Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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Originated: Delivered to:18-Jun-25Halliburton Alaska Oil and Gas Conservation Comm.Wireline & Perforating Attn.: Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska 99501Anchorage, Alaska 99518Office: 907-275-2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET#1 2B-02A 50-029-21154-01 910106459 Kuparuk River Multi Finger Caliper Field & Processed 14-Jun-25 0 12 2B-03B 50-029-21151-02 n/a Kuparuk River Radial Bond Record Field- Final 8-Mar-25 0 13 2F-09 50-029-21090-00 910080198 Kuparuk River Plug Setting Record Field- Final 23-May-25 0 14 2F-09 50-029-21090-00 910010602 Kuparuk River Radial Bond Record Field- Final 2-May-25 0 15 2G-17 50-029-23134-00 910106461 Kuparuk River Plug Setting Record Field- Final 9-Jun-25 0 16 2K-23 50-103-20125-00 910099510 Kuparuk River Multi Finger Caliper Field & Processed 2-Jun-25 0 17 2K-34 50-103-20688-00 910096425 Kuparuk River Multi Finger Caliper Field & Processed 15-Jun-25 0 18 2M-08 50-103-20184-00 910027001 Kuparuk River Multi Finger Caliper Field & Processed 9-May-25 0 19 2M-25 50-103-20152-00 910106929 Kuparuk River Plug Setting Record Field- Final 12-Jun-25 0 110 2M-25 50-103-20152-00 910106929 Kuparuk River Tubing Cut Record Field- Final 13-Jun-25 0 1PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date:216-087223-080184-036202-243190-014214-026192-101191-021T40589T40590T40591T40591T40592T40593T40594T40595T40596T405966/20/2025Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.06.20 08:42:29 -08'00'223-0802B-03B50-029-21151-02 n/aKuparuk RiverRadial Bond RecordField- Final8-Mar-2501
ConocoPhillips Alaska
700 G Street
Anchorage, AK 99501
Email: AKGGREDTSupport@ConocoPhillips.onmicrosoft.com
Date: May 27, 2025
FFROM:Anu Ambatipudi TO: Meredith Guhl
ConocoPhillips Alaska, Inc. AOGCC
700 G Street 333 W.7th Ave., Suite 100
Anchorage AK 99501 Anchorage, Alaska
DATA TRANSMITTAL
Kuparuk River Unit/Field
Well API #PTD #Comments
1H-112 50029237870100 2240320
3B-16A 50029212890100 2231250
2B-03B 50029211510200 2230800
2M-39 50103207950000 2181710
3S-612 50103207770000 2181110
3S-611 50103207740000 2181030
1H-108B 50029236080200 2180820
1H-110 50029236010000 2180310
1H-116 50029235940000 2180120
2S-06 50103207470000 2160850
2M-37 50103207450000 2160820
1D-39 50029229970000 2002160
1D-40A 50029229690100 2001900
2N-302 50103203800000 2011150
1R-03A 50029214060100 2000210
3H-37 50103208220000 2191940
2S-09A 50103207490100 2161280
T40450
T40451
T40452
T40453
T40454
T40455
T40456
T40457
T40458
T40459
T40460
T40461
T40462
T40463
T40464
T40465
T40466
By Gavin Gluyas at 1:15 pm, May 28, 2025
2B-03B 50029211510200 2230800
ConocoPhillips Alaska
700 G Street
Anchorage, AK 99501
Email: AKGGREDTSupport@ConocoPhillips.onmicrosoft.com
Colville River Unit/Field
Well API # PTD # Comments
CD5-31 50103208280000 2210020
CD5-96 50103208110000 2191620
CD4-499 50103208100000 2191610
CD5-26 50103208060000 2191070
CD5-98 50103208030000 2190590
CD5-24 50103207990000 2190060
CD5-23 50103207610000 2171550
CD5-19 50103207600000 2171210
CD5-22 50103207590000 2170890
CD5-316 50103207560000 2170400
CD3-111A 50103205260100 2170040
CD3-198 50103206370000 2110240
CD4-24 50103206020000 2090970
CD4-26 50103206000000 2090490
CD2-15 50103203860000 2011590
CD2-12 50103204550000 2030730
CD4-214 50103205370000 2061450
CD4-17 50103205340000 2061180
CD2-73 50103205900000 2081960
T40467
T40468
T40469
T40470
T40471
T40472
T40473
T40474
T40475
T40476
T40477
T40478
T40479
T40480
T40481
T40482
T40483
T40484
T40487
ConocoPhillips Alaska
700 G Street
Anchorage, AK 99501
Email: AKGGREDTSupport@ConocoPhillips.onmicrosoft.com
Greater Mooses Tooth Unit/Field
Well API # PTD # Comments
MT7-99 50103208450000 2221020
T40485
ConocoPhillips Alaska
700 G Street
Anchorage, AK 99501
Email: AKGGREDTSupport@ConocoPhillips.onmicrosoft.com
ConocoPhillips Alaska
700 G Street
Anchorage, AK 99501
Email: AKGGREDTSupport@ConocoPhillips.onmicrosoft.com
ConocoPhillips Alaska
700 G Street
Anchorage, AK 99501
Email: AKGGREDTSupport@ConocoPhillips.onmicrosoft.com
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________
ConocoPhillips Alaska, Inc. Development Exploratory
Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 8,350 feet feet
true vertical 6,255 feet feet
Effective Depth measured 7,705 feet 7141 feet
true vertical 5,826 feet 5475 feet
Perforation depth Measured depth 8069-8079'
8095-8115'
8116-8136'
feet
True Vertical depth 6062-6068'
6079-6093'
6093-6107'
feet
Tubing (size, grade, measured and true vertical depth) 3.5" 9.3# L-80 7197 5511
Packers and SSSV (type, measured and true vertical depth) Baker ZXP LTP 7141 5475
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:Kuparuk Oil Pool
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Dusty Ward
Contact Email:dusty.ward@conocophillips.com
Authorized Title:Completion Engineer Contact Phone:907-263-6531
2748
Burst Collapse
measured
TVD
Intermediate
Liner
8363
1209
Casing
Structural
6101
3-1/2"
8395
8350 6255
Plugs
Junk measured
Conductor
Surface
16"
9-5/8"
Length
75
3127
110
Job logs attached
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0025655 / ADL00256
Kuparuk Field/ Kuparuk Oil Pool
KRU 2B-03B
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-080
50-029-21151-00-00
P.O. Box 100360 Anchorage, AK 99510-03603. Address:
158
7"
942 102376
25 150247
92.6 Mlbs of 16/20 Wanli Ceramic Proppant, 3,000 lbs of 100 Mesh, and 3782 psi treating pressure
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing PressureGas-Mcf
MD
8,069' MD - 8,136' MD
Size
110
3161
324-302
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
39
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)
152
825
Development Stervice
GINJ SUSP SPLUG
Gas
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 3:46 pm, Jul 17, 2024
Prepared By:
William Martin
Dan Faur
Nannok Crew
Interval 1 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.
2B-03B
Conoco Phillips
Beechey Point County, AK
Post Job Report
Stimulation Treatment
API: 50-029-21151
Prepared for: Dusty Ward
June 21, 2024
A-Sand Formation
35# Hybor G
Table of Contents
Section Page(s)
Executive Summary
Actual Design
Wellbore Information
Interval Summary
Fluid System-Proppant Summary
Interval 1 Plots
Appendix
Well Summary
Chemical Summary
Planned Design
Water Straps
Water Analysis
Real-Time QC
Event Log
Prejob Break Test 6-19-24
Fann 15 min Zone 1
Sand Sieve Analysis
22
23
19
20
21
6
7
8 - 17
18
3
4
5
24
25
26
27
28
Conoco Phillips - 2B-03B TOC 2
62,150 gallons of 35# Hybor G
5,902 gallons of 35# Linear
1,000 gallons of Seawater
0 gallons of Freeze Protect
91,000 pounds of Wanli 16/20 Ceramic
4,000 pounds of 100M
61,136 gallons of 35# Hybor G
6,199 gallons of 35# Linear
252 gallons of Seawater
0 gallons of Freeze Protect
92,601 pounds of Wanli 16/20 Ceramic
3,000 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 June 21, 2024 a stimulation treatment was performed in the A-Sand formation on the 2B-03B well in Beechey Point
County, AK. The 2B-03B was a 1 stage Vertical Plug and Perf Design. The proposed treatment consisted of:
The actual treatment fully completed 1 of 1 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:
A MiniFrac was pumped before the main treatment but closure was not found after monitoring pressure for 1hr and 10 minutes.
The main job was pumped as per design. In the later sand stages, XL became weaker and Lip time surpassed 3 min however no
associated pressure response was observed.
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.
MO was pumped in raw form at a setpoint of 0.48 gal/Mgal to obtain a pH in the target range of 9.1-9.3. XL samples were
brought regularly to the TCC, towards the tail end of the job, lip time increased to 3+ minutes. Each tank was XL'ed with location
chemicals before the stage and water analysis was performed for each tank with nothing abnormal being found.
William Martin
Senior Technical Professional
Conoco Phillips - 2B-03B Executive Summary 3
Interval 1A-Sand@ 8069 - 8136 ft 160.4 °F
6/21/24 15:01
6/21/24 15:59
58 min
2.2 bpm
3,227 psi
NA psi
-bbl
25.2 bpm
4,543 psi
NA psi
22.2 bpm
3,774 psi
3,782 psi
NA psi
2,057 hhp
1541 psi
290 psi
352 psi
7.35 ppg
5
5
41 %
37 %
28 cP
114.4 F
9.3
MiniFrac
23.250 bpm
4255 psi
NA psi
24.82 bpm
4487 psi
NA psi
2170 psi
0.780 psi/ft
1959 psi
1912 psi
1873 psi
104,606 lbs
3,133 lbs
95,601 lbs
95,601 lbs
61,136 gal 1,456 bbls
6,199 gal 148 bbls
252 gal 6 bbls
0 gal 0 bbls
12,232 gal 291 bbls
4,803 gal 114 bbls
24,465 gal 583 bbls
3,102 gal 74 bbls
5,280 gal 126 bbls
5,916 gal 141 bbls
8,440 gal 201 bbls
3,097 gal 74 bbls
Completed
Comments:
Engineer:
Treater:
Supervisor:
Customer Engineer:
Customer Rep:
Pad Volume:
Minifrac Max Surface Pressure:
100M Pumped IFS:
Final 15 min:
Proppant in Formation:
35# Hybor G Volume:
35# Linear Volume:
Seawater Volume:
Minifrac Max DH Pressure:
Final 5 min:
Dart/Ball Early :
Average pH:
Minifrac Average Rate:
Pump Time:
Pad Percentage Actual
Wanli 16/20 Ceramic IFS:
Diagnostic method
Average Visc:
Average Temp:
Initial Rate (Breakdown):
Initial Surface Pressure (Breakdown):
Max Rate:
Max Surface Pressure:
Max BH Pressure:
Interval Summary
2B-03B - Kuparuk - Interval 1
Interval Summary
Start Date/Time:
End Date/Time:
Average Missile Pressure:
Open Well Pressure:
Initial OA Pressure:
Average Surface Pressure:
Average Rate:
Max OA Pressure:
Pumps Starting Stage:
Pad Percentage Design
Average Missile HHP:
Initial BH Pressure (Breakdown):
Average BH Pressure:
Pumps Ending Stage:
Max Proppant Concentration:
Minifrac - Establish Fluid Volume:
Minifrac Max Rate:
Conditioning Pad Volume:
Proppant Laden Fluid Volume:
ISDP:
Final Fracture Gradient:
Final 10 min:
A MiniFrac was pumped before the main treatment but closure was not found after monitoring
pressure for 1hr and 10 minutes. The main job was pumped as per design. In the later sand
stages, XL became weaker and Lip time surpassed 3 min however no associated pressure
response was observed.
Minifrac - Flush Volume:
Proppant Summary
Minifrac Average Pressure:
Minifrac Average DH Pressure:
Freeze Protect Volume:
Chad Burkett
William Martin
Total Proppant Pumped* :
Minifrac - Treatment Volume:
Fluid Summary (by fluid description)
Fluid Summary (by stage description)
Flush Volume:
Establish Stable Fluid Volume:
*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.
Interval Status:
Nathan Brzezinski
Dan Faur
Conoco Phillips - 2B-03B Interval Summary 6
Hydraulic Fracturing Fluid Product Component Information Disclosure
6/21/2024
Alaska
BEECHEY POINT
50-029-21151-00-00
CONOCOPHILLIPS
2B 03B
-149.93820000
70.28720000
NAD83
none
Oil
6254
69052
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) Operator Base Fluid Density = 8.52
BE-6(TM)
Bactericide Halliburton Microbiocide
CL-28M
CROSSLINKER Halliburton Crosslinker
LoSurf-300D Halliburton Non-ionic Surfactant
MO-67 Halliburton pH Control
OPTIFLO-II
DELAYED
RELEASE
BREAKER Halliburton Breaker
OPTIFLO-III
DELAYED
RELEASE
BREAKER Halliburton Breaker
WG-36 GELLING
AGENT Halliburton Gelling Agent
Ceramic
Proppant - Wanli Wanli Proppant
SAND, COMMON
BROWN 100
MESH Halliburton Proppant
Ingredients Water 7732-18-5 100.00%85.45326%588324
Corundum 1302-74-5 65.00%8.74262%60191
Mullite 1302-93-8 45.00%6.05259%41671
Sodium chloride 7647-14-5 5.00%4.27266%29417
Crystalline silica, quartz 14808-60-7 100.00%0.44349%3054
Guar gum 9000-30-0 100.00%0.31519%2170
Water 7732-18-5 100.00%0.16151%1112
Borate salts Proprietary 60.00%0.11536%795
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
Ethanol 64-17-5 60.00%0.04305%297
Ammonium persulfate 7727-54-0 100.00%0.03195%220
Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.02153%149 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Heavy aromatic petroleum
naphtha 64742-94-5 30.00%0.02153%149
Sodium hydroxide 1310-73-2 30.00%0.01384%96
Inorganic mineral 1317-65-3 5.00%0.00961%67
Potassium chloride 7447-40-7 5.00%0.00961%67
Oxylated phenolic resin Proprietary 30.00%0.00959%66 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Oxyalkylated phenolic resin Proprietary 10.00%0.00718%50 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Naphthalene 91-20-3 5.00%0.00359%25
Poly(oxy-1,2-ethanediyl), alpha-(4-
nonylphenyl)-omega-hydroxy-,
branched 127087-87-0 5.00%0.00359%25
2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00349%24
Gluteraldehyde 111-30-8 1.00%0.00192%14
Calcium magnesium carbonate 16389-88-1 1.00%0.00192%14
Polymer Proprietary 1.00%0.00192%14 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Inorganic mineral Proprietary 1.00%0.00192%14 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
1,2,4 Trimethylbenzene 95-63-6 1.00%0.00072%5
Sodium chloride 7647-14-5 1.00%0.00046%4
Sodium bisulfate 7681-38-1 0.10%0.00019%2
Methanesulfonic acid, 1-hydroxy-,
sodium salt 870-72-4 0.10%0.00019%2
C.I. pigment Orange 5 3468-63-1 1.00%0.00010%1
Magensium chloride 7786-30-3 0.01%0.00002%1
Magnesium nitrate 10377-60-3 0.01%0.00002%1
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
0.00%0.00000%0
* 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 1.4
All component information listed was obtained from the suppliers Material Safety Data Sheets (MSDS). As such, the Operator isnot 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 Administrations (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 issubject 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:
Page 1/1
2B-03
Report Printed: 7/17/2024
Daily Operations Summary
Job: INITIAL COMPLETION
Daily Operations
Start Date Last 24hr Sum
6/20/2024 STABBED STINGER ISOLATION TOOL.
6/21/2024 COMPLETED RIG IN, PUMPED STAGE AS DESIGNED
PUMP TIME 58 MINUTES, BREAK DOWN @ 2.2BPM @ 3227 PSI, TOTAL CLEAN VOLUME 1604 BBL, TOTAL PROPPANT PLACED 107,739
LBS AVG SURFACE PSI 3782, AVG RATE, 22.2, ISIP 2170
6/22/2024 RIG DOWN PUMPS, WET SIDE AND IRON, MOBILIZE TO STAGING PAD, VAC TANK BOTTOMS PREP TANKS FOR MOBILIZATION.
7/1/2024 MOBILIZE FROM 2G PAD TO 2B-03. SPOT UP RIG UP CTU #11. RIH AND TAG FILL @8,079' CTMD. FCO WITH DIESEL AND GEL SWEEPS
TO HARD TAG @ 8,230' CTMD. CHASE FILL OUT OF HOLE WITH CLEAN DIESEL TO SURFACE. RDMO - JOB COMPLETE.
7/3/2024 REPLACE DV @ 6515' RKB W/ 1/4" OV. REPLACE DV @ 3195' RKB W/ GLV. CONFIRM NEW GLD W/ 1000 PSI IA DDT. JOB COMPLETE
Rig: HES 760
FALSE 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: 87.89'
Total Depth:1135' FSL, 833' FEL, Sec 30, T11N, R9E, UM 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27):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:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16"H-40 110'
9-5/8"J-55 2748'
7"J-55
3-1/2"L-80 6255'
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
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
ConocoPhillips Alaska, Inc.
WAG
Gas
2/10/2024 223-080
50-029-21151-02-00
KRU 2B-03B
ADL 0025656, ADL0025655
81-172
2/5/2024
115.89'
P.O. Box 100360 Anchorage, AK 99510-0360
508396 5954836
1298' FSL, 931' FEL, Sec. 30, T11N, R9E, UM
2/6/2024670' FSL, 248' FEL, Sec 19, T11N, R9E, UM
5950164
3161'MD/2751'TVD
SETTING DEPTH TVD
5950001
TOP HOLE SIZE AMOUNT
PULLED
507735
507834
TOP
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 River Oil Pool
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
32'
9.2
35'
7141'
3161'
6-1/8"37bbls if 15.3ppg Class G
55
36
110'
32 8395'
SIZE
24"
DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size
and Number; Date perf'd or liner run):
TUBING RECORD
7197'3.5"
5475'
12-1/4"34'
8-1/2"
34'
35'
26
8350'
Gas-Oil Ratio:Choke Size:
Per 20 AAC 25.283 (i)(2) attach electronic information
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Flow Tubing
Sr Res EngSr Pet GeoSr Pet Eng
None
Oil-Bbl:Water-Bbl:
Directional Survey
Water-Bbl:
PRODUCTION TEST
N/A
Date of Test:Oil-Bbl:
PACKER SET (MD/TVD)
J G
s d 1b
10 D
A
2 p
and Bot ;Perfor
L
s
(atta
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
11. Total Depth MD/TVD:
8350' MD/6255'TVD
Liner ran on: 2/6/2024 7141'MD/5475'TVD to 8350'MD/6255'TVD
6101'
21. Re-drill/Lateral Top Window MD/TVD:
7250'MD/5545'TVD
7141'MD/5475'TVD
Received 6/10/2024
Completed
2/10/2024
JSB
RBDMS JSB 030724
GDSR-6/12/24
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Surface Surface
Base of Permafrost 3161 2751
8069 6062
8088 6075
8350 6254
(Miluveach)
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Dusty Ward
Digital Signature with Date:Contact Email:dusty.ward@cop.com
Contact Phone:907-265-6531
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:
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
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Top of Permafrost
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
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
Top of Productive Interval
(Kuparuk A5)
Top of Productive Interval
(Kuparuk A4)
Authorized Title: Wells Engineer
Operations Summary, Cementing Summary, Well Schematic, Directional Survey
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.
