Intermediate String 1 Cement
Cementing Start Date
4/20/2023 18:34
Cementing End Date
4/20/2023 22:14
Wellbore Name
3H-36
Comment
Cement Stages
Stage # 1
Description
Intermediate String 1
Cement
Objective Top Depth (ftKB)
7,296.3
Bottom Depth (ftKB)
12,604.0
Full Return?
No
Vol Cement …Top Plug?
Yes
Btm Plug?
No
Q Pump Init (bbl/m…
6
Q Pump Final (bbl/…
3
Q Pump Avg (bbl/…
5
P Pump Final (psi)
475.0
P Plug Bump (psi)
975.0
Recip?
No
Stroke (ft) Rotated?
No
Pipe RPM (rpm)
Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in)
Comment
Cement Fluids & Additives
Fluid
Fluid Type
Lead Cement
Fluid Description Estimated Top (ftKB)
7,296.3
Est Btm (ftKB)
12,604.0
Amount (sacks)
1,122
Class Volume Pumped (bbl)
244.0
Yield (ft³/sack)
1.25
Mix H20 Ratio (gal/sack)
5.57
Free Water (%) Density (lb/gal)
15.30
Plastic Viscosity (cP)
138.4
Thickening Time (hr)
6.98
CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
Fluid
Fluid Type
Tail Cement
Fluid Description Estimated Top (ftKB)
12,604.0
Est Btm (ftKB)
12,604.0
Amount (sacks)
249
Class Volume Pumped (bbl)
50.0
Yield (ft³/sack)
1.24
Mix H20 Ratio (gal/sack)
5.57
Free Water (%) Density (lb/gal)
15.30
Plastic Viscosity (cP)
138.4
Thickening Time (hr)
6.98
CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
Stage # 2
Description
Stage Cementing
Objective Top Depth (ftKB)
5,500.0
Bottom Depth (ftKB)
7,296.3
Full Return?
No
Vol Cement …Top Plug?
Yes
Btm Plug?
No
Q Pump Init (bbl/m…
4
Q Pump Final (bbl/…
3
Q Pump Avg (bbl/…
4
P Pump Final (psi)
450.0
P Plug Bump (psi)
1,600.0
Recip?
No
Stroke (ft) Rotated?
No
Pipe RPM (rpm)
Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in)
Comment
Cement Fluids & Additives
Fluid
Fluid Type
Spacer
Fluid Description Estimated Top (ftKB)
4,500.0
Est Btm (ftKB)
5,500.0
Amount (sacks) Class Volume Pumped (bbl)
80.0
Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal)
12.50
Plastic Viscosity (cP) Thickening Time (hr) CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
Fluid
Fluid Type
Tail Cement
Fluid Description Estimated Top (ftKB)
5,500.0
Est Btm (ftKB)
7,296.3
Amount (sacks)
844
Class
G
Volume Pumped (bbl)
181.0
Yield (ft³/sack)
1.24
Mix H20 Ratio (gal/sack)
5.57
Free Water (%) Density (lb/gal)
15.30
Plastic Viscosity (cP)
100.6
Thickening Time (hr)
5.50
CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
Intermediate String 1 Cement
From:Taylor, Jenna
To:Brooks, James S (OGC)
Subject:RE: [EXTERNAL]FW: KRU 3H-36 10-407 Completion Report
Date:Tuesday, June 13, 2023 8:12:04 AM
The choke size is correct as in 50/64th. If you need it in bean, it would be 50 bean.
Jenna
From: Brooks, James S (OGC) <james.brooks@alaska.gov>
Sent: Friday, June 9, 2023 1:47 PM
To: Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>
Subject: [EXTERNAL]FW: KRU 3H-36 10-407 Completion Report
CAUTION:This email originated from outside of the organization. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Hi,
Concerning 10-407 box 27 ~ I confused on Choke size value.
Can you please check ?
thanx
From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov>
Sent: Thursday, June 8, 2023 11:08 AM
To: Brooks, James S (OGC) <james.brooks@alaska.gov>
Subject: FW: KRU 3H-36 10-407 Completion Report
Hi James,
Here is the email sent to AOGCC regarding your question as who sent this to us.
Ion the future, do you want to have this included in your email?
Grace
From: AOGCC Permitting (CED sponsored)
Sent: Tuesday, June 6, 2023 10:59 AM
To: Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>
Cc: McCracken, Shane M <Shane.M.McCracken@conocophillips.com>; Hobbs, Greg S
<Greg.S.Hobbs@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>
Subject: RE: KRU 3H-36 10-407 Completion Report
Received for processing.
Thank you,
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.
Grace Christianson
Executive Assistant, AOGCC
(907) 793-1230
From: Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>
Sent: Tuesday, June 6, 2023 10:29 AM
To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Cc: McCracken, Shane M <Shane.M.McCracken@conocophillips.com>; Hobbs, Greg S
<Greg.S.Hobbs@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>
Subject: KRU 3H-36 10-407 Completion Report
Hello – See attached completion report for 3H-36. Please let me know if you need additional
information.
Thank you,
Jenna
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?KRU 3H-36
Will planned perforations require a spacing exception? Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
Kuparuk River Pool
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
17235 5948.32 5947.3 1981 None None
Casing Collapse
Structural
Conductor
Surface 2470
Intermediate 4790
Intermediate 7850
Liner 9210
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:Dustin Morrow
Contact Email:dustin.w.morrow@cop.com
Contact Phone: 832-493-9141
Authorized Title: Staff Completions Engineer
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Sleeve Depths attached
1000.6
4-1/2"
Sleeve Depths attached
172304787.3
4-1/2"
5948.2
7-5/8"
20"
10-3/4"
120
3161.5
Perforation Depth MD (ft):
7-5/8"11564.3
10860
MD
6890
5210
159.1
2970.8
5716.3
159.1
3200.6
592612604
11603.4
Length Size
Proposed Pools:
TVD Burst
PRESENT WELL CONDITION SUMMARY
17196.2
Kuarpuk River Field
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL365501/ADL025524/ADL025532/ADL025531
222-014
P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20838-00-00
ConocoPhillips
11590
Tubing Grade: Tubing MD (ft):
TNT Packer @12,270.9' MD/ 5,890.1' TVD
LTP set at 12,442.7'MD / 5,917' TVD
Perforation Depth TVD (ft): Tubing Size:
L-80 12451.5
17-May-23
HAL TNT Prod Packer, Baker ZXP
Packer/Hanger, No SSSV
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
AOGCC USE ONLY
Perforate
Repair Wepair Well
Exploratory Stratigraphic Development Service
BOP TestMechanical Integrity Test Location Clearance
No
No
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:19 pm, May 12, 2023
323-286
119' SFD
10-404
SFD 5/17/2023 DSR-5/12/23
X
May 12, 2023
VTL 5/17/2023
17-May-23
Fracture Stimulate
119'
CDW 05/15/2023
GCW 05/17/23
5/18/23
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.05.17
18:54:32 -08'00'
RBDMS JSB 051823
Section 1 - Affidavit 10 AAC 25.283 (a)(1)
Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators
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).
Exhibit 1
May 11, 2023
VIA CERTIFIED MAIL
To: Operator and Owners (shown on Exhibit 2)
Re: Notice of Operations pursuant to 20 AAC 25.283 (a)(1) for 3H-36 Well
ADL-025524, ADL-025531, ADL-025532, and ADL-365501
Kuparuk River Unit, Alaska
CPAI Contract No. 203828
ConocoPhillips Alaska, Inc. (“CPAI”) as Operator and on behalf of the Kuparuk River Unit working interest
owners, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation
by hydraulic fracturing pursuant to the provisions of 20 AAC 25.280 (“Application”) for the 3H-36 Well
(the “Well”). The Application will be filed with the Alaska Oil and Gas Conservation Commission (“AOGCC”)
on or about May 11, 2023. This Notice is being provided pursuant to subsection of 20 AAC 25.283.
The Well is currently planned to be drilled as a directional horizontal well on leases ADL-025524, ADL-
025531, ADL-025532, and ADL-365501, as depicted on Exhibit 1, and has locations as follows:
Location FNL Township Range Section Meridian
Surface 1,451’ 281’ FWL T12N R8E 12 Umiat
Top Open Interval 4,764’ 5,223.80’
FEL T13N R8E 34 Umiat
Bottomhole 1,633.50’ 3,180.40’
FEL T13N R8E 33 Umiat
Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current
proposed trajectory of the Well (“Notification Area”), which includes the reservoir section. Exhibit 2 is a
list of the names and addresses of all owners, landowners, surface owners, and operators of record of all
properties within the Notification Area.
Upon your request, CPAI will provide a complete copy of the Application. If you require any additional
information, please contact the undersigned.
Sincerely,
Attachments: Exhibits 1 & 2
Dennise Arzola
Senior Land Negotiator
ConocoPhillips Alaska, Inc.
700 G Street
Anchorage, AK 99501
Office: 907-265-6297
Fax: 907-263-4966
dennise.arzola@cop.com
Exhibit 2
List of the names and addresses of all owners, landowners, surface owners, and operators of record of
all properties within the Notification Area.
Operator & Owner:
ConocoPhillips Alaska, Inc.
700 G Street, Suite ATO-1478
Anchorage, AK 99510
Attn: GKA Asset Development Manager
Owner (Non-Operator):
ConocoPhillips Alaska, Inc. II
700 G Street, Suite ATO 1226
Anchorage, Alaska 99510
Attn: GKA Asset Development Manager
Chevron U.S.A. Inc
1400 Smith Street Room 45104
Houston, TX 77002
Attn: Gary Selisker
ExxonMobil Alaska Production Inc.