N
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB 7,705.0 2B-03B 2/19/2024 rogerba
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Added perforations 2B-03B 4/11/2024 jconne
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 35.0 110.0 110.0 55.00 H-90 WELDED
SURFACE 9 5/8 8.92 34.1 3,161.3 2,748.1 36.00 J-55 BUTT
PRODUCTION 7 6.28 32.0 8,395.2 26.00 J-55 BTC
Liner - Lower
completion work over
2024
3 1/2 2.99 7,141.0 8,350.0 6,254.6 9.20 L-80 Hyd 563
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
32.0
Set Depth …
7,196.7
String Max No…
3 1/2
Set Depth …
5,510.5
Tubing Description
Tubing – Completion Upper
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE 8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
32.0 32.0 0.01 Hanger 6.997 3.5" tubing hanger w/pup Camero
n/Vault
S-218 6"
x 3-1/2"
EUE
8RD
4.500
3,195.3 2,771.7 46.25 Mandrel – GAS
LIFT
4.757 3.5" x 1.5" MMG DV (Target 3168') MMG
DV
SLB 2.818
6,515.2 5,067.4 48.31 Mandrel – GAS
LIFT
4.757 3.5" x 1.5" MMG 110SKI HYD 563
(Target 6500')
MMG
SOV
SLB 2.818
7,153.8 5,482.9 49.89 Seal Assembly 3.500 3.5" 80-40 Seal Assembly (space
out 2')
HES HES 2.984
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
3,195.3 2,771.7 46.25 1 GAS LIFT GLV RK 1 1/2 1,260.0 2/19/2024 SLB MMG 0.188
6,515.2 5,067.4 48.31 2 GAS LIFT OV RK 1 1/2 2/19/2024 SLB MMG 0.250
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
7,141.0 5,474.7 49.83 Packer 5.980 4.15 4.170
7,208.2 5,517.9 50.09 Nipple - X 4.300 2.80 2.813
8,250.6 6,185.2 46.19 Collar - Landing 4.290 2.86 2.860
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,069.0 8,079.0 6,061.7 6,068.4 4/11/2024 6.0 APERF 2.5" MILLENIUM II GUNS, 6
SPF, 60° PHASE
8,095.0 8,115.0 6,079.2 6,092.7 4/11/2024 6.0 APERF 2.5" MILLENIUM II GUNS, 6
SPF, 60° PHASE
8,116.0 8,136.0 6,093.3 6,106.9 4/11/2024 6.0 APERF 2.5" MILLENIUM II GUNS, 6
SPF, 60° PHASE
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
7,141.0 8,350.0 5,474.6 6,254.6 Production
String 1
Cement
37 bbls of 15.3# cement 2/8/2024
2B-03B, 6/10/2024 9:42:04 AM
Vertical schematic (actual)
X O
PRODUCTION; 32.0-8,395.2
Liner - Lower completion work
over 2024; 7,141.0-8,350.0
APERF; 8,116.0-8,136.0
APERF; 8,095.0-8,115.0
APERF; 8,069.0-8,079.0
Production String 1 Cement;
7,141.0 ftKB
Seal Assembly; 7,153.8
Mandrel – GAS LIFT; 6,515.2
Mandrel – GAS LIFT; 3,195.3
SURFACE; 34.1-3,161.3
CONDUCTOR; 35.0-110.0
Hanger; 32.0
KUP PROD
KB-Grd (ft)
28.00
RR Date
8/15/1984
Other Elev…
2B-03B
...
TD
Act Btm (ftKB)
8,350.0
Well Attributes
Field Name
KUPARUK RIVER UNIT
Wellbore API/UWI
500292115102
Wellbore Status
PROD
Max Angle & MD
Incl (°)
96.12
MD (ftKB)
8,299.11
WELLNAME WELLBORE2B-03B
Annotation
Last Workover:
End Date
2/10/2024
H2S (ppm)
90
Date
12/3/2016
Comment
Page 1/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
1/28/2024
00:00
1/28/2024
06:00
6.00 RURD P Perform rig down checklists, prep
location for move, prep loads for
transport to 2B pad, Cold weather
prevent some work being down outside
by crews
0.0 0.0
1/28/2024
06:00
1/29/2024
00:00
18.00 WAIT T Waiting on ambient temperature to
increase to start rig move.
0.0 0.0
1/29/2024
00:00
1/29/2024
06:00
6.00 MIRU, MOVE WAIT T Waiting on ambient temperature to
increase to start rig move.
0.0 0.0
1/29/2024
06:00
1/29/2024
15:00
9.00 MIRU, MOVE MOB P Prep and move camp, shop and
supporting buildings
0.0 0.0
1/29/2024
15:00
1/29/2024
18:00
3.00 MIRU, MOVE MOB P Mob rig from 2M pad to 4 corners 0.0 0.0
1/29/2024
18:00
1/30/2024
00:00
6.00 MIRU, MOVE RGRP T Drive motor on moving system fail //
Perform repairs in road
0.0 0.0
1/30/2024
00:00
1/30/2024
02:00
2.00 MIRU, MOVE MOB P Repairs complete mob rig to 4 corners,
allow traffic by, continue to move to 2B
0.0 0.0
1/30/2024
02:00
1/30/2024
12:00
10.00 MIRU, MOVE RURD P Rig on pad. prep for backing over 2B-
03. Spot over well back in pits raise
derrick continue working pre acceptance
checklist. spot in kill tanks and cutting
tanks.
0.0 0.0
1/30/2024
12:00
1/30/2024
15:00
3.00 MIRU, WELCTL RURD P Pre acceptance checklist completed.
Tool house still RU kill tanks and
hardline to rig. Mix 30 BBL deep clean
pill.
0.0 0.0
1/30/2024
15:00
1/30/2024
17:30
2.50 MIRU, WELCTL CIRC P Reverse circulate well out to 8.5#
seawater. 3BPM 750PSI
0.0 0.0
1/30/2024
17:30
1/30/2024
18:00
0.50 MIRU, WELCTL OWFF P Observe well for flow 0.0 0.0
1/30/2024
18:00
1/30/2024
20:30
2.50 MIRU, WELCTL SLKL P R/U Slickline 0.0 0.0
1/30/2024
20:30
1/30/2024
20:45
0.25 MIRU, WELCTL SLKL P P/T Lubricator 1,500 psi 0.0 0.0
1/30/2024
20:45
1/30/2024
21:00
0.25 MIRU, WELCTL MPSP P M/U IBP 0.0 0.0
1/30/2024
21:00
1/30/2024
21:15
0.25 MIRU, WELCTL MPSP P P/T connection
Sim-ops start loading DrillPipe
0.0 0.0
1/30/2024
21:15
1/30/2024
21:45
0.50 MIRU, WELCTL MPSP P Set IBP COE @ 51' from Rig Floor
Test/Chart 1,000 psi from below 10 min
0.0 0.0
1/30/2024
21:45
1/30/2024
22:30
0.75 MIRU, WELCTL SLKL P R/D Slickline 0.0 0.0
1/30/2024
22:30
1/31/2024
00:00
1.50 MIRU, WELCTL NUND P Check SSSV void, bleed crude/gas to
bucket, Nipple down tree/adaptor
0.0 0.0
1/31/2024
00:00
1/31/2024
00:45
0.75 MIRU, WELCTL NUND P Secure tree in corner of cellar, N/U
BOPE
Inspect tubing hanger threads, function
3-1/2" EUE 8rd XO, 11 turns
Function LDS in 2-5/16", out 2-15/16"
0.0 0.0
1/31/2024
00:45
1/31/2024
03:30
2.75 MIRU, WELCTL NUND P Install 7"x13-5/8" DSA, N/U 13-5/8"
BOPE
Continue sim-ops processing/loading
DP
0.0 0.0
1/31/2024
03:30
1/31/2024
18:00
14.50 MIRU, WHDBOP SVRG P Perform between well maintenance,
brake all door bolts, UPR, blinds, LPR,
clean and inspect, take photos, brake
top flange bolts, swap out 13-5/8"
annular element, (preventative maint.)
Continue to process DP
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Page 2/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
1/31/2024
18:00
1/31/2024
20:00
2.00 MIRU, WHDBOP OTHR P RU to test BOP's MU XO's to test joints.
flood stack with fresh water perform
shell test. Load pipe shed W/264 joints
of XT-39
0.0 0.0
1/31/2024
20:00
2/1/2024
00:00
4.00 MIRU, WHDBOP BOPE P Initial BOPE test, Tested BOPE at
250/3,500 PSI for 5 Min each, test #1
Blind Rams, CMV 1,2,3, & 16, 2" Rig
Floor Kill, IBOP, Outer Test SPool Valve.
Test #2 Blind Rams, CMV, 4,5,& 6, HCR
Kill, Inner Test Spool Valve, Manual
IBOP, Test #3 Blind Rams, CMV, 7,8, &
9, Manual Kill, and XT-39 Dart Valve,
Test #4 Super and Manual Bean Choke
(1,500 psi), Test #5 Lower Pipe Rams,
XT-39 TIW, Test #6, Upper Pipe Rams,
CMV 10 & 11, Test #7 Upper Pipe
Rams, 12, 13, & 15, 3.5" FOSV, Test #8
CMV 14, Test #9 HCR Choke, Test #10
Manual Choke, Test #11, Lower Pipe
Rams, Test #12 Annular, Perform
accumulator test. Initial pressure=2950
PSI, after closure=1550 PSI, 200 PSI
attained =20 sec, full recovery attained
= 108 sec. UVBR's= 5 sec, Annular= 30
sec. Simulated blinds= 5 sec. LVBR’s=6
sec. HCR choke & kill= 1 sec each. 5
back up nitrogen bottles average = 2100
PSI. Test gas detectors, PVT and flow
show. Test Witness Waived by AOGCC
rep Sullivan, Sean T.
0.0 0.0
2/1/2024
00:00
2/1/2024
03:00
3.00 MIRU, WHDBOP BOPE P Continue testing BOPE, Test #7 Upper
Pipe Rams, 12, 13, & 15, 3.5" FOSV,
Test #8 CMV 14, Test #9 HCR Choke,
Test #10 Manual Choke, Test #11,
Lower Pipe Rams, Test #12 Annular,
Perform accumulator test. Initial
pressure=2900 PSI, after closure=1575
PSI, 200 PSI attained =11 sec, full
recovery attained = 121 sec. UVBR's=
5 sec, Annular= 22 sec. Simulated
blinds= 5 sec. LVBR’s=6 sec. HCR
choke & kill= 1 sec each. 5 back up
nitrogen bottles average = 2045 PSI.
Test gas detectors, PVT and flow show.
Test Witness Waived by AOGCC rep
Sullivan, Sean T. (( Total Test time 7.5
hrs ))
0.0 0.0
2/1/2024
03:00
2/1/2024
03:30
0.50 SLOT, RPCOMP OTHR P R/D Testing equipment, clean up RF. 0.0 0.0
2/1/2024
03:30
2/1/2024
04:00
0.50 SLOT, RPCOMP SVRG P Service Rig Top drive 0.0 0.0
2/1/2024
04:00
2/1/2024
07:00
3.00 SLOT, RPCOMP SLKL P Start RU Dutch riser. Tool siezed at
LDS unable to function L/D Dutch riser
(Dutch Riser not required for
operations./ DDT on Cement plug
passed 30 minute no flow W/8.5
seawtaer in well and BOP's tested to
3500 PSI.) R/U HES Slickline Equalized
RBP and pulled plug RD HES Slick-
line .
0.0 0.0
2/1/2024
07:00
2/1/2024
08:00
1.00 SLOT, RPCOMP RURD P RU floor to pull completion. 0.0 0.0
2/1/2024
08:00
2/1/2024
08:30
0.50 SLOT, RPCOMP PULL P MU landing joint to hanger MU X-O's to
lading joint BOLDS.
0.0 0.0
2/1/2024
08:30
2/1/2024
09:30
1.00 SLOT, RPCOMP PULL P Pull hanger and pup joints to floor.
PUW=102K weight broke back to 85K.
7,259.0 7,229.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Page 3/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/1/2024
09:30
2/1/2024
10:30
1.00 SLOT, RPCOMP CIRC P Circulate and condition well 8.5#
seawater SxS at 100 SPM 660 PSI.
7,229.0 7,229.0
2/1/2024
10:30
2/1/2024
10:45
0.25 SLOT, RPCOMP OWFF P OWFF for 15 minutes no flow.
RD circulating eq. blow down top drive.
7,229.0 7,229.0
2/1/2024
10:45
2/1/2024
18:00
7.25 SLOT, RPCOMP PULL P Pull 3.5# EUE 8rd tubing PUW=86K
F/7229' T/Surface
*** Note: 3-1/2" EUE Cut joint 19.92'
7,229.0 0.0
2/1/2024
18:00
2/1/2024
20:00
2.00 SLOT, WHPST OTHR P Load out remaining pulled tubing out of
pipe shed, inspect cut joint, clean rig
floor, load milling assembly components
into shed, get measurments. Rig up RF
for milling operations.
0.0 0.0
2/1/2024
20:00
2/1/2024
20:30
0.50 SLOT, WHPST SFTY P Pre-spud/PJSM with crews. 0.0 0.0
2/1/2024
20:30
2/1/2024
23:00
2.50 SLOT, WHPST BHAH P M/U Milling BHA - 5-3/4" Cut Lip Shoe,
3.1/2" inner dress off mill, Wash Pipe
Extension, Wash Over Boot Basket, 3-
1/2" Flex Joint, Upper String Mill, XO (3-
1/2" IF x XT39) HWDP x 1, Oil Jars,
String Magnets x 2, and XT39 Pup Joint.
*** Note: Swallow 5.28", Mill 4.37" Shear
pins 1.1"
*** Note: Install Wear Ring
0.0 108.8
2/1/2024
23:00
2/2/2024
00:00
1.00 SLOT, WHPST TRIP P TIH with Milling/Drift BHA #1 108.8 587.0
2/2/2024
00:00
2/2/2024
00:30
0.50 SLOT, WHPST SVRG P Rig Service - Top Drive and Iron
Roughnecks
587.0 587.0
2/2/2024
00:30
2/2/2024
08:00
7.50 SLOT, WHPST TRIP P Continue RIH on singles from pipe shed
with drift/milling BHA #2, drifting DP on v
-door
Swap out dies on hand slips
RIH F/587' T/7281' PUW=140K
SOW=97K
587.0 7,241.0
2/2/2024
08:00
2/2/2024
12:00
4.00 SLOT, WHPST MILL P Establish Milling parameters
Rot=30 RPM Tq=6000 PR=3BPM Rot
Wt=115K
Tag top of tubing stump at 7259' ORKB
7253' 7ES RKB.
Mill F7259' T/7268.2' ORKB (F/7253'
T/7262.2' 7ES RKB)
7,241.0 7,259.0
2/2/2024
12:00
2/2/2024
13:00
1.00 SLOT, WHPST CIRC P Circulate high vis 25 BBL sweep 3.5
BPM.
Sweep at bit
Increase rate to 5 BPM sweeep the hole
clean.
Circulate the sweep out of the well.
7,259.0 7,259.0
2/2/2024
13:00
2/2/2024
13:15
0.25 SLOT, WHPST OWFF P OWFF for 15 minutes 0 flow 7,259.0 7,259.0
2/2/2024
13:15
2/2/2024
16:00
2.75 SLOT, WHPST TRIP P TOOH with milling BHA #1 F/7268.2'
ORKB (7262.2' 7ES RKB) T/7150'
polish casing from 7150 to 7050'.
Continue TOOH F/7050' T/587
7,259.0 587.0
2/2/2024
16:00
2/2/2024
16:30
0.50 SLOT, WHPST BHAH P Rack BHA and inspect mill. Empty boot
basket.
587.0 0.0
2/2/2024
16:30
2/2/2024
17:00
0.50 SLOT, WHPST BHAH P MU BHA 0.0 587.0
2/2/2024
17:00
2/2/2024
19:45
2.75 SLOT, WHPST TRIP P TIH F/587' T/7,267'
PUW=140k, SOW=95k
587.0 7,267.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Page 4/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/2/2024
19:45
2/3/2024
00:00
4.25 SLOT, WHPST MILL P Establish Milling parameters
Pump rate 68 spm/4 bpm/575 psi
Rot=60 RPM Tq=6500 PR=4BPM Rot
Wt=111K
ROP slowed down, assuming on collar.
Lower pump rate 50 spm/3 bpm/305 psi
Tag top of tubing stump at 7,262' ORKB
7272' 7ES RKB.
Mill F7267' T/7277' 7ES RKB
7,267.0 7,277.0
2/3/2024
00:00
2/3/2024
01:00
1.00 SLOT, WHPST CIRC P Pump 20 bbl high vis sweep @ 3 bpm,
circulate around the corner, followed by
10 bbl spacer, PUH 6', launch final 20
bbl high vis sweep, increase pump rate
to 6 bpm
7,277.0 7,270.0
2/3/2024
01:00
2/3/2024
01:30
0.50 SLOT, WHPST SVRG P TOOH F/7,270' T/7,249', Rig Service -
Top Drive
7,270.0 7,249.0
2/3/2024
01:30
2/3/2024
04:15
2.75 SLOT, WHPST TRIP P TOOH F/7,249' T/Surface 7,249.0 112.0
2/3/2024
04:15
2/3/2024
05:00
0.75 SLOT, WHPST BHAH P L/D Milling BHA #3, inspect, gauge mills 112.0 0.0
2/3/2024
05:00
2/3/2024
07:45
2.75 SLOT, WHPST BHAH P Organize and verify WS BHA in pipe
shed.
PJSM for PU BHA.
Pulling up to attach the WS wear rig
pulled out of wellhead.
0.0 0.0
2/3/2024
07:45
2/3/2024
11:45
4.00 SLOT, WHPST RURD T Attempted to reset wear ring. unable to
engage wear ring with LDS. Called Vault
rep to address issue. removed seal from
test plug to verify test plug wasn't
preventing wear ring from making full
engagement in tubing head. 5' to
wellhead. Correct measurement from
floor to ULDS was verified attempted to
reset the wear ring. unable to engage
ULDS in wear ring. wait on well head
rep to deliver alternate wear ring.
Well head rep brought new wear ring
and no running tool. returned to wear
house for running tool.
0.0 0.0
2/3/2024
11:45
2/3/2024
14:15
2.50 SLOT, WHPST BHAH P MU BHA and whipstock 0.0 569.6
2/3/2024
14:15
2/3/2024
15:15
1.00 SLOT, WHPST TRIP P TIH F/569.6 T/1228' 569.6 1,228.0
2/3/2024
15:15
2/3/2024
16:45
1.50 SLOT, WHPST CIRC P Attempt a shallow function test.
pressuring up to 2100 PSI unable to
circulate apparent blockage in BHA
pressure falling off slowly continue to
work pressure up to 2200 PSI and allow
to drop off. Blow down top drive.
1,228.0 1,228.0
2/3/2024
16:45
2/3/2024
18:00
1.25 SLOT, WHPST TRIP T Blockage in the BHA unable to establish
shallow test on treletrack. TOOH F/1228
T/569
1,228.0 569.0
2/3/2024
18:00
2/3/2024
19:30
1.50 SLOT, WHPST BHAH T Brake down BHA until we could find
blockage. Screen Sub seems to be fully
open. brake out screen sub for
inspection. brake floats out, found metal
pieces on top of floats, Seems MWD is
plugged off.
569.0 72.8
2/3/2024
19:30
2/3/2024
21:00
1.50 SLOT, WHPST BHAH T Load backup MWD tool into pipeshed,
start warming it up, sim-ops pull
remaining BHA from hole 72,84' and
inspect mill.
72.8 0.0
2/3/2024
21:00
2/3/2024
22:45
1.75 SLOT, WHPST BHAH T M/U Gen II WS setting/Milling BHA w/4
new pins and 37k Shear screw (Batch
#103687763)
0.0 570.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Page 5/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/3/2024
22:45
2/4/2024
00:00
1.25 SLOT, WHPST TRIP T Shallow hole test of Teletrac tools @
652'/80 gpm
570.0 652.0
2/4/2024
00:00
2/4/2024
01:00
1.00 SLOT, WHPST DHEQ P 652', continue testing tools,150 gpm/3.6
bpm
200 gpm/4.75 bpm
652.0 652.0
2/4/2024
01:00
2/4/2024
05:30
4.50 SLOT, WHPST TRIP P Continue TIH on stands at reduced
speed 45 fpm TIH F/652' T/72
PUW=135K SOW=105K
652.0 7,245.0
2/4/2024
05:30
2/4/2024
07:00
1.50 SLOT, WHPST WPST P Orient WS to 315.25* set WS at 7275
ORKB (7269' 7ES)
7,245.0 7,269.0
2/4/2024
07:00
2/4/2024
09:00
2.00 SLOT, WHPST CIRC P Circulate the well over to 11.6# WBM 47
vis 9.4 BPM at 2500PSI. Condition well.
transfer 11.6# WBM to all pits.
7,269.0 7,269.0
2/4/2024
09:00
2/4/2024
09:30
0.50 SLOT, WHPST RURD P Blow down top drive and circulating
lines.
7,269.0 7,269.0
2/4/2024
09:30
2/4/2024
11:30
2.00 SLOT, WHPST SLPC P Slip and cut drilling line 7,269.0 7,269.0
2/4/2024
11:30
2/4/2024
12:00
0.50 SLOT, WHPST SFTY P Hold pre-spud safety meeting 7,269.0 7,269.0
2/4/2024
12:00
2/4/2024
22:00
10.00 SLOT, WHPST MILL P Reestablish milling parameters
PUW=135K SOW=105K
Roll pumps 4 BPM 800 PSI Rot=70
RPM TQ=4900 Rot wt=110 PUW 120K
80 RPM=5300 Ft LBS
90 RPM=5500 Ft Lbs
Tag at 7249.7' Start milling at 75 RPM 5-
7K Tq.
WOB 3-5K
Mill through casing T/7311' ORKB
7305' (7ES RKB)
7,269.0 7,305.0
2/4/2024
22:00
2/4/2024
22:45
0.75 SLOT, WHPST REAM P Ream casing exit pumping 5 bpm/200
spm/1,231 psi, Recep through casing
exit x 2, cease rotating, lower pump
rate 1/4 bpm/17 spm/390 psi, drift
casing exit (clean).
7,305.0 7,305.0
2/4/2024
22:45
2/5/2024
00:00
1.25 SLOT, WHPST DISP P Displace well to new 11.6 ppg drilling
fluid
7,305.0 7,305.0
2/5/2024
00:00
2/5/2024
00:15
0.25 SLOT, WHPST DISP P Continue displacing well with new 11.6
ppg drilling fluid
7,305.0 7,230.0
2/5/2024
00:15
2/5/2024
00:45
0.50 SLOT, WHPST OWFF P Shut down pump observe well for flow 7,230.0 7,230.0
2/5/2024
00:45
2/5/2024
01:15
0.50 SLOT, WHPST CIRC P Line up and pump dry job, 13.6 ppg 15
bbl. Monitor well for flow
7,230.0 7,230.0
2/5/2024
01:15
2/5/2024
04:30
3.25 SLOT, WHPST TRIP P TOOH F/7230' PUW=135K T/551'
PUW=45K
7,230.0 551.0
2/5/2024
04:30
2/5/2024
07:00
2.50 SLOT, WHPST BHAH P LD BHA. #3 Window mill BHA F/551' To
surface
551.0 0.0
2/5/2024
07:00
2/5/2024
07:30
0.50 PROD1, DRILL SVRG P Service top drive. 0.0 0.0
2/5/2024
07:30
2/5/2024
09:30
2.00 PROD1, DRILL BHAH P MU drilling BHA F/0 T/337' Verify tool
face
0.0 337.0
2/5/2024
09:30
2/5/2024
10:00
0.50 PROD1, DRILL TRIP P TIH F/337' T/1150' Perform shallow
surface test on MWD
337.0 1,150.0
2/5/2024
10:00
2/5/2024
11:00
1.00 PROD1, DRILL CIRC P Condition well w/11.6# Circ at 2 BPM at
650PSI
1,150.0 1,150.0
2/5/2024
11:00
2/5/2024
15:00
4.00 PROD1, DRILL TRIP P Continue TIH F/1150' T/4000' condition
well. Continue to TIH 7243' Orient TF
Establish Pump rates and ECD's
250 GPM= 1234 PSI in DP
ECD=13.0
1,150.0 7,243.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Page 6/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/5/2024
15:00
2/6/2024
00:00
9.00 PROD1, DRILL DDRL P Slide F/7,303' T/7,355'
Increase PR to 300 GPM
ECD=13.2PPG
Drill F/7355' 40 RPM 6K Tq. 300 GPM
T/7,564'
7,243.0 7,564.0
2/6/2024
00:00
2/6/2024
01:00
1.00 PROD1, DRILL DDRL P Driling Ahead, PR to 300 GPM
ECD=13.3PPG
Drill F/7,564' RPM 6K Tq. 300 GPM
T/7,612'
*** Note: Average ROP 84 fph
7,564.0 7,612.0
2/6/2024
01:00
2/6/2024
02:30
1.50 PROD1, DRILL DDRL P 7,612' , Pump #1 shut down, increase
pump #2 to rate 256 gpm/1,944 psi
RBIH, Drill ahead 7,612'
PUW=125 k, SOW=93 k
*** Note: Average ROP 77 fph
7,612.0 7,660.0
2/6/2024
02:30
2/6/2024
06:00
3.50 PROD1, DRILL DDRL P Slide F/7,660' T/7,674', P/U stand,
Pump 250 gpm/6 bpm/2,053 psi,
Rotate F/7,674' T/7,759' Rot=50,
TQ=6,100k
7,660.0 7,759.0
2/6/2024
06:00
2/6/2024
12:00
6.00 PROD1, DRILL DDRL P Continue rotating F/7,759'' T/8,042',
pump 272 gpm/6.5 bpm/2,677 psi,
Rot=50 rpm, TQ=7,400 k
7,759.0 8,042.0
2/6/2024
12:00
2/6/2024
18:00
6.00 PROD1, DRILL DDRL P Continue rotating F/8,042'' T/8350',
pump 281 gpm/6.7 bpm/2,441 psi,
Rot=60 rpm, TQ=7,200 k PUW=135 k
pumps on, pumps off 150 k, SOW= 97 k
Average ROP=113 fph
8,042.0 8,350.0
2/6/2024
18:00
2/6/2024
19:00
1.00 COMPZN, CASING CIRC P Circ 20 bbl Hi Vis sweep, chase with 2x
BUS, total pumped 455 bbls, 6 bpm at
2200 psi, reciprocate 20 RPM, TQ 5.8K,
118 PUW, 108K SOW
8,350.0 8,350.0
2/6/2024
19:00
2/6/2024
19:30
0.50 COMPZN, CASING OWFF P Flow check well-slight flow that is
slowing down.
8,350.0 8,350.0
2/6/2024
19:30
2/6/2024
22:30
3.00 COMPZN, CASING TRIP P Trip out of the hole, 140K UWT,
Swabbing, Pump out at 125 gpm, 1000
psi, tight spot at 7945' rotate through at
20 rpm, pulled tight again at 7910'. UWT
155K, attempt to run back in hole and
will not go down, No returns, rotate 30
rpm, work stuck pipe and increase pump
rate to 6 BPM at 2300 psi. Got pipe to
move and returns slowly came back.
8,350.0 7,943.0
2/6/2024
22:30
2/7/2024
00:00
1.50 COMPZN, CASING WASH P Wash down from 7943' to 8228', 3 BPM
at 1000 psi, Wash and ream down from
8228 to 8323'.
7,943.0 8,323.0
2/7/2024
00:00
2/7/2024
02:00
2.00 COMPZN, CASING TRIP P Wash down from 7943' to 8228', 3 BPM
at 1000 psi, Wash and ream down from
8228 to 8323'.
8,323.0 8,350.0
2/7/2024
02:00
2/7/2024
03:00
1.00 COMPZN, CASING TRIP P TOOH F/8,350' T/7,808', work through,
continue TOOH F/7,808' T/7,230'
8,350.0 7,246.0
2/7/2024
03:00
2/7/2024
07:00
4.00 COMPZN, CASING CIRC P Above Window, circulate sweep around 7,246.0 7,246.0
2/7/2024
07:00
2/7/2024
11:00
4.00 COMPZN, CASING TRIP P TOOH F/7,246' T/338' 7,246.0 338.0
2/7/2024
11:00
2/7/2024
14:30
3.50 COMPZN, CASING BHAH P L/D Drilling BHA
*** Note: Bit Grade 1-7-CT-S-N-X-MT-
TD
338.0 0.0
2/7/2024
14:30
2/7/2024
15:45
1.25 COMPZN, CASING OTHR P Clean RF for liner operations 0.0 0.0
2/7/2024
15:45
2/7/2024
16:00
0.25 COMPZN, CASING PUTB P PJSM with rig crew and GBR 0.0 0.0
2/7/2024
16:00
2/7/2024
17:00
1.00 COMPZN, CASING PUTB P RU GBR to run 3.5" Hyd563 tubing 0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Page 7/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/7/2024
17:00
2/7/2024
18:00
1.00 COMPZN, CASING BHAH P P/U 3.5" L-80, 9.3#, HYD 563 Liner
BHA. Baker lock shoe track.
0.0 0.0
2/7/2024
18:00
2/7/2024
18:30
0.50 COMPZN, CASING SVRG P Service top drive 0.0 0.0
2/7/2024
18:30
2/7/2024
23:30
5.00 COMPZN, CASING PUTB P Run 3.5" HYD 563 to 1131', 35K SOW.
PU x nipple, seal bore extension and
baker ZXP LTP. PU HWDP and circulate
through float shoe. 3 BPM at 200 PSI.
0.0 1,575.0
2/7/2024
23:30
2/8/2024
00:00
0.50 COMPZN, CASING RUNL P Trip in hole with liner on drill pipe stands
from derrick . 45K SOW at 1575 and
50K SOW at 2334'
1,575.0 2,334.0
2/8/2024
00:00
2/8/2024
06:00
6.00 COMPZN, CASING TRIP P Trip in hole with liner on drill pipe stands
from derrick . 50K SOW at 2334'
2,334.0 7,260.0
2/8/2024
06:00
2/8/2024
07:00
1.00 COMPZN, CASING CIRC P Condition hole @ 3 bpm, gas in returns, 7,260.0 7,260.0
2/8/2024
07:00
2/8/2024
08:30
1.50 COMPZN, CASING TRIP P TIH with 3.5" Liner 7,260.0 8,307.0
2/8/2024
08:30
2/8/2024
09:30
1.00 COMPZN, CEMENT TRIP P Space out, Cement Head, brake
circulation, 4 bpm/95 spm/760 psi wash
down towards bottom.
8,307.0 8,344.2
2/8/2024
09:30
2/8/2024
12:00
2.50 COMPZN, CEMENT CIRC P Circulate to Condition hole, 11.6 ppg in
and out.
8,344.2 8,344.2
2/8/2024
12:00
2/8/2024
12:30
0.50 COMPZN, CEMENT CMNT P PJSM with HES, Nabors, MI SWACO for
cement job
8,344.2 8,344.2
2/8/2024
12:30
2/8/2024
15:00
2.50 COMPZN, CEMENT CMNT P Pressure test cement lines flood and
P/T surface lines from cementer to
cement head 4,000 psi, (Good Test),
primary cement job, start job as per
cementing procedure, recep pipe
throughout job set on depth 8,340',
cement going down pipe, bump plug @
1018 stks, hold 2,000 psi for 5 mins,
bleed pressure floats are holding.
pressure up against plug 3,800 psi,
slack off and work pipe to confirm set,
pressure up to 2,600 psi to release from
running tool. Rotate 25 rpm, set down
40 k, closed annular.
8,344.2 7,130.0
2/8/2024
15:00
2/8/2024
16:00
1.00 COMPZN, CEMENT RURD P BD top drive and cement line, LD
cement head.
7,130.0 7,130.0
2/8/2024
16:00
2/8/2024
16:30
0.50 COMPZN, CEMENT CIRC P Circulate out cement from 6836' at 8
BPM/1450 psi
7,130.0 7,130.0
2/8/2024
16:30
2/8/2024
17:30
1.00 COMPZN, CEMENT PRTS P P/T & chart packer 1,750 psi for 10 mins
11.6 ppg LSND in hole, Good Test, P/U
and realese RS seal assembly.
7,130.0 7,130.0
2/8/2024
17:30
2/8/2024
18:30
1.00 COMPZN, CEMENT BHAH P Flush mud maifold and kill line with
black water pill. BD kill line and mud
manifold.
7,130.0 7,130.0
2/8/2024
18:30
2/8/2024
19:30
1.00 COMPZN, CEMENT OWFF P Flow check well and load completion
equipment into pipeshed
7,130.0 7,130.0
2/8/2024
19:30
2/9/2024
00:00
4.50 COMPZN, CEMENT PULD P Pump 15 BBL dry job and start POOH
and LD DP. At 7085' PUW = 130K
7,130.0 1,380.0
2/9/2024
00:00
2/9/2024
06:00
6.00 COMPZN, CEMENT PULD P POOH and LD DP. RIH with stood back
drill pipe and LD drill pipe.
1,380.0 0.0
2/9/2024
06:00
2/9/2024
08:00
2.00 COMPZN, CEMENT PUTB P Clean RF and set up for completion ops.
Confirm pipe and jewerly in shed
Correct pipe tally
0.0 0.0
2/9/2024
08:00
2/9/2024
20:30
12.50 COMPZN, RPCOMP PUTB P P/U 3.5" L-80 563, 3.5" L-80 TN110SS
563, and 3.5" EUE 8rd tubing. Stab seal
assembly into SBR and bottom out at
7200'. PU 2' and space out. Pull out of
the seals.
0.0 7,200.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Page 8/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/9/2024
20:30
2/9/2024
22:30
2.00 COMPZN, RPCOMP DISP P Circulate well to CI seawater 3.5 BPM
taking LSND mud returns to cuttings
box.
0.0 0.0
2/9/2024
22:30
2/9/2024
23:00
0.50 COMPZN, RPCOMP THGR P Pump out the stack. Land tubing hanger
& RILDS.
0.0 0.0
2/9/2024
23:00
2/10/2024
00:00
1.00 COMPZN, RPCOMP PRTS P PT TBG to 3500 psi for 30 min and
chart. Trap 1750 on the tubing and PT
the IA to 2500 psi for 30 minutes and
chart. Drop the pressure on the tubing
and shear the SOV. Turn on the pumps
to verify SOV sheared.
0.0 0.0
2/10/2024
00:00
2/10/2024
01:00
1.00 COMPZN, RPCOMP OWFF P Open well for flow test. Blow down
cement hose and rig down landing joint.
0.0 0.0
2/10/2024
01:00
2/10/2024
02:00
1.00 COMPZN, WHDBOP MPSP P Set BPV and PT down IA to 1000 psi for
10 minutes. Blow down 2nd kill line. Jet
the stack and BD kill and choke lines.
0.0 0.0
2/10/2024
02:00
2/10/2024
06:00
4.00 COMPZN, WHDBOP NUND P Remove riser, remove turn buckles.
break bolts on DSA and kill line. Rack
back the stack and remove DSA. NU the
tree.
Test tree 250/5,000 psi
0.0 0.0
2/10/2024
06:00
2/10/2024
06:30
0.50 COMPZN, WHDBOP FRZP P PJSM, R/U LRS to well, P/T lines 3,500
psi, circulate 80 bbl of deisel freeze
protect,
0.0 0.0
2/10/2024
06:30
2/10/2024
08:00
1.50 COMPZN, WHDBOP FRZP P R/U jumper tubing x IA and Allow well to
U-tube
R/D LRS
0.0 0.0
2/10/2024
08:00
2/10/2024
12:00
4.00 COMPZN, WHDBOP RURD P Pull RF mats and rotary bushings, super
sucker and clean under rotary bushing.
Working on Rig Move and Derrick Down
checklist.