P.O. Box 196601
Anchorage, AK 99519
Attn: Todd Griffith
Other Operators of Record:
None
Landowners:
State of Alaska
Department of Natural Resources
Division of Oil and Gas
550 West 7th Avenue, Suite 1100
Anchorage, AK 99501
Attention: Derek Nottingham, Director
Surface Owner:
State of Alaska
Department of Natural Resources
Division of Oil and Gas
550 West 7th Avenue, Suite 1100
Anchorage, AK 99501
Attention: Derek Nottingham, Director
Section 2 – Plat 20 AAC 25.283 (a)(2)
Plat 1: Wells within 0.5 miles
Table 1: Wells within .5 miles
API * Well Name Well
Type
Status Symbology
501032009771 3H-22L1-03PB2 EXPEND PA Plugged and Abandoned
501032008300 3H-02 INJ ACTIVE Injector Produced Water
501032008761 3H-10CL2 PROD ACTIVE Oil
501032008860 3H-12AL1 INJ ACTIVE Injector Miscible Water Alternating Gas
501032009000 3H-19 PROD ACTIVE Oil
501032009263 3H-14BL4 PROD SUSP Suspended
501032009364 3H-20L1-04 PROD ACTIVE Oil
501032009372 3H-20L1-04PB1 EXPEND PA Plugged and Abandoned
501032008500 3H-03 PROD ACTIVE Oil
501032008700 3H-10 INJ PA Plugged and Abandoned
501032008762 3H-10CL2-01 PROD ACTIVE Oil
501032008861 3H-12AL2 INJ ACTIVE Injector Miscible Water Alternating Gas
501032008971 3H-13AL1PB2 EXPEND PA Plugged and Abandoned
501032009101 3H-11A INJ ACTIVE Injector Produced Water
501032009161 3H-11AL1-01 INJ ACTIVE Injector Produced Water
501032009262 3H-14BL3 PROD SUSP Suspended
501032009270 3H-14APB1 EXPEND PA Plugged and Abandoned
501032009365 3H-20L1-05 PROD ACTIVE Oil
501032009400 3H-21 PROD ACTIVE Oil
501032009600 3H-16 PROD PA Plugged and Abandoned
501032020301 3H-25A PROD SUSP Suspended
501032020400 3H-23 PROD PA Plugged and Abandoned
501032020560 3H-31AL1 PROD ACTIVE Oil
501032032200 3H-32 PROD ACTIVE Oil
501032032270 3H-32PB1 EXPEND PA Plugged and Abandoned
501032057801 3H-33A PROD ACTIVE Oil
501032057862 3H-33AL2-01 PROD ACTIVE Oil
501032007800 3H-06 INJ ACTIVE Injector Miscible Water Alternating Gas
501032008401 3H-01A PROD ACTIVE Oil
501032008470 3H-01AL1PB1 EXPEND PA Plugged and Abandoned
501032008701 3H-10A INJ PA Plugged and Abandoned
501032008770 3H-10CPB1 EXPEND PA Plugged and Abandoned
501032008862 3H-12AL3 INJ ACTIVE Injector Miscible Water Alternating Gas
501032008963 3H-13AL1-03 PROD ACTIVE Oil
501032008972 3H-13AL1-01PB1 EXPEND PA Plugged and Abandoned
501032009160 3H-11AL1 INJ ACTIVE Injector Produced Water
501032009260 3H-14BL1 PROD PA Plugged and Abandoned
501032009261 3H-14BL2 PROD SUSP Suspended
501032020370 3H-25APB1 EXPEND PA Plugged and Abandoned
501032020501 3H-31A PROD ACTIVE Oil
501032020800 3H-26 PROD ACTIVE Oil
501032020861 3H-26L1-01 PROD ACTIVE Oil
501032064300 3H-34 PROD ACTIVE Oil
501032064360 3H-34L1 PROD ACTIVE Oil
501032008400 3H-01 PROD PA Plugged and Abandoned
501032008600 3H-09 INJ ACTIVE Injector Miscible Water Alternating Gas
501032008763 3H-10CL2-02 PROD ACTIVE Oil
501032008870 3H-12APB1 EXPEND PA Plugged and Abandoned
501032008962 3H-13AL1-02 PROD ACTIVE Oil
501032008970 3H-13AL1PB1 EXPEND PA Plugged and Abandoned
501032009362 3H-20L1-02 PROD ACTIVE Oil
501032009363 3H-20L1-03 PROD ACTIVE Oil
501032009370 3H-20L1-01PB1 EXPEND PA Plugged and Abandoned
501032009371 3H-20L1-03PB1 EXPEND PA Plugged and Abandoned
501032009760 3H-22L1 INJ ACTIVE Injector Produced Water
501032023500 3H-24 INJ ACTIVE Injector Produced Water
501032020860 3H-26L1 PROD ACTIVE Oil
501032080500 3H-35 INJ ACTIVE Injector Miscible Water Alternating Gas
501032007600 3H-04 PROD ACTIVE Oil
501032008760 3H-10CL1 PROD ACTIVE Oil
501032008800 3H-12 PROD PA Plugged and Abandoned
501032008900 3H-13 PROD PA Plugged and Abandoned
501032009201 3H-14A PROD PA Plugged and Abandoned
501032009361 3H-20L1-01 PROD ACTIVE Oil
501032009601 3H-16A PROD ACTIVE Oil
501032009762 3H-22L1-02 INJ ACTIVE Injector Produced Water
501032023601 3H-28A PROD ACTIVE Oil
501032020300 3H-25 PROD PA Plugged and Abandoned
501032020401 3H-23A PROD ACTIVE Oil
501032020862 3H-26L1-02 PROD ACTIVE Oil
501032064362 3H-34L1-02 PROD ACTIVE Oil
501032057861 3H-33AL2 PROD ACTIVE Oil
501032007700 3H-05 PROD PA Plugged and Abandoned
501032007900 3H-07 INJ ACTIVE Injector Miscible Water Alternating Gas
501032008460 3H-01AL1 PROD ACTIVE Oil
501032008703 3H-10C PROD ACTIVE Oil
501032008901 3H-13A PROD ACTIVE Oil
501032009100 3H-11 PROD PA Plugged and Abandoned
501032009202 3H-14B PROD SUSP Suspended
501032009360 3H-20L1 PROD ACTIVE Oil
501032023600 3H-28 PROD PA Plugged and Abandoned
501032020500 3H-31 PROD PA Plugged and Abandoned
501032082200 3H-37 PROD ACTIVE Oil
501032064361 3H-34L1-01 PROD ACTIVE Oil
501032057860 3H-33AL1 PROD ACTIVE Oil
501032008000 3H-08 PROD ACTIVE Oil
501032008100 3H-17 INJ ACTIVE Injector Sea Water
501032008702 3H-10B PROD PA Plugged and Abandoned
501032008801 3H-12A INJ ACTIVE Injector Miscible Water Alternating Gas
501032008960 3H-13AL1 PROD ACTIVE Oil
501032009300 3H-20 PROD ACTIVE Oil
501032009366 3H-20L1-06 PROD ACTIVE Oil
501032009500 3H-18 INJ ACTIVE Injector Produced Water
501032009700 3H-22 INJ ACTIVE Injector Produced Water
501032014560 3G-24L1 INJ ACTIVE Injector Produced Water
501032014571 3G-24L1PB2 EXPEND PA Plugged and Abandoned
501032020371 3H-25APB2 EXPEND PA Plugged and Abandoned
501032064370 3H-34L1PB1 EXPEND PA Plugged and Abandoned
501032064371 3H-34L1-01PB1 EXPEND PA Plugged and Abandoned
501032057800 3H-33 PROD PA Plugged and Abandoned
501032057870 3H-33AL1PB1 EXPEND PA Plugged and Abandoned
501032009763 3H-22L1-03 INJ ACTIVE Injector Produced Water
501032009770 3H-22L1-03PB1 EXPEND PA Plugged and Abandoned
501032008200 3H-15 INJ ACTIVE Injector Miscible Water Alternating Gas
501032008973 3H-13AL1PB3 EXPEND PA Plugged and Abandoned
501032009200 3H-14 PROD PA Plugged and Abandoned
501032009670 3H-16APB1 EXPEND PA Plugged and Abandoned
501032023670 3H-28APB1 EXPEND PA Plugged and Abandoned
501032020460 3H-23AL1 PROD ACTIVE Oil
SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3)
There are no freshwater aquifers or underground sources of drinking water within a one-half
mile radius of the current or proposed wellbore trajectory.
None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), “That portions of the aquifers on
the North Slope described by a ¼ mile area beyond and lying directly below the Kuparuk
River Unit oil and gas producing field”.
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.
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.
3H-36 Horizontal Kuparuk A-Sand/C-Sand Producer
(As Drilled)
Heavy Heel: 7-5/8" 39# TN-110SS HYD563 Casing (869')
4-1/2" Lower Completion @ 17,230' MD / 5,948' TVD, 89o Inc.
10 - Advanced Upstream Frac Sleeves
Well Path: 3H-36
All Depths are RKB.
Baker SLZXP 4.5" x 7-5/8" @ 12,443' MD / 5,917' TVD
HAL Prod Packer 4.5" x 7-5/8" @ 12,270' MD / 5,890' TVD
HAL Downhole Gauge @ 12,205' MD / 5862' TVD
Alpha sleeve + WIV15 - 4-1/2" x 5-3/4" Swell Packers
Top of Cement @ 7,296’ MD / 4,461’ TVD
Top Tabasco @ 3,391’ MD / 3,108’ TVD
Base Tabasco @ 3,500’ MD / 3,183’ TVD
Top Coyote @ 6,490’ MD / 4,227’ TVD
Base Coyote @ 7,185’ MD / 4,429’ TVD
Top Moraine @ 10,429’ MD / 5,373’ TVD
Top Kuparuk
@ 12,400’ MD / 5,910’ TVD
Base Permafrost @ 1,688’ MD / 1,680' TVD
RKB 䇵 MSL: 75.34'
20" Insulated Conductor
@ 119' MD / 119' TVD
7-5/8" Casing @ 12,604' MD / 5,926' TVD, 87o Inc.
Top of Cement @ 5,500' MD / 3,939 TVD
10-3/4" 45.5# L-80 HYD563 Casing
@ 3,200' MD / 2,970' TVD, 43o Inc.
HES Stage Cementer @ 7,293' MD / 4,460' TVD, 73o Inc.
6-1/2" Production Hole TD @ 17,235' MD / 5,948' TVD, 89o Inc.
7-5/8" 29.7# L-80 HYD563 Casing
Upper Completion:
GLM @ 2,763' MD / 2,641' TVD, 37.2o Inc.
GLM @ 6,790' MD / 6,797' TVD, 72.7o Inc.
GLM @ 10,004' MD / 5,250' TVD, 72.9o Inc.
GLM @ 11,790' MD / 5,771' TVD, 73.0o Inc.
X Nipple @ 11,858' MD / 5,790' TVD, 73.6o Inc.
D Nipple @ 12,338' MD / 5,903' TVD, 80.4o Inc.
Inc.
Fault 14,736' Fault 15,475'
Note double swell packers and faults identified. CDW 05/17/2023
SECTION 6 – ASSESSMENT OF EACH CASING AND CEMENTING
OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE
WELL 20 AAC 25.283(a)(6)
Casing & Cement Assessments:
10-3/4” casing cement pump report on 4/2/2023 shows that the original job pumped as
designed. The cement job was pumped with 540 barrels of 10.7 ppg lead cement and 57.8
barrels 15.8 ppg tail cement, displaced with 9.7ppg mud. The plug did bump, pressured up to
1180 psi and held for 5 minutes, bled off and the floats held. Good cement to surface.
The 7-5/8” casing cement report on 4/20/2023 shows that the job was pumped as designed,
indicating competent cementing operations. The first stage cement job was pumped with 244
barrels of 15.3 ppg lead cement and 50 barrels of 15.8 ppg tail cement. The cement was
displaced with 11.4 ppg mud. The plug did bump, pressured up to 1180 psi and held for 5
minutes, bled off and the floats held.