*** Rig release at 12:00 noon
0.0 0.0
2/10/2024
12:00
2/10/2024
18:00
6.00 DEMOB, MOVE MOB P Trucks on location moving Electrician
shack, Tool shack ect...Set rig tongs on
floor and Bridle up blocks. Set top drive
in stump and BD steam and water lines.
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
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9(+*+ *23 +=*+9 9(+*+ *) 2* )9* 36+396( =*2 3 (6 +9*= *2 *3 ," #'20
3(+*+ *2 *3 3(+*+ *( 2*99)9* 36+396( =* 3 (6 +9*9 * *=2 ," #'20
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)(+*+ 2*( 2+=* )(+*+ * * =)9* 36+396( 3* 3 (6 + *( 2* *9= ," #'20
((+*+ * 3 2+*=) ((+*( *+ *+)) *+ 36+396( 2*= 3 (6 +*+ 2*( 9*2 ," #'20
+(+*+ 3* ( 2+ *= +(+*3 2 *( 9* () *) 36+396(9*= 3 (6 +2*3 * 22*) ," #'20
26 (+*+ )* 2+2*= 26 (+* 2*9 =*9+) *2 36+396(29* 3 (6 (+*9 * * 9 ," #'20
262(+*+ 22*() 2+3*=) 262()*3 )*= 2 *926 )2*= 36+396)+)*+ 3 (6 (3*9 9*= (*33 ," #'20
26(+*+ 23*)( 2+3* ) 26(9*= = *= 2=*)262=(*) 36+396))9*+ 3 (6 )+*2 *+ =*2) ," #'20
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26 (+*+ 2(*+) 2+)*3 26 ( * (+* 3*226=9* 36+396)9=* 3 (6 ) *) * +2*3+ ," #'20
269(+*+ 2*) 2+=* = 269) *( 2*= 3*226 3)*+ 36+396)2*+ 3 (6 = *= *( 23*( ," #'20
263(+*+ 3* 3 2+ *++ 263=3*= 2=2* 99* 2699+*) 36+396=)9* 3 (6 32*3 *+ 2=3* ," #'20
26=(+*+ (*)) 2(+*)= 26=39*) 3*) 3*9263 (*( 36+396=+*( 3 (6 9 *9 *( 2 * = ," #'20
26)(+*+ *( 2+3*)2 26)92*3 39*2 = *926=3*= 36+3963(2*9 3 (6 *9 *= 3+*) ," #'20
26((+*+ 9* 2+(*)= 26(3*( 3*9 )+*926) +*+ 36+3963 *2 3 (6 2=* *( 2*3( ," #'20
26+(+*+ )*9 2+3*+= 26+ =*( =2*9 +=*+26)+ *+ 36+3969)9* 3 (6+(*+ *3 ) *2 ," #'20
6 (+*+ 92* 2+3*9 26+(9*2 9*9 229* 26(=(* 36+39692 *2 3 (6(2*( *+ 9 *)9 ," #'20
62(+*+ 9 * 2+3* 6 3(*2 9()* 2 2*(26+9* 36+396 9(* 3 (6=9* 2*+ 9++*2 ," #'20
6(+*+ 9 *= 2+3*3 62 *( 33 *3 23 *26 29*+ 36+396(* 3 (693*) *9 3=)*29 ," #'20
6 (+*+ 9 *+( 2+3*(9 6 *+ = * 2=(*(6 ()* 36+39623*9 3 (6)* *9 = 3*3 ," #'20
69(+*+ 99*23 2+3*() 6)9*( =()*2 2()*(623(*+ 36+39629(*3 3 (6 (* * ) 9*29 ," #'20
63(+*+ 99* 3 2+3*(= 6 9=*9 )39* =*+6 *3 36+396 (2*9 3 (62((*+ * )) * ," #'20
6=(+*+ 99*) 2+3*(9 692)*) (2*) =* 6 2*( 36+396 2 *+ 3 (62=+*( *9 (9*3 ," #'20
6)(+*+ 93* 2+=*) 69((*9 ((+*= 93*=6 )*= 36+3 6+9=* 3 (623 * *= +22*+( ," #'20
6((+*+ 93*3 2+=* 2 633(*) +3)*+ =3*3699*( 36+3 6())*) 3 (62 * * +(*2 ," #'20
6+(+*+ 93*=( 2+=* 2 6=(*) 26 =*9 (3*=632*( 36+3 6( +* 3 (622 * * 26 3*39 ," #'20
6 (+*+ 93*( 2+=*= 6=+(*3 26 +3* 3*)63(*= 36+3 6)9 *9 3 (6 + *2 * 262 *2= ," #'20
62(+*+ 9=*23 2+3*+9 6)=)*+ 262=9* 3*=6=3* 36+3 6=)2* 3 (6 ) * *9 262+9*2 ," #'20
6(+*+ 9)*+( 2+3*+ 6( =* 26 9*) 93*)6) * 36+3 6= *+ 3 (6 3 *2 2*( 26==* 3 ," #'20
6 (+*+ 9+*93 2+3*() 6+ * 26 )* ==* 6)(=*2 36+3 63(*) 3 (6 +*3 2*3 26 9 *32 ," #'20
69(+*+ 9+* 2+9*== 6+=)* 26 ( * (=*6(32*9 36+3 6933*= 3 (6 +*= 2* 26923* + ," #'20
63(+*+ 9(*(( 2+ *)) 6 * 2693 *2 9 9*(6+2)*2 36+3 6 (*3 3 )6++2*2 *) 269+ *29 ," #'20
6=(+*+ 9(* 2+9*9 6 ++* 2633*) 9*+6+( *9 36+3 6 +*+ 3 )6+) * *+ 263=9* = ," #'20
6)(+*+ 9=* 2+3* 62=)*3 263+=*3 992*3 6 32*= 36+3 6 +* 3 )6+39*9 *2 26= =*)) ," #'20
6((+*+ 9 *+ 2+9*3+ 6 (* 26==9*( 93+*= 62*9 36+3 62) *+ 3 )6+ =* *2 26) =*=( ," #'20
6+(+*+ 9 *3 2+ *32 6 2 *) 26) 2*= 9)=*9 62+9*( 36+3 62 9* 3 )6+2+*3 2* 26))3* ," #'20
96 (+*+ 9 *+ 2+2* = 6 ( * 26)+(*+ 9+2* 6=)* 36+3 6 =*) 3 )6+ 9*= 2*= 26(9 *= ," #'20
962(+*+ 9 *) 2+2* 6933* 26(==*+ 3 9*= 6 +*9 36+36+=(*( 3 )6(+2* * 26+2*=3 ," #'20
96(+*+ 9 *+ 2+2* 2 63)*9 26+ 9*+ 32)*+ 6922*3 36+36+ *( 3 )6()(* * 26+(2*) ," #'20
96 (+*+ 9 *+( 2+2*2= 63++*9 6 * 3 2* 69( *3 36+36( *) 3 )6(=9*= *2 6 3 *+ ," #'20
969(+*+ 99*3 2+ *+ 6=)2*2 6 )2*3 399*= 6333* 36+36)=9* 3 )6(32* *= 62 *9) ," #'20
963(+*+ 99* ) 2+ *+2 6)9*9 629 * 33)*( 6==*= 36+36=+3*3 3 )6( (* * 62+ * ," #'20
96=(+*+ 99* 2+ *+ 6(29* 6 (*+ 3)2*2 6=+(*2 36+36==*+ 3 )6(9*( * 6= * 2 ," #'20
96)(+*+ 93* 2(+*3) 6((3*2 6)(* 3( *= 6)=+* 36+3633)*) 3 )6(2* 2* 6 *2) ," #'20
96((+*+ 93* 2(+*2= 6+33*) 6 9)*( 3+3*2 6( +*+ 36+369()*+ 3 )6( *( * 69 *( ," #'20
96+(+*+ 99*)( 2(+*29 96 =*= 692)*3 = =* 6+2 *) 36+3692(* 3 )6)(+*3 * 69)2* = ," #'20
36 (+*+ 9=* 3 2()*++ 96 +=*( 69((* =2=*+ 6+( *+ 36+36 9)*( 3 )6))+* 2*3 639*39 ," #'20
362(+*+ 9=*3 2()* 962==*2 633+*9 ==*996 3 * 36+36)=* 3 )6)=+*9 *= 6=29*=9 ," #'20
36(+*+ 93*(3 2()*2 96 3*3 6= *+ = 3*39622+*= 36+36 9*+ 3 )6)= *9 *9 6=(=*= ," #'20
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36 (+*+ 9=*) 2(=*( 96 9*= 6) *= =99* 962((*) 36+362 * 3 )6)32*= *+ 6)3(*(+ ," #'20
369(+*+ 9)* 2(=*+ 96 ) * 6))3*2 =3*=963)*2 36+36 = *) 3 )6)9 * *3 6( 2*(3 ," #'20
363(+*+ 9=*=) 2(=*99 96992*9 6(9)*= == *)96 3*3 36+326+((* 3 )6) 3*2 * 6+ 9*)+ ," #'20
36=(+*+ 9)* ( 2(=*( 963 +*) 6+ *2 ==+*296 + *( 36+326+23*) 3 )6)=*) *3 6+))*)) ," #'20
36)(+*+ 9(*2 2()* + 963))* 6++ * =)(* 969=2* 36+326(9*3 3 )6)2)*= 2*2 6 32*= ," #'20
36((+*+ 9)*+) 2()* + 96=99* 6 =)*2 =()*(963(*2 36+326)=(*) 3 )6) (* *2 623*+( ," #'20
36+(+*+ 9)*3 2()*3 96)22* 629 *3 =+)*9963+3*9 36+326=+3* 3 )6=+(*9 *3 62++*++ ," #'20
=6 (+*+ 9)*9 2()*3) 96))(*+ 62 *3 ) )*296== * 36+326=* 3 )6=((*) *2 6) *=) ," #'20
=62(+*+ 9=*3 2(+*9= 96(9)*2 6(3*( )2)*+96) 2* 36+32633 * 3 )6=))*+ 2*= 6 9=*) ," #'20
=6(+*+ 9=*=) 2(+*+2 96+23*+ 6 3)*9 ) *296( * 36+3269)(*9 3 )6==3*) *9 692+* ," #'20
=6 (+*+ 9)*+ 2+ *9+ 96+( *) 69+*) )9 *96(=)*( 36+3269 =*2 3 )6=3*) 2* 69+*3= ," #'20
=69(+*+ 9(* 2+ *9= 36 3 *3 63 *( )3=*)96+ 9*= 36+326 * 3 )6= +* * 63==*)) ," #'20
=63(+*+ 9(*= 2+ *99 3622=*+ 63)=*9 )) *36 2* 36+3263+*3 3 )6=3*= *9 6=92* + ," #'20
=6=(+*+ 9+* ) 2+ *= 362(*) 6=3 *3 )( *(36 ==*( 36+3262(3*9 3 )6=2*2 *3 6)2=*3 ," #'20
=6)(+*+ 9+*3 2+ * = 369)*+ 6)3*2 )+)*2362 * 36+32622 *( 3 )63+(*) *3 6)+* ," #'20
=6((+*+ 9+*( 2(+*(+ 36 2*= 6( * (2 * 362+=*( 36+326 3*) 3 )63(3*3 * 6(=(* ," #'20
=6+(+*+ 3 * 2(+*() 36 ))* 6()3*3 ( *336=2*2 36+3 6+= * 3 )63)*9 * 6+99*) ," #'20
)6 (+*+ 9+*3) 2(+*= 36992*= 6+3 *( ( =*936 3*) 36+3 6((3*2 3 )633+*3 *3 96 *+= ," #'20
)62(+*+ 3 * ) 2(+*39 363 =*2 96 =* (9+*236 + * 36+3 6( +*) 3 )639=*( *3 96 +)*= ," #'20
)63 * 3 *2 2(+*9) 36399*) 96 )2*= (3=*)369(*( 36+3 6)=9* 3 )63 +* *2 9629 * 2 *3# '0
)69 =*3 3*( 2)3*( 36==2* 962=*( (= *236393* 36+3 6=2+*2 3 )63 *( 3*+ 96((* *3# '0
)69+)*3 3*9 2=)*+ 36=+(* 96=9*= (3=* 363(*9 36+3 63)2* 3 )63 +*= 2 *9 96 9*+= *3# '0
)63+*) 32*) 2= *9( 36)3=*+ 96 )* ( )*(36=92* 36+3 69+(*) 3 )633(*2 *) 969 9*+3 *3# '0
)6=((* 3*2 23)*=+ 36(23*+ 969 (*2 (2*(36) * 36+3 69)*( 3 )63( *2 9*( 969)*9) *3# '0
)6)(=*3 3 *3) 23*+9 36())* 969))*( )( *(36)=2*9 36+3 6 3(*2 3 )6=23*2 9*2 963 (* *3# '0
)6()(*( 9+*=( 29)*9( 36+ =*3 963 +* )93*=36( *= 36+3 6+=*) 3 )6=3 * 9*= 963+9*+= *3# '0
)6+)3*2 9(*() 29)* 3 36+++*9 96= *( ) =* 36(( *3 36+3 6 3* 3 )6=(+*= *( 96=32*33 *3# '0
(6 )2*9 9)*() 29(*2= =6 = *9 96==2*) ==)*+36+9)*3 36+3 62)9* 3 )6)(* 2* 96) )*3+ *3# '0
(62=9*= 9)*2 29)*3 =62=* 96)2+*( = 2* =6 2 * 36+3 622=*2 3 )6)=9*3 *+ 96)=2*29 *3# '0
(63(*3 9=*2 29(*( =62+ *) 96)))*+ 3+3* =6 )9*( 36+3 6 3(*2 3 )6( *= 2*3 96(29*=9 *3# '0
(6(=* 93*== 29+* 3 =62 * 96)+9*+ 3(3* =6 +9*2 36+3 6 92* 3 )6(2 *( *2 96( *92 *3# '0
(6 3 * 93*== 29+* 3 =639*= 96( 9* 3=2*(=62 (*) 36+3 6 2*( 3 )6( 9* * 96(==*=+ *3# '0
+ *
Page 1/1
2B-03
Report Printed: 2/23/2024
Cement Detail Report
Cement Details
Description
Production String 1 Cement
Cementing Start Date
2/8/2024 12:30
Cementing End Date
2/8/2024 15:00
Wellbore Name
2B-03B
Comment
37 bbls 15.3 ppg cement
Cement Stages
Stage # 1
Description
Production String 1
Cement
Objective Top Depth (ftKB)
7,141.0
Bottom Depth (ftKB)
8,350.0
Full Return?
Yes
Vol Cement …Top Plug?
Yes
Btm Plug?
Yes
Q Pump Init (bbl/m… Q Pump Final (bbl/… Q Pump Avg (bbl/…P Pump Final (psi) P Plug Bump (psi) Recip?
Yes
Stroke (ft) Rotated?
No
Pipe RPM (rpm)
Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in)
Comment
37 bbls of 15.3# cement
Cement Fluids & Additives
Fluid
Fluid Type
Primary Cement
Fluid Description Estimated Top (ftKB)
7,141.0
Est Btm (ftKB)
8,350.0
Amount (sacks)
177
Class
G
Volume Pumped (bbl)
37.0
Yield (ft³/sack)
1.24
Mix H20 Ratio (gal/sa…
5.57
Free Water (%) Density (lb/gal)
15.30
Plastic Viscosity (cP) Thickening Time (hr)
4.57
CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
String: Production String 1 Cement
Job: RECOMPLETION-<jobsubtyp> 1/28/2024 …
FALSE 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:
8. Date TD Reached: 16. Well Name and Number:
9. Ref Elevations: KB: 17. Field / Pool(s):
GL: 87.89'
Total Depth:1135' FSL, 833' FEL, Sec 30, T11N, R9E, UM 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
16"H-40 110'
9-5/8"J-55 2748'
7"J-55 6286'
3-1/2"L-80 6255'
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
Sr Res EngSr Pet GeoSr Pet Eng
None
Oil-Bbl:Water-Bbl:
7141'MD/5478'TVD
Directional Survey
Water-Bbl:
PRODUCTION TEST
N/A
Date of Test:Oil-Bbl:
PACKER SET (MD/TVD)
Liner ran on: 2/6/2024 7141'MD/5475'TVD to 8350'MD/6103'TVD
Gas-Oil Ratio:Choke Size:
Per 20 AAC 25.283 (i)(2) attach electronic information
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Flow Tubing
SIZE
24"
DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size
and Number; Date perf'd or liner run):
TUBING RECORD
7197'3.5"
5475'
12-1/4"34'
8-1/2"
34'
35'
26
8350'
32'
9.2
35'
7141'
3161'
6-1/8"37bbls if 15.3ppg Class G
55
36
110'
32 8395'
5950164
3161'MD/2751'TVD
SETTING DEPTH TVD
5950001
TOP HOLE SIZE AMOUNT
PULLED
507735
507834
TOP
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 River Oil Pool
7501'MD/5700'TVD
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
50-029-21151-02-00
KRU 2B-03B
ADL 0025656, ADL0025655
81-172
2/5/2024
8350' MD/6103'TVD
115.89'
P.O. Box 100360 Anchorage, AK 99510-0360
508396 5954836
2/6/2024
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
ConocoPhillips Alaska, Inc.
WAG
Gas
2/10/2024 223-080
J G
s d 1b
10 D
A
2 p
and Bot ;Perfor
L
s
(atta
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
4a. Location of Well (Governmental Section):
Surface: 689' FSL, 249' FEL, Sec 19, T11N, R9E, UM
Top of Productive Interval:
1298' FSL, 931' FEL, Sec. 30, T11N, R9E, UM
Completed
2/10/2024
JSB
RBDMS JSB 030724
By James Brooks at 3:36 pm, Mar 06, 2024
GDSR-3/29/24
Superseded
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Surface Surface
Base of Permafrost 3161 2751
8069 6062
8088 6075
8350 6254
(Miluveach)
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Dusty Ward
Digital Signature with Date:Contact Email:dusty.ward@cop.com
Contact Phone:907-265-6531
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:
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
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Top of Permafrost
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
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
Top of Productive Interval
(Kuparuk A5)
Top of Productive Interval
(Kuparuk A4)
Authorized Title: Wells Engineer
Operations Summary, Cementing Summary, Well Schematic, Directional Survey
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.