A stage tool was opened on 4/21/2023 and cement was pumped on 4/22/2023.
181 barrels of 15.3 ppg Class G lead was pumped through the stage tool. The plug was
bumped and pressure up to 1600 psi, held for 5 minutes. The pressure was bled off and the
floats held.
A cement bond log indicates competent cement with a cement top @ 5,500’ MD (3,939’
TVD).
Summary
All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone
penetrated by the well is isolated.
Based on engineering evaluation of the wells referenced in this application, ConocoPhillips
has determined that this well can be successfully fractured within its design limits.
A cement bond log indicates
pg p,p
Good cement to surface.
cement top @ 5,500’ MD
SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST
CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7)
On 4/3/2023 the 10-3/4” casing was pressure tested to 3,500 psi.
On 4/24/2023 the 7-5/8” casing and stage tool were pressure tested to 1,600 psi.
The 4-1/2” tubing was pressure tested to 4,550 psi on 5/8/2023.
The 7-5/8” casing was pressure tested to 3,850 psi on 5/8/2023.
AOGCC Required Pressures [all in psi]
Maximum Predicted Treating Pressure (MPTP) 7,360
Annulus pressure during frac 3,500
Annulus PRV setpoint during frac 3,600
7-5/8" Annulus pressure test 3,850
4-1/2" Tubing pressure Test 4,550
Tubing ePRV 8,360
Highest pump trip 7,860
SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE,
WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8)
Size Weight, ppf Grade API Burst (psi) API Collapse
(psi)
10-3/4” 45.5 L-80 5,210 2,470
7-5/8” 29.7 L-80 6,890 4,790
7-5/8” 39.0 TN110SS 12,620 11,080
4-1/2” 12.6 P110S 11,590 9,210
4-1/2” 12.6 L-80 8,430 7,500
Table 2: Wellbore pressure ratings
Frac Sleeve Locations
MD INC TVD LAT LONG
13034.4 87.79 5940.05 70° 25' 55.156 N 150° 4' 9.212 W Advanced Upstream
13471.5 90.42 5951.16 70° 25' 58.331 N 150° 4' 17.813 W Advanced Upstream
13907.6 89.8 5943.65 70° 26' 1.146 N 150° 4' 27.465 W Advanced Upstream
14261.3 88.96 5949.42 70° 26' 3.325 N 150° 4' 35.554 W Advanced Upstream
15133 90.28 5951.45 70° 26' 8.958 N 150° 4' 54.810 W Advanced Upstream
15961.7 88.81 5957.32 70° 26' 14.749 N 150° 5' 11.915 W Advanced Upstream
16356 91.07 5960.88 70° 26' 17.570 N 150° 5' 19.846 W Advanced Upstream
16834.7 90.4 5947.87 70° 26' 21.058 N 150° 5' 29.259 W Advanced Upstream
17196.2 88.52 5947.32 70° 26' 23.224 N 150° 5' 37.659 W Alpha sleeve
Stimulation Surface Rig-Up
Kuparuk 10K Frac Tree
SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING
ZONES 20 AAC 25.283(a)(9)
CPAI has formed the opinion, based on seismic, well, and other subsurface information currently
available that: The Kuparuk interval is approximately 25’ TVD thick at the heel of the lateral, thinning to
approximately 4’ TVD at the toe. The Kuparuk interval thickness is derived from the partial
penetrations in the 3H-36 lateral, Periscope HD resistivity modeling, and the partial penetration in the
3H-35 and 3H-37 laterals, in addition to offset well thicknesses in the 3H drill site. The Kuparuk Interval
is composed of medium and fine-grained sandstones, siltstones and shale interbeds. The estimated
fracture gradient for the Kuparuk interval is 13.1 ppg. Top Kuparuk was penetrated at 12,486 MD / -
5,845’ TVDSS.
The overlying confining zone consists of approximately 400’ TVD of Lower Kalubik, Upper Kalubik and
HRZ mudstones. The fracture gradient for each of these zones is estimated to be 16 ppg. Top HRZ
was encountered at 11,204 MD / -5,522’ TVDSS.
The underlying confinement zone consists of greater than 500’ TVD of mudstones comprising the
Miluveach Shale. The estimated fracture gradient for the Miluveach Shale is 15.5 ppg with fracture
gradient increasing with depth. The Top Miluveach was not encountered in the 3H-36 lateral. Based on
offset thicknesses, the top Miluveach is projected to be at -5,880’ TVDSS.
SECTION 10 – LOCATION, ORIENTATION AND A REPORT ON
MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT
CONFINING ZONE 20 AAC 25.283(a)(10)
The plat shows the location and orientation of each well that transects the confining zone.
ConocoPhillips has formed the opinion, based on 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 & Cement assessments for all wells that transect the confining zone:
3H-35: The 7-5/8” casing cement report on 2/22/2022 was pumped with 287 barrels of
15.8ppg Class G cement and displaced with 619 barrels of 11.4ppg LSND. Plug was bumped
to 1200psi and floats held. There were no returns during the cement job but a CBL confirmed
a cement top of 4,680’ TVDSS. The 7-5/8” casing passed an MIT-IA to 3300 psi on rig on
3/6/2020.
3H-32: The well was sidetracked in 2000 during which a new 7” intermediate string was run.
The 7” casing cement report on 2/7/2000 reported the cement job was pumped with 70
barrels of Class G cement. Full circulation was regained during the cement displacement.
The plug did not bump but the floats held.
The well had a passing MIT-IA to 1600psi on 5/11/2018.
3M-28A: The 7” casing cement report on 2/29/1996 reported the cement job was pumped
with 42 barrels of Class G cement. The plug did not bump but the floats held. The casing was
tested to 3500 psi for 30 minutes on 4/17/1996. Good Test
The well had a passing MIT-IA to 2500psi on 2/12/2015.
3H-28A SFD
1
Davies, Stephen F (OGC)
From:Morrow, Dustin W <Dustin.W.Morrow@conocophillips.com>
Sent:Tuesday, May 16, 2023 12:16 PM
To:Davies, Stephen F (OGC); Hobbs, Greg S
Cc:Loepp, Victoria T (OGC); Wallace, Chris D (OGC)
Subject:RE: [EXTERNAL]KRU 3H-26 (PTD 222-014; Sundry 323-286) - Operations Start Date
Attachments:3H-36_Final_Frac_Sundry_KUP_FaultsV2.jpg; Reporting - Deviation Survey (All Points) report data -
2023-05-10 13.27.23.xlsx
Yes,
Herearetheresults,heagreedwithyoucommentsandcleanedupthedescriptionsandanewannotatedmapwas
created.Pleaseletmeknowifthereisanythingelse,Icanalsoputyouintouchwithhim.
Ialsoattachedasurvey,pleaseletmeknowifthereisanythingelse.
Waitingonthelogsstill…
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)
CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that six faults
or fracture systems transect the Kuparuk formation or enter the confining zone within one half mile radius of the wellbore
trajectory for 3H-36.
x Fault 1 was encountered in the Torok Fm above the HRZ while drilling the intermediate hole
section at 10,850’ MD. Based on a thinner Torok than offset wells, the throw is interpreted to be 65’.
At the Kuparuk penetration of 3H-36, fault 1 is interpreted to be ~2100’ to the southeast based on
seismic data, with a strike perpendicular to the orientation of 3H-36. Fault 1 was encountered in the
offset parallel horizontal wellbore 3H-35.
x Fault 2 is a fault zone that was encountered in the overburden in the Lower Kalubik while drilling
the intermediate hole section at 11,634’ MD, with a throw of ~15’. At the Kuparuk penetration of
3H-36, fault 1 is interpreted to be ~800’ to the southeast based on seismic data and is roughly
parallel to fault 1. A splay of Fault 2 was encountered in the offset, parallel horizontal wellbore 3H-
35.
x Fault 3 is a seismically identified fault zone that was predicted to be at 13,052’ MD. Seismic
data indicates that both have a north-south strike, roughly parallel to fault 1 and 2. Fault 3 was not
definitively observed in this well but an interpreted splay was present in the offset, parallel
horizontal wellbore 3H-35.
x Fault 4 was encountered in the 3H-36 lateral at 14,734’ MD with ~2’ of throw, faulting the
wellbore from the Kuparuk C4 sands onto the Kuparuk C4 sands. This fault was not resolved on
seismic, its extent is unknown . Losses were taken while crossing this fault.
x Fracture zone 5 was encountered in the 3H-36 lateral at 15,477’ MD. Its extent is unknown due
to the small throw. Losses were taken while crossing this fracture zone.
x Fault 6 was not penetrated with the 3H-36 well bore but is interpreted in seismic data as a major
graben bounding fault approximately 500’ to the south of the 3H-36 well, paralleling the wellbore
with a down to the north throw of ~20-30’.
Fracture gradients within the top seal intervals would not be exceeded during fracture stimulation and would therefore
confine injected fluids to the pool.ௗ CPAI has formed the opinion, based on seismic, well and other subsurface information
currently available that the apparent faults will not interfere with containment.
Maximum principle stress orientation in the area for the Kuparuk interval is N30W to N15W and hydraulic fractures are
expected to propagate at an oblique angle ~15 – 30 degrees to the drilled wellbore. Faults observed in the wellbore and in
2
seismic data are isolated with swell packers and blank pipe. If there are indications that a fracture has intersected a fault
during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately.
Fault
numberWellNameDepthMD
(ft)
DepthTVDSS
(ft)
Vertical
Displacement
(ft)
Loss
(bbls/hr)
13HͲ3610850’542165’None
23HͲ3611634’565015’None
33HͲ3613052’5865N/ANone
43HͲ3614734’58752’30Ͳ60
5(fracture)3HͲ3615477’58770’30Ͳ60
6500’Sof3HͲ
36N/AN/A20’–30’N/A
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Tuesday,May16,202311:55AM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
ThankyouDustin.Iappreciateyourhelpwiththis.IsCPAI’sgeophysiciststillworkingonimprovingtheannotationson
theFaultAnalysismapandclarifyingthediscussionsfortheindividualfaults?
Thanksagainandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Tuesday,May16,202310:30AM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Mr.Davies,
IspentalotoftimelookingforlogsbutIwasnotabletofindanything
ThebestrecordsIcouldfindyieldthefollowing:
3
Forthecementtops:
3HͲ28A–(Ihadthismisslabeledas3MͲ28A)
7”casingwasrunto12565’on2/29/96
200sxsofClassG(1.15ft3/sk)waspumped,noreportsoflostcirculationorlosses,theplugwasnotbumped,thefloats
held
CalculatedTOC:
100%efficiency~10,751’MD/4611’TVD
85%efficiency~11,023’MD/4693’TVD
3HͲ32
7”casingwasrunto13809’on2/4/00
200sxsofClassG(1.15ft3/sk)waspumped,minimalreturnsinitiallybutregainedfullcirculationonceondisplacement,
plugdidnotbumpbutthefloatsheld.