N
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Superseded
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB 7,705.0 2B-03B 2/19/2024 rogerba
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Added RWO date 2B-03B 2/22/2024 fergusp
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 35.0 110.0 110.0 55.00 H-90 WELDED
SURFACE 9 5/8 8.92 34.1 3,161.3 2,751.2 36.00 J-55 BUTT
PRODUCTION 7 6.28 32.0 8,395.2 6,100.8 26.00 J-55 BTC
Liner - Lower
completion work over
2024
3 1/2 2.99 7,141.0 8,350.0 6,103.0 9.20 L-80 Hyd 563
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
32.0
Set Depth …
7,196.7
String Max No…
3 1/2
Set Depth …
5,514.1
Tubing Description
Tubing – Completion Upper
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE 8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
32.0 32.0 0.04 Hanger 6.997 3.5" tubing hanger w/pup Camero
n/Vault
S-218 6"
x 3-1/2"
EUE
8RD
4.500
3,195.3 2,774.8 46.13 Mandrel – GAS
LIFT
4.757 3.5" x 1.5" MMG DV (Target 3168') MMG
DV
SLB 2.818
6,515.2 5,070.7 48.26 Mandrel – GAS
LIFT
4.757 3.5" x 1.5" MMG 110SKI HYD 563
(Target 6500')
MMG
SOV
SLB 2.818
7,153.8 5,486.5 49.84 Seal Assembly 3.500 3.5" 80-40 Seal Assembly (space
out 2')
HES HES 2.984
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
3,195.3 2,774.8 46.13 1 GAS LIFT GLV RK 1 1/2 1,260.0 2/19/2024 SLB MMG 0.188
6,515.2 5,070.7 48.26 2 GAS LIFT OV RK 1 1/2 2/19/2024 SLB MMG 0.250
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
7,141.0 5,478.2 49.78 Packer 5.980 4.15 4.170
7,208.2 5,521.5 50.08 Nipple - X 4.300 2.80 2.813
8,250.6 6,112.7 94.47 Collar - Landing 4.290 2.86 2.860
2B-03B, 2/23/2024 9:54:45 AM
Vertical schematic (actual)
PRODUCTION; 32.0-8,395.2
Liner - Lower completion work
over 2024; 7,141.0-8,350.0
Production String 1 Cement;
7,141.0 ftKB
Seal Assembly; 7,153.8
Mandrel – GAS LIFT; 6,515.2
Mandrel – GAS LIFT; 3,195.3
SURFACE; 34.1-3,161.3
CONDUCTOR; 35.0-110.0
Hanger; 32.0
KUP PROD
KB-Grd (ft)
28.00
RR Date
8/15/1984
Other Elev…
2B-03B
...
TD
Act Btm (ftKB)
8,350.0
Well Attributes
Field Name
KUPARUK RIVER UNIT
Wellbore API/UWI
500292115102
Wellbore Status
PROD
Max Angle & MD
Incl (°)
96.12
MD (ftKB)
8,299.11
WELLNAME WELLBORE2B-03B
Annotation
Last Workover:
End Date
2/10/2024
H2S (ppm)
90
Date
12/3/2016
Comment
Superseded
Page 1/1
2B-03
Report Printed: 2/23/2024
Cement Detail Report
Cement Details
Description
Production String 1 Cement
Cementing Start Date
2/8/2024 12:30
Cementing End Date
2/8/2024 15:00
Wellbore Name
2B-03B
Comment
37 bbls 15.3 ppg cement
Cement Stages
Stage # 1
Description
Production String 1
Cement
Objective Top Depth (ftKB)
7,141.0
Bottom Depth (ftKB)
8,350.0
Full Return?
Yes
Vol Cement …Top Plug?
Yes
Btm Plug?
Yes
Q Pump Init (bbl/m… Q Pump Final (bbl/… Q Pump Avg (bbl/…P Pump Final (psi) P Plug Bump (psi) Recip?
Yes
Stroke (ft) Rotated?
No
Pipe RPM (rpm)
Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in)
Comment
37 bbls of 15.3# cement
Cement Fluids & Additives
Fluid
Fluid Type
Primary Cement
Fluid Description Estimated Top (ftKB)
7,141.0
Est Btm (ftKB)
8,350.0
Amount (sacks)
177
Class
G
Volume Pumped (bbl)
37.0
Yield (ft³/sack)
1.24
Mix H20 Ratio (gal/sa…
5.57
Free Water (%) Density (lb/gal)
15.30
Plastic Viscosity (cP) Thickening Time (hr)
4.57
CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
String: Production String 1 Cement
Job: RECOMPLETION-<jobsubtyp> 1/28/2024 …
Superseded
Page 1/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
1/28/2024
00:00
1/28/2024
06:00
6.00 RURD P Perform rig down checklists, prep
location for move, prep loads for
transport to 2B pad, Cold weather
prevent some work being down outside
by crews
0.0 0.0
1/28/2024
06:00
1/29/2024
00:00
18.00 WAIT T Waiting on ambient temperature to
increase to start rig move.
0.0 0.0
1/29/2024
00:00
1/29/2024
06:00
6.00 MIRU, MOVE WAIT T Waiting on ambient temperature to
increase to start rig move.
0.0 0.0
1/29/2024
06:00
1/29/2024
15:00
9.00 MIRU, MOVE MOB P Prep and move camp, shop and
supporting buildings
0.0 0.0
1/29/2024
15:00
1/29/2024
18:00
3.00 MIRU, MOVE MOB P Mob rig from 2M pad to 4 corners 0.0 0.0
1/29/2024
18:00
1/30/2024
00:00
6.00 MIRU, MOVE RGRP T Drive motor on moving system fail //
Perform repairs in road
0.0 0.0
1/30/2024
00:00
1/30/2024
02:00
2.00 MIRU, MOVE MOB P Repairs complete mob rig to 4 corners,
allow traffic by, continue to move to 2B
0.0 0.0
1/30/2024
02:00
1/30/2024
12:00
10.00 MIRU, MOVE RURD P Rig on pad. prep for backing over 2B-
03. Spot over well back in pits raise
derrick continue working pre acceptance
checklist. spot in kill tanks and cutting
tanks.
0.0 0.0
1/30/2024
12:00
1/30/2024
15:00
3.00 MIRU, WELCTL RURD P Pre acceptance checklist completed.
Tool house still RU kill tanks and
hardline to rig. Mix 30 BBL deep clean
pill.
0.0 0.0
1/30/2024
15:00
1/30/2024
17:30
2.50 MIRU, WELCTL CIRC P Reverse circulate well out to 8.5#
seawater. 3BPM 750PSI
0.0 0.0
1/30/2024
17:30
1/30/2024
18:00
0.50 MIRU, WELCTL OWFF P Observe well for flow 0.0 0.0
1/30/2024
18:00
1/30/2024
20:30
2.50 MIRU, WELCTL SLKL P R/U Slickline 0.0 0.0
1/30/2024
20:30
1/30/2024
20:45
0.25 MIRU, WELCTL SLKL P P/T Lubricator 1,500 psi 0.0 0.0
1/30/2024
20:45
1/30/2024
21:00
0.25 MIRU, WELCTL MPSP P M/U IBP 0.0 0.0
1/30/2024
21:00
1/30/2024
21:15
0.25 MIRU, WELCTL MPSP P P/T connection
Sim-ops start loading DrillPipe
0.0 0.0
1/30/2024
21:15
1/30/2024
21:45
0.50 MIRU, WELCTL MPSP P Set IBP COE @ 51' from Rig Floor
Test/Chart 1,000 psi from below 10 min
0.0 0.0
1/30/2024
21:45
1/30/2024
22:30
0.75 MIRU, WELCTL SLKL P R/D Slickline 0.0 0.0
1/30/2024
22:30
1/31/2024
00:00
1.50 MIRU, WELCTL NUND P Check SSSV void, bleed crude/gas to
bucket, Nipple down tree/adaptor
0.0 0.0
1/31/2024
00:00
1/31/2024
00:45
0.75 MIRU, WELCTL NUND P Secure tree in corner of cellar, N/U
BOPE
Inspect tubing hanger threads, function
3-1/2" EUE 8rd XO, 11 turns
Function LDS in 2-5/16", out 2-15/16"
0.0 0.0
1/31/2024
00:45
1/31/2024
03:30
2.75 MIRU, WELCTL NUND P Install 7"x13-5/8" DSA, N/U 13-5/8"
BOPE
Continue sim-ops processing/loading
DP
0.0 0.0
1/31/2024
03:30
1/31/2024
18:00
14.50 MIRU, WHDBOP SVRG P Perform between well maintenance,
brake all door bolts, UPR, blinds, LPR,
clean and inspect, take photos, brake
top flange bolts, swap out 13-5/8"
annular element, (preventative maint.)
Continue to process DP
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
Page 2/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
1/31/2024
18:00
1/31/2024
20:00
2.00 MIRU, WHDBOP OTHR P RU to test BOP's MU XO's to test joints.
flood stack with fresh water perform
shell test. Load pipe shed W/264 joints
of XT-39
0.0 0.0
1/31/2024
20:00
2/1/2024
00:00
4.00 MIRU, WHDBOP BOPE P Initial BOPE test, Tested BOPE at
250/3,500 PSI for 5 Min each, test #1
Blind Rams, CMV 1,2,3, & 16, 2" Rig
Floor Kill, IBOP, Outer Test SPool Valve.
Test #2 Blind Rams, CMV, 4,5,& 6, HCR
Kill, Inner Test Spool Valve, Manual
IBOP, Test #3 Blind Rams, CMV, 7,8, &
9, Manual Kill, and XT-39 Dart Valve,
Test #4 Super and Manual Bean Choke
(1,500 psi), Test #5 Lower Pipe Rams,
XT-39 TIW, Test #6, Upper Pipe Rams,
CMV 10 & 11, Test #7 Upper Pipe
Rams, 12, 13, & 15, 3.5" FOSV, Test #8
CMV 14, Test #9 HCR Choke, Test #10
Manual Choke, Test #11, Lower Pipe
Rams, Test #12 Annular, Perform
accumulator test. Initial pressure=2950
PSI, after closure=1550 PSI, 200 PSI
attained =20 sec, full recovery attained
= 108 sec. UVBR's= 5 sec, Annular= 30
sec. Simulated blinds= 5 sec. LVBR’s=6
sec. HCR choke & kill= 1 sec each. 5
back up nitrogen bottles average = 2100
PSI. Test gas detectors, PVT and flow
show. Test Witness Waived by AOGCC
rep Sullivan, Sean T.
0.0 0.0
2/1/2024
00:00
2/1/2024
03:00
3.00 MIRU, WHDBOP BOPE P Continue testing BOPE, Test #7 Upper
Pipe Rams, 12, 13, & 15, 3.5" FOSV,
Test #8 CMV 14, Test #9 HCR Choke,
Test #10 Manual Choke, Test #11,
Lower Pipe Rams, Test #12 Annular,
Perform accumulator test. Initial
pressure=2900 PSI, after closure=1575
PSI, 200 PSI attained =11 sec, full
recovery attained = 121 sec. UVBR's=
5 sec, Annular= 22 sec. Simulated
blinds= 5 sec. LVBR’s=6 sec. HCR
choke & kill= 1 sec each. 5 back up
nitrogen bottles average = 2045 PSI.
Test gas detectors, PVT and flow show.
Test Witness Waived by AOGCC rep
Sullivan, Sean T. (( Total Test time 7.5
hrs ))
0.0 0.0
2/1/2024
03:00
2/1/2024
03:30
0.50 SLOT, RPCOMP OTHR P R/D Testing equipment, clean up RF. 0.0 0.0
2/1/2024
03:30
2/1/2024
04:00
0.50 SLOT, RPCOMP SVRG P Service Rig Top drive 0.0 0.0
2/1/2024
04:00
2/1/2024
07:00
3.00 SLOT, RPCOMP SLKL P Start RU Dutch riser. Tool siezed at
LDS unable to function L/D Dutch riser
(Dutch Riser not required for
operations./ DDT on Cement plug
passed 30 minute no flow W/8.5
seawtaer in well and BOP's tested to
3500 PSI.) R/U HES Slickline Equalized
RBP and pulled plug RD HES Slick-
line .
0.0 0.0
2/1/2024
07:00
2/1/2024
08:00
1.00 SLOT, RPCOMP RURD P RU floor to pull completion. 0.0 0.0
2/1/2024
08:00
2/1/2024
08:30
0.50 SLOT, RPCOMP PULL P MU landing joint to hanger MU X-O's to
lading joint BOLDS.
0.0 0.0
2/1/2024
08:30
2/1/2024
09:30
1.00 SLOT, RPCOMP PULL P Pull hanger and pup joints to floor.
PUW=102K weight broke back to 85K.
7,259.0 7,229.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
Page 3/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/1/2024
09:30
2/1/2024
10:30
1.00 SLOT, RPCOMP CIRC P Circulate and condition well 8.5#
seawater SxS at 100 SPM 660 PSI.
7,229.0 7,229.0
2/1/2024
10:30
2/1/2024
10:45
0.25 SLOT, RPCOMP OWFF P OWFF for 15 minutes no flow.
RD circulating eq. blow down top drive.
7,229.0 7,229.0
2/1/2024
10:45
2/1/2024
18:00
7.25 SLOT, RPCOMP PULL P Pull 3.5# EUE 8rd tubing PUW=86K
F/7229' T/Surface
*** Note: 3-1/2" EUE Cut joint 19.92'
7,229.0 0.0
2/1/2024
18:00
2/1/2024
20:00
2.00 SLOT, WHPST OTHR P Load out remaining pulled tubing out of
pipe shed, inspect cut joint, clean rig
floor, load milling assembly components
into shed, get measurments. Rig up RF
for milling operations.
0.0 0.0
2/1/2024
20:00
2/1/2024
20:30
0.50 SLOT, WHPST SFTY P Pre-spud/PJSM with crews. 0.0 0.0
2/1/2024
20:30
2/1/2024
23:00
2.50 SLOT, WHPST BHAH P M/U Milling BHA - 5-3/4" Cut Lip Shoe,
3.1/2" inner dress off mill, Wash Pipe
Extension, Wash Over Boot Basket, 3-
1/2" Flex Joint, Upper String Mill, XO (3-
1/2" IF x XT39) HWDP x 1, Oil Jars,
String Magnets x 2, and XT39 Pup Joint.
*** Note: Swallow 5.28", Mill 4.37" Shear
pins 1.1"
*** Note: Install Wear Ring
0.0 108.8
2/1/2024
23:00
2/2/2024
00:00
1.00 SLOT, WHPST TRIP P TIH with Milling/Drift BHA #1 108.8 587.0
2/2/2024
00:00
2/2/2024
00:30
0.50 SLOT, WHPST SVRG P Rig Service - Top Drive and Iron
Roughnecks
587.0 587.0
2/2/2024
00:30
2/2/2024
08:00
7.50 SLOT, WHPST TRIP P Continue RIH on singles from pipe shed
with drift/milling BHA #2, drifting DP on v
-door
Swap out dies on hand slips
RIH F/587' T/7281' PUW=140K
SOW=97K
587.0 7,241.0
2/2/2024
08:00
2/2/2024
12:00
4.00 SLOT, WHPST MILL P Establish Milling parameters
Rot=30 RPM Tq=6000 PR=3BPM Rot
Wt=115K
Tag top of tubing stump at 7259' ORKB
7253' 7ES RKB.
Mill F7259' T/7268.2' ORKB (F/7253'
T/7262.2' 7ES RKB)
7,241.0 7,259.0
2/2/2024
12:00
2/2/2024
13:00
1.00 SLOT, WHPST CIRC P Circulate high vis 25 BBL sweep 3.5
BPM.
Sweep at bit
Increase rate to 5 BPM sweeep the hole
clean.
Circulate the sweep out of the well.
7,259.0 7,259.0
2/2/2024
13:00
2/2/2024
13:15
0.25 SLOT, WHPST OWFF P OWFF for 15 minutes 0 flow 7,259.0 7,259.0
2/2/2024
13:15
2/2/2024
16:00
2.75 SLOT, WHPST TRIP P TOOH with milling BHA #1 F/7268.2'
ORKB (7262.2' 7ES RKB) T/7150'
polish casing from 7150 to 7050'.
Continue TOOH F/7050' T/587
7,259.0 587.0
2/2/2024
16:00
2/2/2024
16:30
0.50 SLOT, WHPST BHAH P Rack BHA and inspect mill. Empty boot
basket.
587.0 0.0
2/2/2024
16:30
2/2/2024
17:00
0.50 SLOT, WHPST BHAH P MU BHA 0.0 587.0
2/2/2024
17:00
2/2/2024
19:45
2.75 SLOT, WHPST TRIP P TIH F/587' T/7,267'
PUW=140k, SOW=95k
587.0 7,267.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
Page 4/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/2/2024
19:45
2/3/2024
00:00
4.25 SLOT, WHPST MILL P Establish Milling parameters
Pump rate 68 spm/4 bpm/575 psi
Rot=60 RPM Tq=6500 PR=4BPM Rot
Wt=111K
ROP slowed down, assuming on collar.
Lower pump rate 50 spm/3 bpm/305 psi
Tag top of tubing stump at 7,262' ORKB
7272' 7ES RKB.
Mill F7267' T/7277' 7ES RKB
7,267.0 7,277.0
2/3/2024
00:00
2/3/2024
01:00
1.00 SLOT, WHPST CIRC P Pump 20 bbl high vis sweep @ 3 bpm,
circulate around the corner, followed by
10 bbl spacer, PUH 6', launch final 20
bbl high vis sweep, increase pump rate
to 6 bpm
7,277.0 7,270.0
2/3/2024
01:00
2/3/2024
01:30
0.50 SLOT, WHPST SVRG P TOOH F/7,270' T/7,249', Rig Service -
Top Drive
7,270.0 7,249.0
2/3/2024
01:30
2/3/2024
04:15
2.75 SLOT, WHPST TRIP P TOOH F/7,249' T/Surface 7,249.0 112.0
2/3/2024
04:15
2/3/2024
05:00
0.75 SLOT, WHPST BHAH P L/D Milling BHA #3, inspect, gauge mills 112.0 0.0
2/3/2024
05:00
2/3/2024
07:45
2.75 SLOT, WHPST BHAH P Organize and verify WS BHA in pipe
shed.
PJSM for PU BHA.
Pulling up to attach the WS wear rig
pulled out of wellhead.
0.0 0.0
2/3/2024
07:45
2/3/2024
11:45
4.00 SLOT, WHPST RURD T Attempted to reset wear ring. unable to
engage wear ring with LDS. Called Vault
rep to address issue. removed seal from
test plug to verify test plug wasn't
preventing wear ring from making full
engagement in tubing head. 5' to
wellhead. Correct measurement from
floor to ULDS was verified attempted to
reset the wear ring. unable to engage
ULDS in wear ring. wait on well head
rep to deliver alternate wear ring.
Well head rep brought new wear ring
and no running tool. returned to wear
house for running tool.
0.0 0.0
2/3/2024
11:45
2/3/2024
14:15
2.50 SLOT, WHPST BHAH P MU BHA and whipstock 0.0 569.6
2/3/2024
14:15
2/3/2024
15:15
1.00 SLOT, WHPST TRIP P TIH F/569.6 T/1228' 569.6 1,228.0
2/3/2024
15:15
2/3/2024
16:45
1.50 SLOT, WHPST CIRC P Attempt a shallow function test.
pressuring up to 2100 PSI unable to
circulate apparent blockage in BHA
pressure falling off slowly continue to
work pressure up to 2200 PSI and allow
to drop off. Blow down top drive.
1,228.0 1,228.0
2/3/2024
16:45
2/3/2024
18:00
1.25 SLOT, WHPST TRIP T Blockage in the BHA unable to establish
shallow test on treletrack. TOOH F/1228
T/569
1,228.0 569.0
2/3/2024
18:00
2/3/2024
19:30
1.50 SLOT, WHPST BHAH T Brake down BHA until we could find
blockage. Screen Sub seems to be fully
open. brake out screen sub for
inspection. brake floats out, found metal
pieces on top of floats, Seems MWD is
plugged off.
569.0 72.8
2/3/2024
19:30
2/3/2024
21:00
1.50 SLOT, WHPST BHAH T Load backup MWD tool into pipeshed,
start warming it up, sim-ops pull
remaining BHA from hole 72,84' and
inspect mill.
72.8 0.0
2/3/2024
21:00
2/3/2024
22:45
1.75 SLOT, WHPST BHAH T M/U Gen II WS setting/Milling BHA w/4
new pins and 37k Shear screw (Batch
#103687763)
0.0 570.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
Page 5/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/3/2024
22:45
2/4/2024
00:00
1.25 SLOT, WHPST TRIP T Shallow hole test of Teletrac tools @
652'/80 gpm
570.0 652.0
2/4/2024
00:00
2/4/2024
01:00
1.00 SLOT, WHPST DHEQ P 652', continue testing tools,150 gpm/3.6
bpm
200 gpm/4.75 bpm
652.0 652.0
2/4/2024
01:00
2/4/2024
05:30
4.50 SLOT, WHPST TRIP P Continue TIH on stands at reduced
speed 45 fpm TIH F/652' T/72
PUW=135K SOW=105K
652.0 7,245.0
2/4/2024
05:30
2/4/2024
07:00
1.50 SLOT, WHPST WPST P Orient WS to 315.25* set WS at 7275
ORKB (7269' 7ES)
7,245.0 7,269.0
2/4/2024
07:00
2/4/2024
09:00
2.00 SLOT, WHPST CIRC P Circulate the well over to 11.6# WBM 47
vis 9.4 BPM at 2500PSI. Condition well.
transfer 11.6# WBM to all pits.
7,269.0 7,269.0
2/4/2024
09:00
2/4/2024
09:30
0.50 SLOT, WHPST RURD P Blow down top drive and circulating
lines.
7,269.0 7,269.0
2/4/2024
09:30
2/4/2024
11:30
2.00 SLOT, WHPST SLPC P Slip and cut drilling line 7,269.0 7,269.0
2/4/2024
11:30
2/4/2024
12:00
0.50 SLOT, WHPST SFTY P Hold pre-spud safety meeting 7,269.0 7,269.0
2/4/2024
12:00
2/4/2024
22:00
10.00 SLOT, WHPST MILL P Reestablish milling parameters
PUW=135K SOW=105K
Roll pumps 4 BPM 800 PSI Rot=70
RPM TQ=4900 Rot wt=110 PUW 120K
80 RPM=5300 Ft LBS
90 RPM=5500 Ft Lbs
Tag at 7249.7' Start milling at 75 RPM 5-
7K Tq.
WOB 3-5K
Mill through casing T/7311' ORKB
7305' (7ES RKB)
7,269.0 7,305.0
2/4/2024
22:00
2/4/2024
22:45
0.75 SLOT, WHPST REAM P Ream casing exit pumping 5 bpm/200
spm/1,231 psi, Recep through casing
exit x 2, cease rotating, lower pump
rate 1/4 bpm/17 spm/390 psi, drift
casing exit (clean).
7,305.0 7,305.0
2/4/2024
22:45
2/5/2024
00:00
1.25 SLOT, WHPST DISP P Displace well to new 11.6 ppg drilling
fluid
7,305.0 7,305.0
2/5/2024
00:00
2/5/2024
00:15
0.25 SLOT, WHPST DISP P Continue displacing well with new 11.6
ppg drilling fluid
7,305.0 7,230.0
2/5/2024
00:15
2/5/2024
00:45
0.50 SLOT, WHPST OWFF P Shut down pump observe well for flow 7,230.0 7,230.0
2/5/2024
00:45
2/5/2024
01:15
0.50 SLOT, WHPST CIRC P Line up and pump dry job, 13.6 ppg 15
bbl. Monitor well for flow
7,230.0 7,230.0
2/5/2024
01:15
2/5/2024
04:30
3.25 SLOT, WHPST TRIP P TOOH F/7230' PUW=135K T/551'
PUW=45K
7,230.0 551.0
2/5/2024
04:30
2/5/2024
07:00
2.50 SLOT, WHPST BHAH P LD BHA. #3 Window mill BHA F/551' To
surface
551.0 0.0
2/5/2024
07:00
2/5/2024
07:30
0.50 PROD1, DRILL SVRG P Service top drive. 0.0 0.0
2/5/2024
07:30
2/5/2024
09:30
2.00 PROD1, DRILL BHAH P MU drilling BHA F/0 T/337' Verify tool
face
0.0 337.0
2/5/2024
09:30
2/5/2024
10:00
0.50 PROD1, DRILL TRIP P TIH F/337' T/1150' Perform shallow
surface test on MWD
337.0 1,150.0
2/5/2024
10:00
2/5/2024
11:00
1.00 PROD1, DRILL CIRC P Condition well w/11.6# Circ at 2 BPM at
650PSI
1,150.0 1,150.0
2/5/2024
11:00
2/5/2024
15:00
4.00 PROD1, DRILL TRIP P Continue TIH F/1150' T/4000' condition
well. Continue to TIH 7243' Orient TF
Establish Pump rates and ECD's
250 GPM= 1234 PSI in DP
ECD=13.0
1,150.0 7,243.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
Page 6/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/5/2024
15:00
2/6/2024
00:00
9.00 PROD1, DRILL DDRL P Slide F/7,303' T/7,355'
Increase PR to 300 GPM
ECD=13.2PPG
Drill F/7355' 40 RPM 6K Tq. 300 GPM
T/7,564'
7,243.0 7,564.0
2/6/2024
00:00
2/6/2024
01:00
1.00 PROD1, DRILL DDRL P Driling Ahead, PR to 300 GPM
ECD=13.3PPG
Drill F/7,564' RPM 6K Tq. 300 GPM
T/7,612'
*** Note: Average ROP 84 fph
7,564.0 7,612.0
2/6/2024
01:00
2/6/2024
02:30
1.50 PROD1, DRILL DDRL P 7,612' , Pump #1 shut down, increase
pump #2 to rate 256 gpm/1,944 psi
RBIH, Drill ahead 7,612'
PUW=125 k, SOW=93 k
*** Note: Average ROP 77 fph
7,612.0 7,660.0
2/6/2024
02:30
2/6/2024
06:00
3.50 PROD1, DRILL DDRL P Slide F/7,660' T/7,674', P/U stand,
Pump 250 gpm/6 bpm/2,053 psi,
Rotate F/7,674' T/7,759' Rot=50,
TQ=6,100k
7,660.0 7,759.0
2/6/2024
06:00
2/6/2024
12:00
6.00 PROD1, DRILL DDRL P Continue rotating F/7,759'' T/8,042',
pump 272 gpm/6.5 bpm/2,677 psi,
Rot=50 rpm, TQ=7,400 k
7,759.0 8,042.0
2/6/2024
12:00
2/6/2024
18:00
6.00 PROD1, DRILL DDRL P Continue rotating F/8,042'' T/8350',
pump 281 gpm/6.7 bpm/2,441 psi,
Rot=60 rpm, TQ=7,200 k PUW=135 k
pumps on, pumps off 150 k, SOW= 97 k
Average ROP=113 fph
8,042.0 8,350.0
2/6/2024
18:00
2/6/2024
19:00
1.00 COMPZN, CASING CIRC P Circ 20 bbl Hi Vis sweep, chase with 2x
BUS, total pumped 455 bbls, 6 bpm at
2200 psi, reciprocate 20 RPM, TQ 5.8K,
118 PUW, 108K SOW
8,350.0 8,350.0
2/6/2024
19:00
2/6/2024
19:30
0.50 COMPZN, CASING OWFF P Flow check well-slight flow that is
slowing down.
8,350.0 8,350.0
2/6/2024
19:30
2/6/2024
22:30
3.00 COMPZN, CASING TRIP P Trip out of the hole, 140K UWT,
Swabbing, Pump out at 125 gpm, 1000
psi, tight spot at 7945' rotate through at
20 rpm, pulled tight again at 7910'. UWT
155K, attempt to run back in hole and
will not go down, No returns, rotate 30
rpm, work stuck pipe and increase pump
rate to 6 BPM at 2300 psi. Got pipe to
move and returns slowly came back.
8,350.0 7,943.0
2/6/2024
22:30
2/7/2024
00:00
1.50 COMPZN, CASING WASH P Wash down from 7943' to 8228', 3 BPM
at 1000 psi, Wash and ream down from
8228 to 8323'.
7,943.0 8,323.0
2/7/2024
00:00
2/7/2024
02:00
2.00 COMPZN, CASING TRIP P Wash down from 7943' to 8228', 3 BPM
at 1000 psi, Wash and ream down from
8228 to 8323'.
8,323.0 8,350.0
2/7/2024
02:00
2/7/2024
03:00
1.00 COMPZN, CASING TRIP P TOOH F/8,350' T/7,808', work through,
continue TOOH F/7,808' T/7,230'
8,350.0 7,246.0
2/7/2024
03:00
2/7/2024
07:00
4.00 COMPZN, CASING CIRC P Above Window, circulate sweep around 7,246.0 7,246.0
2/7/2024
07:00
2/7/2024
11:00
4.00 COMPZN, CASING TRIP P TOOH F/7,246' T/338' 7,246.0 338.0
2/7/2024
11:00
2/7/2024
14:30
3.50 COMPZN, CASING BHAH P L/D Drilling BHA
*** Note: Bit Grade 1-7-CT-S-N-X-MT-
TD
338.0 0.0
2/7/2024
14:30
2/7/2024
15:45
1.25 COMPZN, CASING OTHR P Clean RF for liner operations 0.0 0.0
2/7/2024
15:45
2/7/2024
16:00
0.25 COMPZN, CASING PUTB P PJSM with rig crew and GBR 0.0 0.0
2/7/2024
16:00
2/7/2024
17:00
1.00 COMPZN, CASING PUTB P RU GBR to run 3.5" Hyd563 tubing 0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
Page 7/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/7/2024
17:00
2/7/2024
18:00
1.00 COMPZN, CASING BHAH P P/U 3.5" L-80, 9.3#, HYD 563 Liner
BHA. Baker lock shoe track.
0.0 0.0
2/7/2024
18:00
2/7/2024
18:30
0.50 COMPZN, CASING SVRG P Service top drive 0.0 0.0
2/7/2024
18:30
2/7/2024
23:30
5.00 COMPZN, CASING PUTB P Run 3.5" HYD 563 to 1131', 35K SOW.
PU x nipple, seal bore extension and
baker ZXP LTP. PU HWDP and circulate
through float shoe. 3 BPM at 200 PSI.
0.0 1,575.0
2/7/2024
23:30
2/8/2024
00:00
0.50 COMPZN, CASING RUNL P Trip in hole with liner on drill pipe stands
from derrick . 45K SOW at 1575 and
50K SOW at 2334'
1,575.0 2,334.0
2/8/2024
00:00
2/8/2024
06:00
6.00 COMPZN, CASING TRIP P Trip in hole with liner on drill pipe stands
from derrick . 50K SOW at 2334'
2,334.0 7,260.0
2/8/2024
06:00
2/8/2024
07:00
1.00 COMPZN, CASING CIRC P Condition hole @ 3 bpm, gas in returns, 7,260.0 7,260.0
2/8/2024
07:00
2/8/2024
08:30
1.50 COMPZN, CASING TRIP P TIH with 3.5" Liner 7,260.0 8,307.0
2/8/2024
08:30
2/8/2024
09:30
1.00 COMPZN, CEMENT TRIP P Space out, Cement Head, brake
circulation, 4 bpm/95 spm/760 psi wash
down towards bottom.
8,307.0 8,344.2
2/8/2024
09:30
2/8/2024
12:00
2.50 COMPZN, CEMENT CIRC P Circulate to Condition hole, 11.6 ppg in
and out.
8,344.2 8,344.2
2/8/2024
12:00
2/8/2024
12:30
0.50 COMPZN, CEMENT CMNT P PJSM with HES, Nabors, MI SWACO for
cement job
8,344.2 8,344.2
2/8/2024
12:30
2/8/2024
15:00
2.50 COMPZN, CEMENT CMNT P Pressure test cement lines flood and
P/T surface lines from cementer to
cement head 4,000 psi, (Good Test),
primary cement job, start job as per
cementing procedure, recep pipe
throughout job set on depth 8,340',
cement going down pipe, bump plug @
1018 stks, hold 2,000 psi for 5 mins,
bleed pressure floats are holding.
pressure up against plug 3,800 psi,
slack off and work pipe to confirm set,
pressure up to 2,600 psi to release from
running tool. Rotate 25 rpm, set down
40 k, closed annular.
8,344.2 7,130.0
2/8/2024
15:00
2/8/2024
16:00
1.00 COMPZN, CEMENT RURD P BD top drive and cement line, LD
cement head.
7,130.0 7,130.0
2/8/2024
16:00
2/8/2024
16:30
0.50 COMPZN, CEMENT CIRC P Circulate out cement from 6836' at 8
BPM/1450 psi
7,130.0 7,130.0
2/8/2024
16:30
2/8/2024
17:30
1.00 COMPZN, CEMENT PRTS P P/T & chart packer 1,750 psi for 10 mins
11.6 ppg LSND in hole, Good Test, P/U
and realese RS seal assembly.
7,130.0 7,130.0
2/8/2024
17:30
2/8/2024
18:30
1.00 COMPZN, CEMENT BHAH P Flush mud maifold and kill line with
black water pill. BD kill line and mud
manifold.
7,130.0 7,130.0
2/8/2024
18:30
2/8/2024
19:30
1.00 COMPZN, CEMENT OWFF P Flow check well and load completion
equipment into pipeshed
7,130.0 7,130.0
2/8/2024
19:30
2/9/2024
00:00
4.50 COMPZN, CEMENT PULD P Pump 15 BBL dry job and start POOH
and LD DP. At 7085' PUW = 130K
7,130.0 1,380.0
2/9/2024
00:00
2/9/2024
06:00
6.00 COMPZN, CEMENT PULD P POOH and LD DP. RIH with stood back
drill pipe and LD drill pipe.
1,380.0 0.0
2/9/2024
06:00
2/9/2024
08:00
2.00 COMPZN, CEMENT PUTB P Clean RF and set up for completion ops.
Confirm pipe and jewerly in shed
Correct pipe tally
0.0 0.0
2/9/2024
08:00
2/9/2024
20:30
12.50 COMPZN, RPCOMP PUTB P P/U 3.5" L-80 563, 3.5" L-80 TN110SS
563, and 3.5" EUE 8rd tubing. Stab seal
assembly into SBR and bottom out at
7200'. PU 2' and space out. Pull out of
the seals.
0.0 7,200.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
Page 8/8
2B-03
Report Printed: 2/23/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
2/9/2024
20:30
2/9/2024
22:30
2.00 COMPZN, RPCOMP DISP P Circulate well to CI seawater 3.5 BPM
taking LSND mud returns to cuttings
box.
0.0 0.0
2/9/2024
22:30
2/9/2024
23:00
0.50 COMPZN, RPCOMP THGR P Pump out the stack. Land tubing hanger
& RILDS.
0.0 0.0
2/9/2024
23:00
2/10/2024
00:00
1.00 COMPZN, RPCOMP PRTS P PT TBG to 3500 psi for 30 min and
chart. Trap 1750 on the tubing and PT
the IA to 2500 psi for 30 minutes and
chart. Drop the pressure on the tubing
and shear the SOV. Turn on the pumps
to verify SOV sheared.
0.0 0.0
2/10/2024
00:00
2/10/2024
01:00
1.00 COMPZN, RPCOMP OWFF P Open well for flow test. Blow down
cement hose and rig down landing joint.
0.0 0.0
2/10/2024
01:00
2/10/2024
02:00
1.00 COMPZN, WHDBOP MPSP P Set BPV and PT down IA to 1000 psi for
10 minutes. Blow down 2nd kill line. Jet
the stack and BD kill and choke lines.
0.0 0.0
2/10/2024
02:00
2/10/2024
06:00
4.00 COMPZN, WHDBOP NUND P Remove riser, remove turn buckles.
break bolts on DSA and kill line. Rack
back the stack and remove DSA. NU the
tree.
Test tree 250/5,000 psi
0.0 0.0
2/10/2024
06:00
2/10/2024
06:30
0.50 COMPZN, WHDBOP FRZP P PJSM, R/U LRS to well, P/T lines 3,500
psi, circulate 80 bbl of deisel freeze
protect,
0.0 0.0
2/10/2024
06:30
2/10/2024
08:00
1.50 COMPZN, WHDBOP FRZP P R/U jumper tubing x IA and Allow well to
U-tube
R/D LRS
0.0 0.0
2/10/2024
08:00
2/10/2024
12:00
4.00 COMPZN, WHDBOP RURD P Pull RF mats and rotary bushings, super
sucker and clean under rotary bushing.
Working on Rig Move and Derrick Down
checklist.
*** Rig release at 12:00 noon
0.0 0.0
2/10/2024
12:00
2/10/2024
18:00
6.00 DEMOB, MOVE MOB P Trucks on location moving Electrician
shack, Tool shack ect...Set rig tongs on
floor and Bridle up blocks. Set top drive
in stump and BD steam and water lines.