CalculatedTOC:
85%efficiency~12,267’MD/5,606’TVD(reducedefficiencypotentialduetoinitiallossofreturns)
75%efficiency~12,448’MD/5,664’TVD
ProposedTops
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Monday,May15,20233:20PM
4
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Dustin,
ForSection10,couldCPAIpleaseprovidecalculatedtopsofcementfortheotherwellswithintheAreaofReview(3HͲ32
and3MͲ28A)todemonstratecementͲisolationfortheKuparukreservoir?
Thanksagainforyourhelp,
SteveDavies
AOGCC
From:Davies,StephenF(OGC)
Sent:Monday,May15,20233:07PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Dustin,
I’mabitconfusedbySection11andtheaccompanyingfaultanalysismap.Sixfaults/fracturezonesarediscussed,but
thereappeartobe7ormaybe8faults/fracturesmarkedonthemapwithintheAOR.ThedescriptionforFault6
describesaWNWͲtrendingfaultthatisn’tshownonthemap,andthedescriptionappearstobeincomplete
(“…parallelingthewellborewitha.”)anditdoesn’tmakesense(“…isinterpretedintheseismicdataasamajorgraben
boundingfaultapproximately500’tothesouthofthe3HͲ36wellparallelingthewellborewitha.Thisfaultis~1,700’
tothenortheastandparallelto3HͲ37drilledwellpathfortheentiretyofthelateral…”).
Pleaselabelthefaultsonthemapwiththesamenumbersasthecorrespondingdescriptionsandindicatethe
downthrownsideofeachfault.PleasealsoreͲreadandclarifythefaultdescriptionsasneeded.
Thanksagain.
SteveDavies
AOGCC
From:Davies,StephenF(OGC)
Sent:Monday,May15,202312:55PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
ThankyouDustin.Ifoundthestagetooldepthonthewellschematic.Ididn’tseeanyoftheotherinformationeither
attachedtoemailsorloggedintoourcentraldatabase,butthisisanewlydrilledwell.ApologiesifI’veoverlookedany
datathathasalreadybeensubmitted.
Thanksagain.
SteveDavies
AOGCC
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Monday,May15,202312:51PM
5
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Yessir,
Iwillgetallthatinformationtrackeddownandfigureoutwhyithasnotbeensubmittedalready.
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Monday,May15,202312:26PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Dustin,
CouldCPAIpleaseprovidefieldcopiesofthecementreports,themeasureddepthofthe7Ͳ5/8”casingstagetool,
directionalsurveydata,CBL,andwelllogsfor3HͲ26?Directionalsurveydatainspreadsheet,tabͲdelimited,orcommaͲ
delimitedformisfine.Welllogsin.lasortabͲdelimitedformatarepreferred.
PleasenotethatthesefieldͲqualitydatadonotmeetthefinalreportingrequirementsof20AAC25.071.
Thanksforyourhelp,
SteveDavies
AOGCC
From:Davies,StephenF(OGC)
Sent:Monday,May15,202310:04AM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
ThankyouDustin.SeveralpeoplehereatAOGCCareinvolvedinthereviewanddecisionprocess,andI’mnotcertainof
theirschedulesorcurrentworkloads.Obviously,thelongertheleadtimethatCPAIcanprovide,thebetter.
Regards,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Monday,May15,20239:44AM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
6
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
MorningSteve,
WeareplanningtoberiggedinasearlyasWednesdaybuthaveaskedourfracsupervisortoplanforMay19thdueto
Sundrysubmittaldate.
Iamtryingtocoachtheplanningteamonrealistictimesforreceivinganapprovedsundry.
Wedon’thavealltherequiredinformationuntilthelinerisonbottomandset.
Iwillworkonourprocessworktogettheseoutsooner,Idonotlikerequestingarush.
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Monday,May15,20239:17AM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you
recognize the sender and know the content is safe.
Dustin,
CPAI’sSundryApplicationtofracturestimulateKRU3HͲ26wasreceivedbyAOGCConFridayafternoon.Theestimated
operationsstartdateisWednesday,May17th.Howfirmisthatoperationsstartdate?Pleasebeawarethattwo
businessdaysisafairlyslimmargintoworkthisapplicationthroughAOGCC’sreviewprocessforfractureͲstimulation
operations.Pleaseletusknowsothatwecanprioritizeotherexistingwork.
Thanksandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
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.
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)
CPAI has formed the opinion, based on seismic, well, and other subsurface information currently
available that six faults or fracture systems transect the Kuparuk formation or enter the confining zone
within one half mile radius of the wellbore trajectory for 3H-36.
x Fault 1 was encountered in the Torok Fm above the HRZ while drilling the
intermediate hole section at 10,850’ MD. Based on a thinner Torok than offset wells,
the throw is interpreted to be 65’. At the Kuparuk penetration of 3H-36, fault 1 is
interpreted to be ~2100’ to the southeast based on seismic data, with a strike
perpendicular to the orientation of 3H-36. Fault 1 was encountered in the offset
parallel horizontal wellbore 3H-35.
x Fault 2 was encountered in the overburden in the Lower Kalubik while drilling the
intermediate hole section at 11,634’ MD, with a throw of ~15’. At the Kuparuk
penetration of 3H-36, fault 1 is interpreted to be ~800’ to the southeast based on
seismic data and is roughly parallel to fault 1. Fault 2 was encountered in the offset,
parallel horizontal wellbore 3H-35.
x Fault 3 is a seismically identified fault that was predicted to be at 13,052’ MD.
Seismic data indicates that both have a north-south strike, roughly parallel to fault 1
and 2. Fault 3 was not definitively observed in this well but was present in the offset,
parallel horizontal wellbore 3H-35.
x Fault 4 was encountered in the 3H-36 lateral at 14,734’ MD with ~2’ of throw, faulting
the wellbore from the Kuparuk C4 sands onto the Kuparuk C4 sands. This fault was
not resolved on seismic, its extent is unknown . Losses were taken while crossing
this fault.
x Fracture zone 5 was encountered in the 3H-36 lateral at 15,477’ MD. Its extent is
unknown due to the small throw. Losses were taken while crossing this fracture zone.
x Fault 6 was not penetrated with the 3H-36 well bore but is interpreted in seismic data
as a major graben bounding fault approximately 500’ to the south of the 3H-36 well,
paralleling the wellbore with a . This fault is ~1,700’ to the northeast and parallel to
the 3H-37 drilled well path for the entirety of the lateral, with a down to the north throw
of ~20’-30’.
Fracture gradients within the top seal intervals would not be exceeded during fracture stimulation and
would therefore confine injected fluids to the pool. CPAI has formed the opinion, based on seismic,
well and other subsurface information currently available that the apparent faults will not interfere with
containment.
Maximum principle stress orientation in the area for the Kuparuk interval is N30W to N15W and
hydraulic fractures are expected to propagate at an oblique angle ~15 – 30 degrees to the drilled
wellbore. Faults observed in the wellbore and in seismic data are isolated with swell packers and blank
pipe. If there are indications that a fracture has intersected a fault during fracturing operations,
ConocoPhillips will go to flush and terminate the stage immediately.
Superseded
Fault
number
Well
Name
Depth
MD (ft)
Depth
TVDSS (ft)
Vertical
Displacement
(ft)
Loss
(bbls/hr)
1 3H-36 10850’ 5421 65’ None
2 3H-36 11634’ 5650 15’ None
3 3H-36 13052’ 5865 N/A None
4 3H-36 14734’ 5875 2’ 30-60
5 (fracture) 3H-36 15477’ 5877 0’ 30-60
6 500’ S of
3H-36 N/A N/A 20’ – 30’ N/A
Superseded
Plat 2: 3H-36 Fault Analysis
Superseded
SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM
20 AAC 25.283(a)(12)
3H-36 was completed in 2023 as a horizontal producer in the Kuparuk A and C formations.
The well was completed with a 4-½" tubing upper completion and a 4-1/2” liner with dart
actuated sliding sleeves lower completion. The first stage will be pumped through a toe
initiator valve. After the 1st stage we will drop a dart to shift open the 2nd stage sleeve and
isolate the first stage. We will then pump the 2nd stage and drop a dart after each remaining
stage, these balls will provide isolation from the previous stage and allow us to fracture from
the toe of the well towards the heel.
Proposed Procedure:
Halliburton Pumping Services: (Kuparuk A/C Frac)
1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition
to identify any pre existing conditions.
2. Ensure all Pre-frac Well work has been completed and confirm the tubing and
annulus are filled with a freeze protect fluid to 2,000’ TVD.
3. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC.
4. MIRU 25 clean insulated Frac tanks, with a berm surrounding the tanks that can
hold a single tank volume plus 10%. Load tanks with 100º F seawater (approx.
24,000 barrels are required for the treatment with breakdown, maximum pad, and
450 bbls usable volume per tank).
5. MIRU HES Frac Equipment.
6. PT Surface lines to 9,500 psi using a Pressure test fluid.
7. Test IA Pop off system to ensure lines are clear and all components are functioning
properly.
8. Bring up pumps and increase annulus pressure from 2,500 psi to 3,500 psi as the
tubing pressures up.
9. Pump approx. 300 bbl breakdown stage (30# Hybor G) according to the attached
excel HES pump schedule. Bring pumps up to maximum rate of 30 BPM as quick
as possible, pressure permitting. Ensure sufficient volume is pumped to load the
well with Frac fluid, prior to shut down.
10. Perform a hard shut down, Obtain ISIP and fluid efficiency estimates.
11. Pump the Frac job by following attached HES schedule @ 30bpm with a maximum
expected treating pressure of 7,550 psi.
12. RDMO HES Equipment. Freeze Protect the tubing and wellhead if not able to
complete following the flush.
13. Well is ready for Post Frac well prep for flowback (Slickline and possibly CTU).
g
f7,550
SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID
RECOVERY PLAN 20 AAC 25.283(a)(13)
Flowback will be initiated through a de-sander unit until the fluids clean up at which time it will
be turned over to production.
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.4115006LEASE3H-36SALES ORDERBHST (°F)146LONG-150.057078FORMATIONKuparukDATE Max Pressure (psi)9000*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In1:11:25 1-2 Calcium Chloride Prime Up Pressure Test 5 1,260 30 30 0:06:00 1:11:25 1-3 Shut-In Shut-In1:05:25 1-4 30# Linear Pump-In 5 1,260 30 30 0:06:00 1:05:25 1.00 30.00 2.00 0.25 0.151-5 30# Hybor G Establish Stable Fluid 15 8,400 200 200 0:13:20 0:59:25 2.00 1.00 0.75 30.00 2.00 0.25 0.151-6 30# Hybor G Minifrac 15 6,300 150 150 0:10:00 0:46:05 2.00 1.00 0.75 30.00 2.00 0.25 0.151-7 30# Linear Flush 30 10,992 262 262 0:08:43 0:36:05 1.00 30.00 2.00 0.25 0.151-8 Shut-In Shut-In0:27:22 1-9 30# Hybor G Establish Stable Fluid 15 8,400 200 200 0:13:20 0:27:22 2.00 1.00 0.75 30.00 2.00 0.25 0.151-10 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:14:02 2.00 1.00 0.75 30.00 2.00 0.25 0.151-11 30# Hybor G Conditioning Pad 100M 0.50 30 5,000 119 122 2,500 0:04:04 0:10:04 2.00 1.00 0.75 30.00 2.00 0.25 0.151-12 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 1,716 41 43 1,716 0:01:25 0:06:00 2.00 1.00 0.75 30.00 2.00 0.25 0.151-13 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 1,560 37 40 3,120 0:01:21 0:04:35 2.00 1.00 0.75 30.00 2.00 0.25 0.151-14 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 1,560 37 42 4,680 0:01:24 0:03:13 2.00 1.00 0.75 30.00 2.00 0.25 0.151-15 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 871 21 24 3,484 0:00:49 0:01:49 2.00 1.00 0.75 30.00 2.00 0.25 0.151-16 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:01:00 1.00 30.00 2.00 0.25 0.152-1 30# Linear Displacement 30 10,761 256 256 0:08:32 0:31:56 1.00 30.00 2.00 0.152-2 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:23:23 2.00 1.00 0.75 30.00 2.00 0.25 0.152-3 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:16:43 2.00 1.0000 0.75 30.00 2.00 0.25 0.152-4 30# Hybor G Conditioning Pad 100M 0.50 30 5,000 119 122 2,500 0:04:04 0:12:45 2.00 1.00 0.75 30.00 2.00 0.25 0.152-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 2,640 63 66 2,640 0:02:11 0:08:42 2.00 1.00 0.75 30.00 2.00 0.25 0.152-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 2,400 57 62 4,800 0:02:05 0:06:30 2.00 1.00 0.75 30.00 2.00 0.25 0.152-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 2,400 57 65 7,200 0:02:10 0:04:25 2.00 1.00 0.75 30.00 2.00 0.25 0.152-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 1,340 32 38 5,360 0:01:15 0:02:15 2.00 1.00 0.75 30.00 2.00 0.25 0.152-9 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:01:00 1.00 30.00 2.00 0.25 0.153-1 30# Linear Displacement 30 10,455 249 249 0:08:18 0:42:13 1.00 30.00 2.00 0.153-2 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:33:55 2.00 1.00 0.75 30.00 2.00 0.25 0.153-3 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:27:15 2.00 1.00 0.75 30.00 2.00 0.25 0.153-4 30# Hybor G Conditioning Pad 100M 0.50 30 8,500 202 207 4,250 0:06:54 0:23:17 2.00 1.00 0.75 30.00 2.00 0.25 0.153-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 5,280 126 131 5,280 0:04:23 0:16:23 2.00 1.00 0.75 30.00 2.00 0.25 0.153-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 4,800 114 124 9,600 0:04:09 0:12:00 2.00 1.00 0.75 30.00 2.00 0.25 0.153-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 4,800 114 130 14,400 0:04:20 0:07:51 2.00 1.00 0.75 30.00 2.00 0.25 0.153-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 2,680 64 75 10,720 0:02:31 0:03:31 2.00 1.00 0.75 30.00 2.00 0.25 0.153-9 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:01:00 1.00 30.00 2.00 0.25 0.154-1 30# Linear Displacement 30 10,203 243 243 0:08:06 0:39:46 1.00 30.00 2.00 0.154-2 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:31:40 2.00 1.00 0.75 30.00 2.00 0.25 0.154-3 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:25:00 2.00 1.00 0.75 30.00 2.00 0.25 0.154-4 30# Hybor G Conditioning Pad 100M 0.50 30 8,480 202 207 4,240 0:06:53 0:21:02 2.00 1.00 0.75 30.00 2.00 0.25 0.154-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 1,696 40 42 1,696 0:01:24 0:14:09 2.00 1.00 0.75 30.00 2.00 0.25 0.154-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 1,749 42 45 3,498 0:01:31 0:12:44 2.00 1.00 0.75 30.00 2.00 0.25 0.154-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 2,650 63 72 7,950 0:02:23 0:11:14 2.00 1.00 0.75 30.00 2.00 0.25 0.154-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 2,915 69 82 11,660 0:02:44 0:08:50 2.00 1.00 0.75 30.00 2.00 0.25 0.154-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30 2,650 63 77 13,250 0:02:35 0:06:06 2.00 1.00 0.75 30.00 2.00 0.25 0.154-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30 2,491 59 75 14,946 0:02:31 0:03:31 2.00 1.00 0.75 30.00 2.00 0.25 0.154-11 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:01:00 1.00 30.00 2.00 0.25 0.155-1 30# Linear Displacement 30 9,673 230 230 0:07:41 0:34:55 1.00 30.00 2.00 0.155-2 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:27:14 2.00 1.00 0.75 30.00 2.00 0.25 0.155-3 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:20:34 2.00 1.00 0.75 30.00 2.00 0.25 0.155-4 30# Hybor G Conditioning Pad 100M 0.50 30 5,000 119 122 2,500 0:04:04 0:16:36 2.00 1.00 0.75 30.00 2.00 0.25 0.155-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 3,960 94 98 3,960 0:03:17 0:12:32 2.00 1.00 0.75 30.00 2.00 0.25 0.155-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 3,600 86 93 7,200 0:03:07 0:09:15 2.00 1.00 0.75 30.00 2.00 0.25 0.155-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 3,600 86 97 10,800 0:03:15 0:06:08 2.00 1.00 0.75 30.00 2.00 0.25 0.155-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 2,010 48 56 8,040 0:01:53 0:02:53 2.00 1.00 0.75 30.00 2.00 0.25 0.155-9 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:01:00 1.00 30.00 2.00 0.25 0.156-1 30# Linear Displacement 30 9,116 217 217 0:07:14 0:41:33 1.00 30.00 2.00 0.25 0.156-2 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:34:19 2.00 1.00 0.75 30.00 2.00 0.25 0.156-3 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:27:39 2.00 1.00 0.75 30.00 2.00 0.25 0.156-4 30# Hybor G Conditioning Pad 100M 0.50 30 9,600 229 234 4,800 0:07:48 0:23:41 2.00 1.00 0.75 30.00 2.00 0.25 0.156-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 1,920 46 48 1,920 0:01:36 0:15:53 2.00 1.00 0.75 30.00 2.00 0.25 0.156-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 1,980 47 51 3,960 0:01:43 0:14:18 2.00 1.00 0.75 30.00 2.00 0.25 0.156-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 3,000 71 81 9,000 0:02:42 0:12:35 2.00 1.00 0.75 30.00 2.00 0.25 0.156-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 3,300 79 93 13,200 0:03:06 0:09:52 2.00 1.00 0.75 30.00 2.00 0.25 0.156-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30 3,000 71 87 15,000 0:02:55 0:06:46 2.00 1.00 0.75 30.00 2.00 0.25 0.156-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30 2,820 67 85 16,920 0:02:51 0:03:51 2.00 1.00 0.75 30.00 2.00 0.25 0.156-11 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:01:00 1.00 30.00 2.00 0.25 0.157-1 30# Linear Displacement 30 8,890 212 212 0:07:03 0:50:04 1.00 30.00 2.00 0.25 0.157-2 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:43:01 2.00 1.00 0.75 30.00 2.00 0.25 0.157-3 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:36:21 2.00 1.00 0.75 30.00 2.00 0.25 0.157-4 30# Hybor G Conditioning Pad 100M 0.50 30 10,720 255 261 5,360 0:08:42 0:32:23 2.00 1.00 0.75 30.00 2.00 0.25 0.157-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 2,144 51 53 2,144 0:01:47 0:23:41 2.00 1.00 0.75 30.00 2.00 0.25 0.157-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 2,211 53 57 4,422 0:01:55 0:21:54 2.00 1.00 0.75 30.00 2.00 0.25 0.157-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 3,350 80 90 10,050 0:03:01 0:19:59 2.00 1.00 0.75 30.00 2.00 0.25 0.157-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 3,685 88 103 14,740 0:03:27 0:16:58 2.00 1.00 0.75 30.00 2.00 0.25 0.157-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30 3,350 80 98 16,750 0:03:16 0:13:30 2.00 1.00 0.75 30.00 2.00 0.25 0.157-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30 3,149 75 95 18,894 0:03:11 0:10:14 2.00 1.00 0.75 30.00 2.00 0.25 0.157-11 30# Linear Flush 30 8,890 212 212 0:07:03 0:07:03 1.00 30.00 2.00 0.25 0.157-12 Shut-In Shut-InInterval 1Kuparuk A Sand@ 17196.2 - 17198.98 ft 146.4 °FInterval 2Kuparuk A Sand@ 16834.7 - 16837.48 ft 146.4 °FInterval 3Kuparuk A Sand@ 16356 - 16358.78 ft 146.3 °FInterval 4Kuparuk A Sand@ 15961.7 - 15964.48 ft 146.3 °FInterval 5Kuparuk A Sand@ 15133 - 15135.78 ft 146.3 °FInterval 6Kuparuk A Sand@ 14261.3 - 14264.08 ft 146.3 °FInterval 7Kuparuk A Sand@ 13907.6 - 13910.38 ft 146.2 °FLiquid AdditivesDry Additives50-103-208380908606139 Conoco Phillips - 3H-36Planned Design1