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 2/10/2024
Superseded
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(* * * (* * * ()*+ 36+396( 3*3 3 (6 +3*( * * 4/A4
2(+*+ *( + *= 2(+*+ *2 *9)9* 36+396( 3*= 3 (6 +3*9 * *2 ," #'20
(+*+ * 3* (+*+ * *(2)9* 36+396( 3*( 3 (6 +3* *2 *3 ," #'20
(+*+ *2 2=*+ (+*+ *3 2* )9* 36+396( =* 3 (6 +9*( *2 *92 ," #'20
9(+*+ *23 +=*+9 9(+*+ *) 2* )9* 36+396( =*2 3 (6 +9*= *2 *3 ," #'20
3(+*+ *2 *3 3(+*+ *( 2*99)9* 36+396( =* 3 (6 +9*9 * *=2 ," #'20
=(+*+ *2 )2*22 =(+*+ *( 2*=3)9* 36+396( =* 3 (6 +9* *2 *=3 ," #'20
)(+*+ 2*( 2+=* )(+*+ * * =)9* 36+396( 3* 3 (6 + *( 2* *9= ," #'20
((+*+ * 3 2+*=) ((+*( *+ *+)) *+ 36+396( 2*= 3 (6 +*+ 2*( 9*2 ," #'20
+(+*+ 3* ( 2+ *= +(+*3 2 *( 9* () *) 36+396(9*= 3 (6 +2*3 * 22*) ," #'20
26 (+*+ )* 2+2*= 26 (+* 2*9 =*9+) *2 36+396(29* 3 (6 (+*9 * * 9 ," #'20
262(+*+ 22*() 2+3*=) 262()*3 )*= 2 *926 )2*= 36+396)+)*+ 3 (6 (3*9 9*= (*33 ," #'20
26(+*+ 23*)( 2+3* ) 26(9*= = *= 2=*)262=(*) 36+396))9*+ 3 (6 )+*2 *+ =*2) ," #'20
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26 (+*+ 2(*+) 2+)*3 26 ( * (+* 3*226=9* 36+396)9=* 3 (6 ) *) * +2*3+ ," #'20
269(+*+ 2*) 2+=* = 269) *( 2*= 3*226 3)*+ 36+396)2*+ 3 (6 = *= *( 23*( ," #'20
263(+*+ 3* 3 2+ *++ 263=3*= 2=2* 99* 2699+*) 36+396=)9* 3 (6 32*3 *+ 2=3* ," #'20
26=(+*+ (*)) 2(+*)= 26=39*) 3*) 3*9263 (*( 36+396=+*( 3 (6 9 *9 *( 2 * = ," #'20
26)(+*+ *( 2+3*)2 26)92*3 39*2 = *926=3*= 36+3963(2*9 3 (6 *9 *= 3+*) ," #'20
26((+*+ 9* 2+(*)= 26(3*( 3*9 )+*926) +*+ 36+3963 *2 3 (6 2=* *( 2*3( ," #'20
26+(+*+ )*9 2+3*+= 26+ =*( =2*9 +=*+26)+ *+ 36+3969)9* 3 (6+(*+ *3 ) *2 ," #'20
6 (+*+ 92* 2+3*9 26+(9*2 9*9 229* 26(=(* 36+39692 *2 3 (6(2*( *+ 9 *)9 ," #'20
62(+*+ 9 * 2+3* 6 3(*2 9()* 2 2*(26+9* 36+396 9(* 3 (6=9* 2*+ 9++*2 ," #'20
6(+*+ 9 *= 2+3*3 62 *( 33 *3 23 *26 29*+ 36+396(* 3 (693*) *9 3=)*29 ," #'20
6 (+*+ 9 *+( 2+3*(9 6 *+ = * 2=(*(6 ()* 36+39623*9 3 (6)* *9 = 3*3 ," #'20
69(+*+ 99*23 2+3*() 6)9*( =()*2 2()*(623(*+ 36+39629(*3 3 (6 (* * ) 9*29 ," #'20
63(+*+ 99* 3 2+3*(= 6 9=*9 )39* =*+6 *3 36+396 (2*9 3 (62((*+ * )) * ," #'20
6=(+*+ 99*) 2+3*(9 692)*) (2*) =* 6 2*( 36+396 2 *+ 3 (62=+*( *9 (9*3 ," #'20
6)(+*+ 93* 2+=*) 69((*9 ((+*= 93*=6 )*= 36+3 6+9=* 3 (623 * *= +22*+( ," #'20
6((+*+ 93*3 2+=* 2 633(*) +3)*+ =3*3699*( 36+3 6())*) 3 (62 * * +(*2 ," #'20
6+(+*+ 93*=( 2+=* 2 6=(*) 26 =*9 (3*=632*( 36+3 6( +* 3 (622 * * 26 3*39 ," #'20
6 (+*+ 93*( 2+=*= 6=+(*3 26 +3* 3*)63(*= 36+3 6)9 *9 3 (6 + *2 * 262 *2= ," #'20
62(+*+ 9=*23 2+3*+9 6)=)*+ 262=9* 3*=6=3* 36+3 6=)2* 3 (6 ) * *9 262+9*2 ," #'20
6(+*+ 9)*+( 2+3*+ 6( =* 26 9*) 93*)6) * 36+3 6= *+ 3 (6 3 *2 2*( 26==* 3 ," #'20
6 (+*+ 9+*93 2+3*() 6+ * 26 )* ==* 6)(=*2 36+3 63(*) 3 (6 +*3 2*3 26 9 *32 ," #'20
69(+*+ 9+* 2+9*== 6+=)* 26 ( * (=*6(32*9 36+3 6933*= 3 (6 +*= 2* 26923* + ," #'20
63(+*+ 9(*(( 2+ *)) 6 * 2693 *2 9 9*(6+2)*2 36+3 6 (*3 3 )6++2*2 *) 269+ *29 ," #'20
6=(+*+ 9(* 2+9*9 6 ++* 2633*) 9*+6+( *9 36+3 6 +*+ 3 )6+) * *+ 263=9* = ," #'20
6)(+*+ 9=* 2+3* 62=)*3 263+=*3 992*3 6 32*= 36+3 6 +* 3 )6+39*9 *2 26= =*)) ," #'20
6((+*+ 9 *+ 2+9*3+ 6 (* 26==9*( 93+*= 62*9 36+3 62) *+ 3 )6+ =* *2 26) =*=( ," #'20
6+(+*+ 9 *3 2+ *32 6 2 *) 26) 2*= 9)=*9 62+9*( 36+3 62 9* 3 )6+2+*3 2* 26))3* ," #'20
96 (+*+ 9 *+ 2+2* = 6 ( * 26)+(*+ 9+2* 6=)* 36+3 6 =*) 3 )6+ 9*= 2*= 26(9 *= ," #'20
962(+*+ 9 *) 2+2* 6933* 26(==*+ 3 9*= 6 +*9 36+36+=(*( 3 )6(+2* * 26+2*=3 ," #'20
96(+*+ 9 *+ 2+2* 2 63)*9 26+ 9*+ 32)*+ 6922*3 36+36+ *( 3 )6()(* * 26+(2*) ," #'20
96 (+*+ 9 *+( 2+2*2= 63++*9 6 * 3 2* 69( *3 36+36( *) 3 )6(=9*= *2 6 3 *+ ," #'20
969(+*+ 99*3 2+ *+ 6=)2*2 6 )2*3 399*= 6333* 36+36)=9* 3 )6(32* *= 62 *9) ," #'20
963(+*+ 99* ) 2+ *+2 6)9*9 629 * 33)*( 6==*= 36+36=+3*3 3 )6( (* * 62+ * ," #'20
96=(+*+ 99* 2+ *+ 6(29* 6 (*+ 3)2*2 6=+(*2 36+36==*+ 3 )6(9*( * 6= * 2 ," #'20
96)(+*+ 93* 2(+*3) 6((3*2 6)(* 3( *= 6)=+* 36+3633)*) 3 )6(2* 2* 6 *2) ," #'20
96((+*+ 93* 2(+*2= 6+33*) 6 9)*( 3+3*2 6( +*+ 36+369()*+ 3 )6( *( * 69 *( ," #'20
96+(+*+ 99*)( 2(+*29 96 =*= 692)*3 = =* 6+2 *) 36+3692(* 3 )6)(+*3 * 69)2* = ," #'20
36 (+*+ 9=* 3 2()*++ 96 +=*( 69((* =2=*+ 6+( *+ 36+36 9)*( 3 )6))+* 2*3 639*39 ," #'20
362(+*+ 9=*3 2()* 962==*2 633+*9 ==*996 3 * 36+36)=* 3 )6)=+*9 *= 6=29*=9 ," #'20
36(+*+ 93*(3 2()*2 96 3*3 6= *+ = 3*39622+*= 36+36 9*+ 3 )6)= *9 *9 6=(=*= ," #'20
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36 (+*+ 9=*) 2(=*( 96 9*= 6) *= =99* 962((*) 36+362 * 3 )6)32*= *+ 6)3(*(+ ," #'20
369(+*+ 9)* 2(=*+ 96 ) * 6))3*2 =3*=963)*2 36+36 = *) 3 )6)9 * *3 6( 2*(3 ," #'20
363(+*+ 9=*=) 2(=*99 96992*9 6(9)*= == *)96 3*3 36+326+((* 3 )6) 3*2 * 6+ 9*)+ ," #'20
36=(+*+ 9)* ( 2(=*( 963 +*) 6+ *2 ==+*296 + *( 36+326+23*) 3 )6)=*) *3 6+))*)) ," #'20
36)(+*+ 9(*2 2()* + 963))* 6++ * =)(* 969=2* 36+326(9*3 3 )6)2)*= 2*2 6 32*= ," #'20
36((+*+ 9)*+) 2()* + 96=99* 6 =)*2 =()*(963(*2 36+326)=(*) 3 )6) (* *2 623*+( ," #'20
36+(+*+ 9)*3 2()*3 96)22* 629 *3 =+)*9963+3*9 36+326=+3* 3 )6=+(*9 *3 62++*++ ," #'20
=6 (+*+ 9)*9 2()*3) 96))(*+ 62 *3 ) )*296== * 36+326=* 3 )6=((*) *2 6) *=) ," #'20
=62(+*+ 9=*3 2(+*9= 96(9)*2 6(3*( )2)*+96) 2* 36+32633 * 3 )6=))*+ 2*= 6 9=*) ," #'20
=6(+*+ 9=*=) 2(+*+2 96+23*+ 6 3)*9 ) *296( * 36+3269)(*9 3 )6==3*) *9 692+* ," #'20
=6 (+*+ 9)*+ 2+ *9+ 96+( *) 69+*) )9 *96(=)*( 36+3269 =*2 3 )6=3*) 2* 69+*3= ," #'20
=69(+*+ 9(* 2+ *9= 36 3 *3 63 *( )3=*)96+ 9*= 36+326 * 3 )6= +* * 63==*)) ," #'20
=63(+*+ 9(*= 2+ *99 3622=*+ 63)=*9 )) *36 2* 36+3263+*3 3 )6=3*= *9 6=92* + ," #'20
=6=(+*+ 9+* ) 2+ *= 362(*) 6=3 *3 )( *(36 ==*( 36+3262(3*9 3 )6=2*2 *3 6)2=*3 ," #'20
=6)(+*+ 9+*3 2+ * = 369)*+ 6)3*2 )+)*2362 * 36+32622 *( 3 )63+(*) *3 6)+* ," #'20
=6((+*+ 9+*( 2(+*(+ 36 2*= 6( * (2 * 362+=*( 36+326 3*) 3 )63(3*3 * 6(=(* ," #'20
=6+(+*+ 3 * 2(+*() 36 ))* 6()3*3 ( *336=2*2 36+3 6+= * 3 )63)*9 * 6+99*) ," #'20
)6 (+*+ 9+*3) 2(+*= 36992*= 6+3 *( ( =*936 3*) 36+3 6((3*2 3 )633+*3 *3 96 *+= ," #'20
)62(+*+ 3 * ) 2(+*39 363 =*2 96 =* (9+*236 + * 36+3 6( +*) 3 )639=*( *3 96 +)*= ," #'20
)63 * 3 *2 2(+*9) 36399*) 96 )2*= (3=*)369(*( 36+3 6)=9* 3 )63 +* *2 9629 * 2 *3# '0
)69 =*3 3*( 2)3*( 36==2* 962=*( (= *236393* 36+3 6=2+*2 3 )63 *( 3*+ 96((* *3# '0
)69+)*3 3*9 2=)*+ 36=+(* 96=9*= (3=* 363(*9 36+3 63)2* 3 )63 +*= 2 *9 96 9*+= *3# '0
)63+*) 32*) 2= *9( 36)3=*+ 96 )* ( )*(36=92* 36+3 69+(*) 3 )633(*2 *) 969 9*+3 *3# '0
)6=((* 3*2 23)*=+ 36(23*+ 969 (*2 (2*(36) * 36+3 69)*( 3 )63( *2 9*( 969)*9) *3# '0
)6)(=*3 3 *3) 23*+9 36())* 969))*( )( *(36)=2*9 36+3 6 3(*2 3 )6=23*2 9*2 963 (* *3# '0
)6()(*( 9+*=( 29)*9( 36+ =*3 963 +* )93*=36( *= 36+3 6+=*) 3 )6=3 * 9*= 963+9*+= *3# '0
)6+)3*2 9(*() 29)* 3 36+++*9 96= *( ) =* 36(( *3 36+3 6 3* 3 )6=(+*= *( 96=32*33 *3# '0
(6 )2*9 9)*() 29(*2= =6 = *9 96==2*) ==)*+36+9)*3 36+3 62)9* 3 )6)(* 2* 96) )*3+ *3# '0
(62=9*= 9)*2 29)*3 =62=* 96)2+*( = 2* =6 2 * 36+3 622=*2 3 )6)=9*3 *+ 96)=2*29 *3# '0
(63(*3 9=*2 29(*( =62+ *) 96)))*+ 3+3* =6 )9*( 36+3 6 3(*2 3 )6( *= 2*3 96(29*=9 *3# '0
(6(=* 93*== 29+* 3 =62 * 96)+9*+ 3(3* =6 +9*2 36+3 6 92* 3 )6(2 *( *2 96( *92 *3# '0
(6 3 * 93*== 29+* 3 =639*= 96( 9* 3=2*(=62 (*) 36+3 6 2*( 3 )6( 9* * 96(==*=+ *3# '0
+ *
Superseded
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
Development Exploratory
Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 8350'feet None feet
true vertical 6103' feet None feet
Effective Depth measured 8350'feet 7153'feet
true vertical 6103' feet 5483' feet
Perforation depth Measured depth
True Vertical depth
Tubing (size, grade, measured and true vertical depth) 3-1/2" L-80 7197' MD 5510' TVD
Packers and SSSV (type, measured and true vertical depth) 7154' MD
N/A
5483' MD
N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work: Kuparuk River Oil Pool
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
3161' 2748'
Burst Collapse
Production
Liner
8363'
2172'
Casing
6286'
3-1/2"
8395'
8350' 6255'
3127'
110'Conductor
Surface
Intermediate
16"
9-5/8"
75'
measured
TVD
7"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-080
50-029-21151-02-00
P.O. Box 100360
Anchorage, AK 99510
3. Address:
ConocoPhillips Alaska, Inc.
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0025655, ADL0025656
Kuparuk River Field/ Kuparuk River Oil Pool
KRU 2B-03B
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
25 BOPD
Gas-Mcf
MD
~
Size
110'
250 BWPD 820 psi 60 mscfd
Well was Shut-In ~~
146 psi
324-160
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
~
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
N/A
Packer: 80-40 Seal Assembly
SSSV: None
Jonathan Coberly
jonathan.coberly@conocophillips.com
(907) 265-1013CTD / RWO Engineering Supervisor
New Perfs: 8069-8079', 8095-8115', 8116-8136'
New Perfs: 6062-6068', 6079-6093', 6093-6107'
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 9:52 am, Jun 07, 2024
DTTMSTART JOBTYP SUMMARYOPS
3/7/2024 SUPPORT
OTHER
OPERATIONS
CLEAN DRIFT W/ 20.33' OF 1.875" STEM & 1.75" SAMPLE BAILER. READY
FOR CBL. IN PROGRESS.
3/8/2024 SUPPORT
OTHER
OPERATIONS
RAN 1.69" CBL LOGGING TOOLS TO TD @ 8254' RKB LOG TO 6400' RKB
TOC @ 7190' RKB, CLEAN DRIFT TO 8254' RKB W/ 20' x 2.70" DUMMY
DRIFT. READY FOR E-LINE.
4/10/2024 SUPPORT
OTHER
OPERATIONS
SPOT ELINE EQUIPMENT, ISSUES WITH CRANE OUT-RIGGER, RESOLVE,
COMPLETE RU, PT LUBRICATOR, CHANGE OUT NEEDLE VALVE. JOB IN
PROGRESS.
4/11/2024 SUPPORT
OTHER
OPERATIONS
PERFORATE 3.5" LINER WITH MILLENNIUM II, 2.5" GUNS, 6SPF, 60°
PHASE, CORRELATE TO CBL LOG DATED 03/08/24.
RUN 1: INTERVAL 8136' - 8116', CCL TO TOP SHOT = 9.7', CCL STOP
DEPTH = 8106.3'
RUN 2: INTERVAL 8095' - 8115', CCL TO TOP SHOT = 2.8', CCL STOP
DEPTH = 8092.2'
RUN 3: INTERVAL 8069' - 8079', CCL TO TOP SHOT = 2.9', CCL STOP
DEPTH = 8066.1'
JOB IS COMPLETE.
4/14/2024 SUPPORT
OTHER
OPERATIONS
DRIFT FOR DUAL SPARTEK GAUGES TO 8150' RKB. MEASURE SBHP @
8100 RKB (4037 PSI) JOB COMPLETE.
5/5/2024 ACQUIRE
DATA
(AC EVAL) : TIFL (PASS).