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.4115006LEASE3H-36SALES ORDERBHST (°F)146LONG-150.057078FORMATIONKuparukDATE Max Pressure (psi)9000*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-208380908606139 8-1 Shut-In Shut-In0:54:34 8-2 Calcium Chloride Prime Up Pressure Test 5 1,260 30 30 0:06:00 0:54:34 8-3 Shut-In Shut-In0:48:34 8-4 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:48:34 1.00 30.00 2.00 0.25 0.158-5 30# Linear Displacement 30 8,611 205 205 0:06:50 0:47:34 1.00 30.00 2.00 0.25 0.158-6 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:40:44 2.00 1.00 0.75 30.00 2.00 0.25 0.158-7 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:34:04 2.00 1.00 0.75 30.00 2.00 0.25 0.158-8 30# Hybor G Conditioning Pad 100M 0.50 30 12,320 293 300 6,160 0:10:00 0:30:06 2.00 1.00 0.75 30.00 2.00 0.25 0.158-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 2,464 59 61 2,464 0:02:03 0:20:06 2.00 1.00 0.75 30.00 2.00 0.25 0.158-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 2,541 61 66 5,082 0:02:12 0:18:04 2.00 1.00 0.75 30.00 2.00 0.25 0.158-11 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 3,850 92 104 11,550 0:03:28 0:15:51 2.00 1.00 0.75 30.00 2.00 0.25 0.158-12 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 4,235 101 119 16,940 0:03:58 0:12:23 2.00 1.00 0.75 30.00 2.00 0.25 0.158-13 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30 3,850 92 112 19,250 0:03:45 0:08:25 2.00 1.00 0.75 30.00 2.00 0.25 0.158-14 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30 3,619 86 109 21,714 0:03:39 0:04:39 2.00 1.00 0.75 30.00 2.00 0.25 0.158-15 30# Linear Spacer and Dart Drop 30 1,260 30 30 0:01:00 0:01:00 1.00 30.00 2.00 0.25 0.159-1 30# Linear Displacement 30 8,332 198 198 0:06:37 0:55:14 1.00 30.00 2.00 0.25 0.159-2 30# Hybor G Establish Stable Fluid 30 8,400 200 200 0:06:40 0:48:37 2.00 1.00 0.75 30.00 2.00 0.25 0.159-3 30# Hybor G Pad 30 5,000 119 119 0:03:58 0:41:57 2.00 1.00 0.75 30.00 2.00 0.25 0.159-4 30# Hybor G Conditioning Pad 100M 0.50 30 13,280 316 323 6,640 0:10:47 0:37:59 2.00 1.00 0.75 30.00 2.00 0.25 0.159-5 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 1.00 30 2,656 63 66 2,656 0:02:12 0:27:12 2.00 1.00 0.75 30.00 2.00 0.25 0.159-6 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 2.00 30 2,739 65 71 5,478 0:02:22 0:25:00 2.00 1.00 0.75 30.00 2.00 0.25 0.159-7 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 3.00 30 4,150 99 112 12,450 0:03:45 0:22:38 2.00 1.00 0.75 30.00 2.00 0.25 0.159-8 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 4.00 30 4,565 109 128 18,260 0:04:17 0:18:53 2.00 1.00 0.75 30.00 2.00 0.25 0.159-9 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 5.00 30 4,150 99 121 20,750 0:04:03 0:14:36 2.00 1.00 0.75 30.00 2.00 0.25 0.159-10 30# Hybor G Proppant Laden Fluid Wanli 20/40 Ceramic 6.00 30 3,901 93 118 23,406 0:03:57 0:10:33 2.00 1.00 0.75 30.00 2.00 0.25 0.159-11 30# Linear Flush 30 8,332 198 198 0:06:37 0:06:37 1.00 30.00 2.00 0.25 0.159-12 Shut-In Shut-In467,309 11,126 11,639 481,950Design Total (gal)Design Total (lbs)CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-6349,197443,000(gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)115,59238,950Initial Design Material Volume 698.4 464.8 261.9 13,943.7 929.6 105.9 69.7-2,520-Whole Units to be ordered--CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-6-(gpm) (gpm) (gpm) ppm ppm ppm ppm-Max Additive Rate 2.5 1.3 0.9 37.8 2.5 0.3 0.2-Min Additive Rate7:01:39 Interval 9Kuparuk A Sand@ 13034.4 - 13037.18 ft 146.1 °FInterval 8Kuparuk A Sand@ 13471.5 - 13474.28 ft 146.2 °FProppant TypeWanli 20/40 Ceramic100M---Fluid Type30# Hybor G30# LinearSeawaterCalcium Chloride ----Conoco Phillips - 3H-36Planned Design2
Hydraulic Fracturing Fluid Product Component Information Disclosure
2023-05-12
Alaska
HARRISON BAY
50-103-20838
CONOCOPHILLIPS
3H 36
-150.0570
70.4115
NAD83
none
Oil
5963
467309
Hydraulic Fracturing Fluid Composition:
Trade Name Supplier Purpose Ingredients
Chemical
Abstract
Service
Number
(CAS #)
Maximum Ingredient
Concentration in
Additive (% by mass)**
Maximum
Ingredient
Concentration
in HF Fluid (%
by mass)**
Ingredient Mass
lbs Comments Company
First
Name Last Name Email Phone
SEAWATER (SG 8.52) Halliburton Base Fluid Water 7732-18-5 100.00%88.11638%3981473 Density = 8.52 Halliburton
BE-6(TM) Bactericide Halliburton Microbiocide Listed Below Listed Below 0
CL-28M CROSSLINKER Halliburton Crosslinker Listed Below Listed Below 0
LoSurf-300D Halliburton Non-ionic Surfactant Listed Below Listed Below 0
LVT-200
Baker
Hughes Additive Listed Below Listed Below 0 NA
MO-67 Halliburton pH Control Listed Below Listed Below 0
OPTIFLO-II DELAYED
RELEASE BREAKER Halliburton Breaker Listed Below Listed Below 0
OPTIFLO-III DELAYED
RELEASE BREAKER Halliburton Breaker Listed Below Listed Below 0
SP BREAKER Halliburton Breaker Listed Below Listed Below 0
WG-36 GELLING AGENT Halliburton Gelling Agent Listed Below Listed Below 0
Ceramic Proppant - Wanli Wanli Proppant Listed Below Listed Below 0 NA
SAND, COMMON BROWN
100 MESH Halliburton Proppant Listed Below Listed Below 0 NA
Calcium Chloride Customer Salt Solution Listed Below Listed Below 0 NA
Ingredients
Listed
Above Listed Above 0.00%0.00000%0
1,2,4 Trimethylbenzene 95-63-6 1.00%0.00078%36
2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00155%70
2-Methyl-4-isothiazolin-3-one 2682-20-4 0.01%0.00002%1
5-Chloro-2-methyl-3(2H)-
Isothaiazolone 26172-55-4 0.01%0.00002%1
Ammonium persulfate 7727-54-0 100.00%0.02286%1033
Borate salts Proprietary 60.00%0.09816%4436
Denise Tuck,
Halliburton, 3000
N. Sam Houston
Pkwy E.,
Houston, TX
77032, 281-871-
6226 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
C.I. pigment Orange 5 3468-63-1 1.00%0.00002%2
Calcium Chloride 10043-52-4 100.00%0.56657%25600
Calcium magnesium carbonate 16389-88-1 1.00%0.00164%74
Corundum 1302-74-5 65.00%6.37280%287950
Crystalline silica, quartz 14808-60-7 100.00%0.86858%39247
Distillates (petroleum),
hydrotreated light 64742-47-8 100.00%0.01532%692
Ethanol 64-17-5 60.00%0.04693%2121
Gluteraldehyde 111-30-8 1.00%0.00164%74
Guar gum 9000-30-0 100.00%0.30776%13906
Heavy aromatic petroleum
naphtha 64742-94-5 30.00%0.02346%1061
Inorganic mineral 1317-65-3 5.00%0.00818%370
Inorganic mineral Proprietary 1.00%0.00164%74 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Magensium chloride 7786-30-3 0.01%0.00002%1
Magnesium nitrate 10377-60-3 0.01%0.00002%1
Methanesulfonic acid, 1-hydroxy-,
sodium salt 870-72-4 0.10%0.00016%8
Mullite 1302-93-8 45.00%4.41194%199350
Naphthalene 91-20-3 5.00%0.00391%177
Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.02346%1061 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Oxyalkylated phenolic resin Proprietary 10.00%0.00782%354 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Oxylated phenolic resin Proprietary 30.00%0.00686%310 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Poly(oxy-1,2-ethanediyl), alpha-(4-
nonylphenyl)-omega-hydroxy-,
branched 127087-87-0 5.00%0.00391%177
Polymer Proprietary 1.00%0.00164%74 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Potassium chloride 7447-40-7 5.00%0.00818%370
Sodium bisulfate 7681-38-1 0.10%0.00016%8
Sodium chloride 7647-14-5 5.00%4.40643%199102
Sodium hydroxide 1310-73-2 30.00%0.01842%833
Sodium persulfate 7775-27-1 100.00%0.00002%1
Sodium sulfate 7757-82-6 0.10%0.00000%1
Water 7732-18-5 100.00%0.15956%7210
* Total Water Volume sources may include fresh water, produced water, and/or recycled water _
** Information is based on the maximum potential for concentration and thus the total may be over 100%
Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.Version web 1.3
All component information listed was obtained from the supplier’s Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who
provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this
information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D.
Production Type:
True Vertical Depth (TVD):
Total Water Volume (gal)*:
MSDS and Non-MSDS Ingredients are listed below the green line
Well Name and Number:
Longitude:
Latitude:
Long/Lat Projection:
Indian/Federal:
Fracture Date
State:
County:
API Number:
Operator Name:
Stage Job Size
(lb)
Top MD
(ft)
Top TVD
(ft)
Propped Half-
Length (ft)
Fracture
Height (ft)
Avg Fracture
Width (in)
1 15,500 17,196 5,927 140 20 0.386
2 22,500 16,835 5,923 180 25 0.41
3 44,250 16,356 5,913 340 35 0.447
4 57,240 15,962 5,912 700 35 0.448
5 32,500 15,133 5,912 240 35 0.433
6 64,800 14,261 5,902 780 45 0.453
7 72,360 13,908 5,904 840 40 0.466
8 83,160 13,472 5,907 880 40 0.474
9 89,640 13,034 5,900 700 40 0.471
Disclaimer Notice:
KRU 3H-36
This model was generated using commercially available modeling software and is based on
engineering estimates of reservoir properties. Conoco Phillips 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
1
Davies, Stephen F (OGC)
From:Morrow, Dustin W <Dustin.W.Morrow@conocophillips.com>
Sent:Wednesday, May 17, 2023 10:32 AM
To:Davies, Stephen F (OGC); Hobbs, Greg S; Wagner III, Trey H; Metzgar, Kyle N
Cc:Loepp, Victoria T (OGC); Wallace, Chris D (OGC)
Subject:RE: [EXTERNAL]KRU 3H-26 (PTD 222-014; Sundry 323-286) - Operations Start Date
Mr.Davies,
Wehavebeenreviewingtheconcernsraisedandwewouldliketomeetanddiscussinordertoaccuratelyunderstand
yourconcernsandgetyoutheneededinformation.
Doyouhavetimethismorningorintheearlyafternoon?
Ithinkeverybodyonourendcanfreeuptomeetyourschedule.
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Tuesday,May16,20232:14PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Dustin,
IhavemanyconcernsrelatedtoconfinementoffluidsafterviewingCPAI’sFaultAnalysismapandrevised
descriptions.ThepotentialforFaultsandFractureZones3,4,5,and6tointerferewithcontainmentisconcerning,
especiallyFaults3,4andFractureZone5.
x Howshallowandhowdeepwithinthegeologicsectionareeachofthesefaultsresolvableontheseismic
data?Inotherwords,howfarupintotheoverlyingconfiningintervalandhowfardownintotheunderlying
confiningintervaldoeachofthesefaultsandfracturesextend?
x Whydoesn’tFault3presentaconcernsinceCPAIisapparentlyfracturingimmediatelyadjacenttothatfault,
whichalsoappearstobeparallelwiththemaximumprinciplestressdirectioninthisarea?
x Whywon’tFault3serveasadirectconduitto3HͲ35?
x WilltheinducedfracturesfromtheportlocatedbetweenFault4andFractureZone5beofsufficientlengthto
intersecteitherofthosetwofeatures?HowfarawayfromFault4andFractureZone5willthemodeledfrac
wingsterminate?
x WhyisCPAInotconcernedwithfracturingbetweenandverynearFault4andFractureZone5sinceboth
featuresencounteredsignificantlossesduringdrilling?Won’tthosefaultsandfractureschannelinjectedfrac
fluidsoutofzone?
x Willanyoftheothermodeledfracturesbeofsufficientlengthtointersectanyofthemappedfeatures?
x IsFault6ofsufficientverticaldisplacementtoimpedesupportofproductionwellslocatedtothesoutheast?
Thanksforyourhelp,
SteveDavies
AOGCC
2
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Tuesday,May16,202312:49PM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
ThankyouSteve,Ireallyappreciateyouandyourteam.
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Tuesday,May16,202312:21PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Dustin,
Thankstoyouallforyourhelpwiththis.IwillletyouknowifIhaveadditionalquestions.Victoriamayhaveadditional
questions.Ifso,theywillbesentinaseparateemail.
Thanksandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Tuesday,May16,202312:16PM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Yes,
Herearetheresults,heagreedwithyoucommentsandcleanedupthedescriptionsandanewannotatedmapwas
created.Pleaseletmeknowifthereisanythingelse,Icanalsoputyouintouchwithhim.
Ialsoattachedasurvey,pleaseletmeknowifthereisanythingelse.
Waitingonthelogsstill…
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)
3
CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that six faults
or fracture systems transect the Kuparuk formation or enter the confining zone within one half mile radius of the wellbore
trajectory for 3H-36.
x Fault 1 was encountered in the Torok Fm above the HRZ while drilling the intermediate hole
section at 10,850’ MD. Based on a thinner Torok than offset wells, the throw is interpreted to be 65’.
At the Kuparuk penetration of 3H-36, fault 1 is interpreted to be ~2100’ to the southeast based on
seismic data, with a strike perpendicular to the orientation of 3H-36. Fault 1 was encountered in the
offset parallel horizontal wellbore 3H-35.
x Fault 2 is a fault zone that was encountered in the overburden in the Lower Kalubik while drilling
the intermediate hole section at 11,634’ MD, with a throw of ~15’. At the Kuparuk penetration of
3H-36, fault 1 is interpreted to be ~800’ to the southeast based on seismic data and is roughly
parallel to fault 1. A splay of Fault 2 was encountered in the offset, parallel horizontal wellbore 3H-
35.
x Fault 3 is a seismically identified fault zone that was predicted to be at 13,052’ MD. Seismic
data indicates that both have a north-south strike, roughly parallel to fault 1 and 2. Fault 3 was not
definitively observed in this well but an interpreted splay was present in the offset, parallel
horizontal wellbore 3H-35.
x Fault 4 was encountered in the 3H-36 lateral at 14,734’ MD with ~2’ of throw, faulting the
wellbore from the Kuparuk C4 sands onto the Kuparuk C4 sands. This fault was not resolved on
seismic, its extent is unknown . Losses were taken while crossing this fault.
x Fracture zone 5 was encountered in the 3H-36 lateral at 15,477’ MD. Its extent is unknown due
to the small throw. Losses were taken while crossing this fracture zone.
x Fault 6 was not penetrated with the 3H-36 well bore but is interpreted in seismic data as a major
graben bounding fault approximately 500’ to the south of the 3H-36 well, paralleling the wellbore
with a down to the north throw of ~20-30’.
Fracture gradients within the top seal intervals would not be exceeded during fracture stimulation and would therefore
confine injected fluids to the pool.ௗ CPAI has formed the opinion, based on seismic, well and other subsurface information
currently available that the apparent faults will not interfere with containment.
Maximum principle stress orientation in the area for the Kuparuk interval is N30W to N15W and hydraulic fractures are
expected to propagate at an oblique angle ~15 – 30 degrees to the drilled wellbore. Faults observed in the wellbore and in
seismic data are isolated with swell packers and blank pipe. If there are indications that a fracture has intersected a fault
during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately.
Fault
numberWellNameDepthMD
(ft)
DepthTVDSS
(ft)
Vertical
Displacement
(ft)
Loss
(bbls/hr)
13HͲ3610850’542165’None
23HͲ3611634’565015’None
33HͲ3613052’5865N/ANone
43HͲ3614734’58752’30Ͳ60
5(fracture)3HͲ3615477’58770’30Ͳ60
6500’Sof3HͲ
36N/AN/A20’–30’N/A
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
4
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Tuesday,May16,202311:55AM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
ThankyouDustin.Iappreciateyourhelpwiththis.IsCPAI’sgeophysiciststillworkingonimprovingtheannotationson
theFaultAnalysismapandclarifyingthediscussionsfortheindividualfaults?
Thanksagainandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Tuesday,May16,202310:30AM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Hobbs,GregS<Greg.S.Hobbs@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Mr.Davies,
IspentalotoftimelookingforlogsbutIwasnotabletofindanything
ThebestrecordsIcouldfindyieldthefollowing:
Forthecementtops:
3HͲ28A–(Ihadthismisslabeledas3MͲ28A)
7”casingwasrunto12565’on2/29/96
200sxsofClassG(1.15ft3/sk)waspumped,noreportsoflostcirculationorlosses,theplugwasnotbumped,thefloats
held
CalculatedTOC:
100%efficiency~10,751’MD/4611’TVD
85%efficiency~11,023’MD/4693’TVD
3HͲ32
7”casingwasrunto13809’on2/4/00
200sxsofClassG(1.15ft3/sk)waspumped,minimalreturnsinitiallybutregainedfullcirculationonceondisplacement,
plugdidnotbumpbutthefloatsheld.
CalculatedTOC:
85%efficiency~12,267’MD/5,606’TVD(reducedefficiencypotentialduetoinitiallossofreturns)
75%efficiency~12,448’MD/5,664’TVD
ProposedTops
5
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Monday,May15,20233:20PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Dustin,
ForSection10,couldCPAIpleaseprovidecalculatedtopsofcementfortheotherwellswithintheAreaofReview(3HͲ32
and3MͲ28A)todemonstratecementͲisolationfortheKuparukreservoir?
Thanksagainforyourhelp,
SteveDavies
AOGCC
From:Davies,StephenF(OGC)
Sent:Monday,May15,20233:07PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
6
Dustin,
I’mabitconfusedbySection11andtheaccompanyingfaultanalysismap.Sixfaults/fracturezonesarediscussed,but
thereappeartobe7ormaybe8faults/fracturesmarkedonthemapwithintheAOR.ThedescriptionforFault6
describesaWNWͲtrendingfaultthatisn’tshownonthemap,andthedescriptionappearstobeincomplete
(“…parallelingthewellborewitha.”)anditdoesn’tmakesense(“…isinterpretedintheseismicdataasamajorgraben
boundingfaultapproximately500’tothesouthofthe3HͲ36wellparallelingthewellborewitha.Thisfaultis~1,700’
tothenortheastandparallelto3HͲ37drilledwellpathfortheentiretyofthelateral…”).
Pleaselabelthefaultsonthemapwiththesamenumbersasthecorrespondingdescriptionsandindicatethe
downthrownsideofeachfault.PleasealsoreͲreadandclarifythefaultdescriptionsasneeded.
Thanksagain.
SteveDavies
AOGCC
From:Davies,StephenF(OGC)
Sent:Monday,May15,202312:55PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
ThankyouDustin.Ifoundthestagetooldepthonthewellschematic.Ididn’tseeanyoftheotherinformationeither
attachedtoemailsorloggedintoourcentraldatabase,butthisisanewlydrilledwell.ApologiesifI’veoverlookedany
datathathasalreadybeensubmitted.
Thanksagain.
SteveDavies
AOGCC
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Monday,May15,202312:51PM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Yessir,
Iwillgetallthatinformationtrackeddownandfigureoutwhyithasnotbeensubmittedalready.
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Monday,May15,202312:26PM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
7
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
Dustin,
CouldCPAIpleaseprovidefieldcopiesofthecementreports,themeasureddepthofthe7Ͳ5/8”casingstagetool,
directionalsurveydata,CBL,andwelllogsfor3HͲ26?Directionalsurveydatainspreadsheet,tabͲdelimited,orcommaͲ
delimitedformisfine.Welllogsin.lasortabͲdelimitedformatarepreferred.
PleasenotethatthesefieldͲqualitydatadonotmeetthefinalreportingrequirementsof20AAC25.071.
Thanksforyourhelp,
SteveDavies
AOGCC
From:Davies,StephenF(OGC)
Sent:Monday,May15,202310:04AM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
ThankyouDustin.SeveralpeoplehereatAOGCCareinvolvedinthereviewanddecisionprocess,andI’mnotcertainof
theirschedulesorcurrentworkloads.Obviously,thelongertheleadtimethatCPAIcanprovide,thebetter.
Regards,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
From:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Sent:Monday,May15,20239:44AM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:RE:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
MorningSteve,
WeareplanningtoberiggedinasearlyasWednesdaybuthaveaskedourfracsupervisortoplanforMay19thdueto
Sundrysubmittaldate.
Iamtryingtocoachtheplanningteamonrealistictimesforreceivinganapprovedsundry.
Wedon’thavealltherequiredinformationuntilthelinerisonbottomandset.
Iwillworkonourprocessworktogettheseoutsooner,Idonotlikerequestingarush.
Thankyou,
DustinW.Morrow
StaffCompletionsEngineer
ConocoPhillipsAlaska
Cell:832Ͳ493Ͳ9141
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.
8
Office:907Ͳ263Ͳ4752
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Monday,May15,20239:17AM
To:Morrow,DustinW<Dustin.W.Morrow@conocophillips.com>
Cc:Loepp,VictoriaT(OGC)<victoria.loepp@alaska.gov>;Wallace,ChrisD(OGC)<chris.wallace@alaska.gov>
Subject:[EXTERNAL]KRU3HͲ26(PTD222Ͳ014;Sundry323Ͳ286)ͲOperationsStartDate
CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you
recognize the sender and know the content is safe.
Dustin,
CPAI’sSundryApplicationtofracturestimulateKRU3HͲ26wasreceivedbyAOGCConFridayafternoon.Theestimated
operationsstartdateisWednesday,May17th.Howfirmisthatoperationsstartdate?Pleasebeawarethattwo
businessdaysisafairlyslimmargintoworkthisapplicationthroughAOGCC’sreviewprocessforfractureͲstimulation
operations.Pleaseletusknowsothatwecanprioritizeotherexistingwork.
Thanksandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3H-36 (PTD No. 222-014; Sundry No. 323-286) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 May 17, 2023 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 5/15/2023 (a)(2) Plat Provided with application. SFD 5/15/2023 (a)(2)(A) Well location Provided with application. Well lies in Section 12, 11, 2, and 3 of T12N, R8E, UM and Sections 34 and 33 of T13N, R8E, UM. The planned fracturing interval lies entirely within Section 33 of T13N, R8E, UM. SFD 5/15/2023 (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 May 15, 2023), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of KRU 3H-36. There are no subsurface water rights or temporary subsurface water rights within 7 miles of the surface location of KRU 3H-36 or within 5 miles of the proposed fracturing interval in KRU 3H-36. SFD 5/15/2023 (a)(2)(C) Identify all well types within ½ mile List of all wells within ½-mile radius of the KRU 3H-36 well path is provided with application. SFD 5/15/2023 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the Kuparuk River Unit per Aquifer Exemption Title 40 CFR 147.402(b)(3). An outline of the EPA’s current Aquifer Exemption Area for the Kuparuk River Unit is available on 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 5/15/2023 (a)(4) Baseline water sampling plan None required: No freshwater aquifers are present. SFD 5/15/2023
20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3H-36 (PTD No. 222-014; Sundry No. 323-286) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 May 17, 2023 (a)(5) Casing and cementing information Provided with application. well schematic attached, cementing information and evaluation provided. CDW 05/15/2023 (a)(6) Casing and cementing operation assessment 4.5” tubing will be anchored with a packer set at 12270 ft with shallowest frac sleeve at 13034 ft. 10-3/4” surface casing cemented to surface. TOC in 7-5/8” casing at 5500 ft, with a 2 stage cement job utilizing a ES tool at 7293 ft. No issues with cement for the upcoming stimulation. 7-5/8”casing was pressure tested to 3850 psi . CDW 05/15/2023 (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 5/15/2023 (a)(6)( B) Each hydrocarbon zone is isolated Yes: Surface casing was set at 3,200’ MD (-2,970’ TVD) and cemented with operator-reported good returns at surface. For KRU 3H-36, 13-5/8” hole was drilled from the base of surface casing to a total depth of about 12,604’ MD (-5,839’ TVDSS) and 7-5/8” casing was set at those same depths. Based on operator-supplied information, the Kuparuk, Moraine, and Coyote sands are all cement isolated in this well. SFD 5/15/2023 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3850 psi MITIA completed, 4550 psi MITT completed. CDW 05/15/2023 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi wellhead max. frac. Pressure 7360 psi. Pump knock out 7860 psi and tubing ePRV 8360 psi., lines test 9500 psi. CDW 05/15/2023
20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3H-36 (PTD No. 222-014; Sundry No. 323-286) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 May 17, 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: Kalubik and HRZ mudstones having an aggregate thickness of about 400’ true vertical thickness (TVT). Fracture gradient is expected to range from about 0.83 psi/ft (16 ppg EMW). Fracturing Zone: Kuparuk shallow marine deposits consisting of very fine- to fine-grained sandstone that grades downward to siltstone and shale. Fracture gradient is expected to range from about 0.68 psi/ft (13.1 ppg EMW). Lower confining zones: Mudstones assigned to the Miluveach Shale having an aggregate thickness of about 500’ TVT. Fracture gradient is expected to range from about 0.81 psi/ft (15.5 ppg EMW). SFD 5/15/2023 (a)(10) Location, orientation, report on mechanical condition of each well 3 wells identified and evaluated. CDW 05/15/2023 (a)(11) Sufficient information to determine wells will not interfere with containment within ½ mile Yes. There are two wells within ½ mile of KRU 3H-36: 3H-28A and 3H-32. The Kuparuk is isolated by casing and cement in both of those wells. It is highly unlikely that those wells will interfere with containment for this fracturing operation. SFD 5/16/2023 (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 six faults or fracture zones within a ½-mile radius of KRU 3H-36. Following a review of relevant 3D seismic data and discussion with the Operator’s technical staff, it is likely that any of these faults and fracture zones will interfere with containment of the injected fracturing fluids. However, if—during fracturing operations—there are indications that any fracture stage has intersected a fault or natural fracture, the operator will go to flush and terminate the stage immediately. SFD 5/17/2023
20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3H-36 (PTD No. 222-014; Sundry No. 323-286) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 May 17, 2023 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/15/2023 (a)(12)(A) Estimated volume Provided with application. 11639 bbl total dirty vol including freeze protect. 481K lb total proppant CDW 05/15/2023 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/15/2023 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided, proprietary chemicals on file with AOGCC. CDW 05/15/2023 (a)(12)(D) Inert substances , weight or volume of each Provided with application. CDW 05/15/2023 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7360 psi. Max pressure is 7860 psi to ePRV of 8360 psi. With 3500 psi back pressure IA (IA popoff set 3600 psi), max tubing differential should be 3860 psi. CDW 05/15/2023 (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 140’ to 880’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 20’ to 40’ (top TVD of about 5,900’) so induced fractures may penetrate into, but not through, the overlying confining Kalubik and HRZ shales that combined are about 400’ thick in this area. SFD 5/15/2023 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 05/15/2023 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3500 psi back pressure, tested to 3850 psi, popoff set as 3600 psi CDW 05/15/2023 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing will be anchored with a packer set at 12270 ft with shallowest frac sleeve at 13034 ft. 10-3/4” surface CDW 05/15/2023
20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3H-36 (PTD No. 222-014; Sundry No. 323-286) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 May 17, 2023 casing cemented to surface. TOC in 7-5/8” casing at 5500 ft, with a 2 stage cement job utilizing a ES tool at 7293 ft. (c)(2) Tested >110% of max anticipated pressure differential Tubing tested to 4550 psi. Max pressure differential is estimated as 3860 psi (7360 with 3500 psi backpressure) so test of 4246 psi satisfies 110% CDW 05/15/2023 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9500 psi line pressure test, pump knock out 7860 psi with tubing ePRV set at 8360 psi. IA PRV set as 3600 psi. CDW 05/15/2023 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/15/2023 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3600 psi. Surface annulus open. Frac pressures continuously monitored. CDW 05/15/2023 (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 05/15/2023 (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 Confidential exploratory well.
20 AAC 25.283 Hydraulic Fracturing Application – Checklist KRU 3H-36 (PTD No. 222-014; Sundry No. 323-286) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 May 17, 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.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________KUPARUK RIV UNIT 3H-36
JBR 05/23/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
4" and 4-1/2" TJ's used for testing. Upper IBOP Failed greased and cycled retest passed. Accumulator bottles 16 @ 1028 psi
precharge average.
Test Results
TEST DATA
Rig Rep:M.Sam/ A.AllenOperator:ConocoPhillips Alaska, Inc.Operator Rep:B.Marmon/ W. Jeardoe
Rig Owner/Rig No.:Doyon 142 PTD#:2220140 DATE:4/23/2023
Type Operation:DRILL Annular:
250/2500Type Test:BIWKLY
Valves:
250/4000
Rams:
250/4000
Test Pressures:Inspection No:bopKPS230423144739
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5.5
MASP:
2401
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 FP
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8 P
#1 Rams 1 3-1/2" x 6" V P
#2 Rams 1 Blind/Shears P
#3 Rams 1 3-1/2" x 6" V P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 1 3-1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1700
200 PSI Attained P15
Full Pressure Attained P62
Blind Switch Covers:Pall Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6 @ 1975
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P15
#1 Rams P7
#2 Rams P7
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9999
9
9
FP
Upper IBOP Failed
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________KUPARUK RIV UNIT 3H-36
JBR 04/26/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:Tested gas alarms, annular tested w 5" DP, good test
TEST DATA
Rig Rep:Matt Sam / Andy AllenOperator:ConocoPhillips Alaska, Inc.Operator Rep:Adam Dorr / Byron Marmon
Contractor/Rig No.:Doyon 142 PTD#:2220140 DATE:3/25/2023
Well Class:DEV Inspection No:divAGE230329092138
Inspector Adam Earl
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:13.5 P
Vent Line(s) Size:16 P
Vent Line(s) Length:135 P
Closest Ignition Source:100 P
Outlet from Rig Substructure:119 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:NA
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:19 P
Knife Valve Open Time:9 P
Diverter Misc:0 NA
Systems Pressure:P3025
Pressure After Closure:P1950
200 psi Recharge Time:P8
Full Recharge Time:P47
Nitrogen Bottles (Number of):P6
Avg. Pressure:P2000
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
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KRU 3H-36 (PTD 222-014)
Conditions of Approval:
Approval is granted to run the LWD-Sonic on upcoming well with the following provisions:
1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as
soon as they become available. The evaluation is to include/highlight the intervals of competent
cement that CPAI is using to meet the objective requirements for annular isolation, reservoir
isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation
is not acceptable.
2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must
start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC.
Starting the log below the actual TOC based on calculations predicting a different TOC will not
be acceptable.
3. CPAI will provide a cement job summary report and evaluation along with the cement log and
evaluation to the AOGCC when they become available
4. CPAI will provide the results of the FIT when available.
5. Depending on the cement job results indicated by the cement job report, the logs and the FIT,
remedial measures or additional logging may be required.
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WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3H-36Initial Class/TypeDEV / PENDGeoArea890Unit11160On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2220140KUPARUK RIVER, KUPARUK RIV OIL - 490100NA1Permit fee attachedYes2Lease number appropriateYes3Unique well name and numberYes4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryYes6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18Conductor string providedYes19Surface casing protects all known USDWsYes264% excess20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgNoProductive interval will be completed with uncemented frac sleeves22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesRig has steel tanks; all waste to approved disposal wells24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYesAnti-collision analysis complete; no major risk failures26Adequate wellbore separation proposedYesDiverter line size and route meet regulation27If diverter required, does it meet regulationsYesMax formation pressure is 3002 psig(9.6 ppg EMW); will drill w/ 9.6-10.8 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 2401 psig; will test BOPs to 3500 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesH2S measures required33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)No3H-Pad wells are H2S-bearing. H2S measures are required.35Permit can be issued w/o hydrogen sulfide measuresYes36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate2/4/2022ApprVTLDate2/23/2022ApprDLBDate2/4/2022AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate-03JLC 3/3/2022