2B-03B Perforations
Summary of Operations
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB 7,705.0 2B-03B 2/19/2024 rogerba
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Added perforations 2B-03B 4/11/2024 jconne
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 35.0 110.0 110.0 55.00 H-90 WELDED
SURFACE 9 5/8 8.92 34.1 3,161.3 2,748.1 36.00 J-55 BUTT
PRODUCTION 7 6.28 32.0 8,395.2 26.00 J-55 BTC
Liner - Lower
completion work over
2024
3 1/2 2.99 7,141.0 8,350.0 6,254.6 9.20 L-80 Hyd 563
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
32.0
Set Depth
7,196.7
Set Depth
5,510.5
String Max No
3 1/2
Tubing Description
Tubing Completion Upper
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE 8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
32.0 32.0 0.01 Hanger 6.997 3.5" tubing hanger w/pup Camero
n/Vault
S-218 6"
x 3-1/2"
EUE
8RD
4.500
3,195.3 2,771.7 46.25 Mandrel GAS
LIFT
4.757 3.5" x 1.5" MMG DV (Target 3168') MMG
DV
SLB 2.818
6,515.2 5,067.4 48.31 Mandrel GAS
LIFT
4.757 3.5" x 1.5" MMG 110SKI HYD 563
(Target 6500')
MMG
SOV
SLB 2.818
7,153.8 5,482.9 49.89 Seal Assembly 3.500 3.5" 80-40 Seal Assembly (space
out 2')
HES HES 2.984
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
3,195.3 2,771.7 46.25 1 GAS LIFT GLV RK 1 1/2 1,260.0 2/19/2024 SLB MMG 0.188
6,515.2 5,067.4 48.31 2 GAS LIFT OV RK 1 1/2 2/19/2024 SLB MMG 0.250
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
7,141.0 5,474.7 49.83 Packer 5.980 4.15 4.170
7,208.2 5,517.9 50.09 Nipple - X 4.300 2.80 2.813
8,250.6 6,185.2 46.19 Collar - Landing 4.290 2.86 2.860
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,069.0 8,079.0 6,061.7 6,068.4 4/11/2024 6.0 APERF 2.5" MILLENIUM II GUNS, 6
SPF, 60° PHASE
8,095.0 8,115.0 6,079.2 6,092.7 4/11/2024 6.0 APERF 2.5" MILLENIUM II GUNS, 6
SPF, 60° PHASE
8,116.0 8,136.0 6,093.3 6,106.9 4/11/2024 6.0 APERF 2.5" MILLENIUM II GUNS, 6
SPF, 60° PHASE
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
7,141.0 8,350.0 5,474.6 6,254.6 Production
String 1
Cement
37 bbls of 15.3# cement 2/8/2024
2B-03B, 6/7/2024 7:46:28 AM
Vertical schematic (actual)
X O
PRODUCTION; 32.0-8,395.2
Liner - Lower completion work
over 2024; 7,141.0-8,350.0
APERF; 8,116.0-8,136.0
APERF; 8,095.0-8,115.0
APERF; 8,069.0-8,079.0
Production String 1 Cement;
7,141.0 ftKB
Seal Assembly; 7,153.8
Mandrel GAS LIFT; 6,515.2
Mandrel GAS LIFT; 3,195.3
SURFACE; 34.1-3,161.3
CONDUCTOR; 35.0-110.0
Hanger; 32.0
KUP PROD
KB-Grd (ft)
28.00
RR Date
8/15/1984
Other Elev
2B-03B
...
TD
Act Btm (ftKB)
8,350.0
Well Attributes
Field Name
KUPARUK RIVER UNIT
Wellbore API/UWI
500292115102
Wellbore Status
PROD
Max Angle & MD
Incl (°)
96.12
MD (ftKB)
8,299.11
WELLNAME WELLBORE2B-03B
Annotation
Last Workover:
End Date
2/10/2024
H2S (ppm)
90
Date
12/3/2016
Comment
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: Replace Tubing
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?N/A
Yes No
9. Property Designation (Lease Number): 10. Field:
Kuparuk Oil Pool Kuparuk Oil Pool
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
8350' 6103' 7705' 5826'None None
Casing Collapse
Conductor
Surface
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone: 907-263-6531
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
KRU 2B-03B
8069-8079'MD
8095-8115'MD
8116-8136'MD
8363'
3.5"
6062-6068'
6079-6093'
6093-6107'
8350'1209'
3-1/2"
6255'
Baker ZXP
3127'
8395'
Perforation Depth MD (ft):
110'
3161'
6286'7"
16"
9-5/8"
75'
Burst
7197'
MD
110'
2748'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025655, ADL00256
223-080
P.O. Box 100360, Anchorage, AK 99510 50-029-21151-02-00
ConocoPhillips Alaska, Inc
Proposed Pools:
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
Packer: 7141'MD/5475'
Perforation Depth TVD (ft):
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Length Size
Kuparuk River Field
Dusty Ward
dusty.ward@conocophillips.com
CTD/RWO Engineer
Subsequent Form Required:
Suspension Expiration Date:
L-80
TVD
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Date:
6/23/2024
By Grace Christianson at 9:01 am, May 22, 2024
324-302
10-404
SFD 6/10/2024
CDW 06/07/2024
DSR-5/22/24
6/23/2024
X
Fracture Stimulate
VTL 6/7/2024*&: JLC 6/19/2024
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.06.19 10:55:08 -08'00'06/19/24
RBDMS JSB 062024
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
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-1480 (Zip 99501)
P.O. Box 100360
Anchorage, AK 99510-0360
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 Via Certified Mail No. 7021 1970 0001 0637 9047
1400 Smith Street Room 45104
Houston, TX 77002
Attn: Gary Selisker
ExxonMobil Alaska Production Inc. Via Certified Mail No. 7018 0680 0002 2000 1489
PO Box 196601
Anchorage, AK 99519
Attn: Todd Griffith
Landowners:
State of Alaska Via Certified Mail No. 7019 0140 0000 8047 6485
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 Via Certified Mail No. 7019 0140 0000 8047 6485
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 (2)(A)
Plat 1: Wells within 1/2 mile
Table 1: Wells within 1/2 miles (2)(C)
2B-03B Frac Sundry Well Intersect Tract Buffer
Field Name API * Well Name Status Symbology
KUPARUK RIVER UNIT 500292107800 2B-06 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292107900 2B-08 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292108000 2B-07 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292108200 2B-09 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292108400 2B-10 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292108900 2B-11 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292109200 2B-12 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292106700 2B-05 ACTIVE Injector Miscible Water Alternating Gas
KUPARUK RIVER UNIT 500292115200 2B-04 ACTIVE Oil
KUPARUK RIVER UNIT 500292115400 2B-02 PA Plugged and Abandoned
KUPARUK RIVER UNIT 500292115401 2B-02A ACTIVE Oil
KUPARUK RIVER UNIT 500292115460 2B-02AL1 ACTIVE Oil
KUPARUK RIVER UNIT 500292115461
2B-02AL1-
01 ACTIVE Oil
KUPARUK RIVER UNIT 500292115470 2B-02APB1 PA Plugged and Abandoned
KUPARUK RIVER UNIT 500292113800 2B-13 ACTIVE Oil
KUPARUK RIVER UNIT 500292116700 2G-04 ACTIVE Oil
KUPARUK RIVER UNIT 500292114300 2B-14 ACTIVE Oil
KUPARUK RIVER UNIT 500292114500 2B-15 ACTIVE Oil
KUPARUK RIVER UNIT 500292114560 2B-15L1 ACTIVE Oil
KUPARUK RIVER UNIT 500292114561 2B-15L1-01 ACTIVE Oil
KUPARUK RIVER UNIT 500292114570
2B-
15L1PB1 PA Plugged and Abandoned
KUPARUK RIVER UNIT 500292114600 2B-16 ACTIVE Oil
KUPARUK RIVER UNIT 500292114700 2B-01 ACTIVE Oil
KUPARUK RIVER UNIT 500292115100 2B-03 PA Plugged and Abandoned
KUPARUK RIVER UNIT 500292115101 2B-03A SUSP Suspended
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)
The surface casing is cemented and tested in accordance with 20 AAC 25.030. The 7.0” production casing
was cemented on original drill and CBL from 9/19/1994 estimates TOC outside the 7.0” at 6734’ ORKB/5215’
TVD. The recent sidetrack of original wellbore to install a 3.5” cement liner had a CBL that showed TOC of
cemented liner to be 7190’ MD/ 5506’ TVD, which is 753’ MD/ 472’ TVD above the top of the Kuparuk
reservoir, which is at 7943’ MD/ 5978’ TVD. It is our assessment that this cement height will provide adequate
isolation for stimulation operations.
See Wellbore schematic for casing details.
2B-03B RWOST Schematic RWO Completion
COMPLETION
INFO
MD
(ft RKB)
TVD
(ft RKB)
OD
(in)
Nom. ID
(in)
Weight
(lb/ft)Grade Thread
Conductor 110 110 16 15.06 55 H90 Welded
Surface 3161 2751 9.625 8.921 36 J55 BTC
Production 8395 6101 7 6.276 26 J55 BTC
Liner 8350 6254.6 3.5 2.992 9.3 L80 HYD563
Tubing 7196.7 5511 3.5 2.992 9.3 L80/TN110 HYD563/EUEM
3.5" COMPLETION
3-1/2" 9.3# L80/TN110 EUEM Tubing to surface
3-1/2" Camco MMG gas lift mandrels @ 3195' and
6515' RKB
CEMENTED 3.5" LINER
5.0" x 7.0" Liner Top Packer @ 7141' RKB (4" ID)
SBE
3-½" X landing nipple at 7208' RKB (2.813" min ID)
3.5" Cemented Liner Across A-sand Interval
3-1/2" Landing Collar
3-1/2" Float Collar
3-1/2" Float Shoe
Surface Casing
(Cemented to Surface)
Production
Casing
Conductor
A-sand
perfs
C-sand
Perfs
7758' ORKB
TOWS ~ 7269' MD
7982' ORKB
TOW: 8066.5',
BOW: 8074
TD OH ~ 8350' RKB
3.5" Liner TOC ~7190' MD / 5506' TVD
CEMENTED COMPLETION LEFT IN HOLE
3.5" x 7.0" Packer (7758' RKB)
GLM
Blast Rings
GLM
3.5" x 7.0" Packer (7982' RKB)
2-3/8" CTD Liner Top (7993' RKB)
2.75" D-Nipple (8000' RKB)
Camco SOS @ 8006' RKB
Perfs:
Zone MD TVDSS
A5 Top Perf 8069 5945
A5 Base Perf 8080 5952
A4 Top Perf 8095 5962
A4 Base Perf 8136 5990
Arctic Packed OA.
MIT-OA pass to
1800 psig 07/2023
Production Casing Original
TOC ~6734' ORKB/ 5215'
OTVD
Agree. SFDTOC of
cemented liner to be 7190’MD/
CBL
CBL from 9/19/1994
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:
9-5/8” casing cement pump report on 08/09/1984 shows that the original job pumped as designed. The cement
job was pumped with 800 sx of class 3 cement and 500 sx of class 2 tail cement. The plug was bumped.
Original 7.0” casing was cemented per plan on 8/16/1984 with 350 sx of Class 1 G cement. A subsequent CBL
on 09/191984 showed estimated TOC at 6734’ ORKB / 5215’ OTVD.
And arctic pack cement job was performed on 8/17/1984 with 250 sx of clas I cement. Subsequent MIT-OAs to
1800 psig have passed, indicating competent arctic pack cement.
The 3-1/2” liner was cemented in place on 2/8/2024 per plan with plugs bumping and floats holding while
reciprocating through job. Subsequent CBL report on 03/08/2024 shows good TOC at 7190’ RKB/ 5506’ TVD.
Summary
All casing is cemented 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.
Agree.
SFD
SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND
TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7)
On 7/23/2023the 7.0” x 9-5/8” outer annulus casing was pressure tested to 1800 psi as an MIT-OA. Good test.
On 2/9/2024 the 3-1/2” x 7.0” inner annulus casing was pressure tested to 2500 psi as a MIT-IA. Good Test
On 2/9/2024 the 3-1/2” tubing was pressure tested to 3500 psi as a MIT-T. Good Test
AOGCC Required Pressures [all in psi]
Maximum Predicted Treating Pressure (MPTP) 5,550
Inner Annulus pressure during frac 2,500
Annulus PRV setpoint during frac 2,600
7” Annulus pressure Test 2,750
3-1/2" Tubing pressure Test 3,550
Electronic PRV 6,650
Highest pump trip 6,050
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
9-5/8”36 J-55 3,520 2,020
7.0” 26 J-55 4,980 4,320
3-1/2”9.3 L-80 10,160 10,540
3-1/2”9.3 TN-110SS 13,970 13,530
Table 2: Wellbore pressure ratings
Stimulation Surface Rig-Up
Stinger Tree Saver
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 fracturing zone, within the Kuparuk Oil Pool, are the Kuparuk A4 and A5 sands, starting at 5945’ TVDSS (8069’ MD)
in the 2B-03B well and have an average gross thickness of ~60’ TVD. The Kuparuk Oil Pool is comprised of multiple
stacked reservoirs of very fined grained, quartz rich sandstones separated by laterally continuous shale beds, in this area
the main reservoirs are the Kuparuk C4 sand and A4 and A5 reservoirs. The gross thickness of the Kuparuk interval here
is ~210’ TVD. The estimated fracture pressure for the Kuparuk A4 and A5 is 13.1 ppg. The overlaying confining interval
for the Kuparuk is the Kalubik and HRZ shales, totaling approximately 350’ TVD. The top of the confining interval starts at
5488’ TVDSS (7346’ MD) The estimated fracture pressure of the Kalubik and HRZ ranges from 16-17 ppg. The underlying
confining zone is the Miluveach shale, extending ~500’ feet below the reservoir based on offset well control with an
estimated fracture pressure of 15.5 ppg. The estimated formation pressure in the A4 and A5 sands is 3500 psi.
Top pick TVDSS MD
HRZ -5488.92 7346.39
Kalubik -5720.9 7723.44
Kuparuk C4 (Top
Kuparuk)
-5861.34 7942.75
Kuparuk_A5 -5945.26 8069.5
Kuparuk_A4 -5957.9 8088.4
Miluveach -6073.43 8257.8
Table of formation tops
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:
2B-02: This well has been P&A’d.
2B-02A: CTD Lateral drilled in 2016. Original 7” casing cement job of 2B-02 in 8/24/1984 was done according
to plan. 280 sx of Class G cement was pump and plugs bumped. An Arctic Pack cement job was done on
8/27/1984 of 250 sx of CS 1 cement, follow by 53 bbls of arctic pak. The CBL ran in 1984 shows adequate
cement for isolation.
2B-02AL1: CTD Lateral drilled in 2016. Original 7” casing cement job in 8/24/1984 was done according to
plan. 280 sx of Class G cement was pump and plugs bumped. An Arctic Pack cement job was done on
8/27/1984 of 250 sx of CS 1 cement, follow by 53 bbls of arctic pak. The CBL ran in 1984 shows adequate
cement for isolation.
2B-02AAL1-01: CTD Lateral drilled in 2016. Original 7” casing cement job in 8/24/1984 was done according to
plan. 280 sx of Class G cement was pump and plugs bumped. An Arctic Pack cement job was done on
8/27/1984 of 250 sx of CS 1 cement, follow by 53 bbls of arctic pak. The CBL ran in 1984 shows adequate
cement for isolation.
2B-02APB1: This well has been P&A’d.
2B-03: This well has been P&A’d.
2B-03A: This well has been Suspended.
2B-05: Original 7” casing was ran and cemented in with 400 sx of Class G cement. Plug bumped. Arctic pak
job was pumped with 250 sx of Permafrost C cement followed by 62 bbls Arcitc Pack. Release from the well on
2/5/1984. The CBL ran in 1984 shows adequate cement for isolation.
2B-07: Original 7” casing was cemented in place with 450 sx of class G cement. Plug was bumped. An arctic
pack job with 250 sx of permafrost C cement was pumped followed by 62 bbls of Arctic Pack. Rig was releases
2/21/1984. The CBL ran in 1984 shows adequate cement for isolation.
2G-04: Original 7” casing was ran and cemented in with 535 sx of class G cement. Plug bumped. Well was
arctic packes with 42 bbls of permafrost C cement, followed by 60 bbls of Arctic Pak. The CBL ran in 1984
shows adequate cement for isolation.
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 five faults
transect the Kuparuk Oil Pool reservoir within one half mile radius of the 2B-03B wellbore, as shown in Plat. The 2B-03B
wellbore did not intersect any of the mapped faults during drilling. The mapped faults in the area have 40’ or less
interpreted throw and terminate within the overburden confining zones, the Kalubik and HRZ.
If there is any indication that a fracture has intersected any mapped faults (or any other faults unmapped to date) during
fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately.
five faultsp, ,,
transect the Kuparuk Oil Pool reservoir within one half mile radius of the 2B-03B
40’ or lessypp ggpp
interpreted throw and terminate within the overburden confining zones, the Kalubik and HRZ
SECTION 12 –PROPOSED HYDRAULIC FRACTURING PROGRAM
20 AAC 25.283(a)(12)
2B-03B was completed in 2024 as a slant producer in the Kuparuk A and C formations. The well was
completed with a 3-1/2” tubing upper completion and a 3-1/2”cemented liner across the A and C sands. Only
the A-sands will be perforated at this time. The A-sand is now planned to be frac’d as a single stage.
Proposed Procedure:
Halliburton Pumping Services:
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. Pressure test the treesaver to 10,000 psi.
4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC.
5. MIRU ~5 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank
volume plus 10%. Load tanks with enough 100º F seawater required for breakdown, maximum pad
and displacement. (450 bbls usable volume per tank).
6. MIRU HES Frac Equipment.
7. PT Surface lines to 8,000 psi using a Pressure test fluid.
8. Test IA Pop off system to ensure lines are clear and all components are functioning properly.
9. Bring up pumps and increase annulus pressure from 2,000 psi to 2,500 psi as the tubing pressures
up.
10. Pump the single stage Frac job by following attached HES schedule @ ~25bpm with a maximum
expected treating pressure of 5,550 psi.
11. RDMO HES Equipment. Freeze Protect the tubing and wellhead if not able to complete following the
flush.
12. Well is ready for Post Frac well prep and flowback
Stage
Job
Size
(lb)
Top
MD
(ft)
Top
TVD
(ft)
Propped
HalfLength
(ft)
Fracture
Height
(ft)
Avg
Fracture
Width (in)
1 95,000 8,069 5,878 200 120 0.154
KRU 2B-03B
Disclaimer Notice:
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 results.
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 for initial clean up production.
Hydraulic Fracturing Fluid Product Component Information Disclosure
2024-03-22
Alaska
BEECHEY POINT
50-029-21151
CONOCOPHILLIPS
2B 03B
-149.9382
70.2872
NAD83
none
Oil
6254
72610
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%84.10598%618638 Density = 8.52 Halliburton
BE-6(TM)
Bactericide Halliburton Microbiocide Listed Below Listed Below 0
CAT-3
ACTIVATOR Halliburton Activator 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 NA
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
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%0.00075%6
2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00163%12
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
Ammonia 7664-41-7 1.00%0.00023%2
Ammonium chloride 12125-02-9 5.00%0.00113%9
Ammonium persulfate 7727-54-0 100.00%0.00495%37
Borate salts Proprietary 60.00%0.10738%790
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%1
Calcium Chloride 10043-52-4 100.00%1.38673%10200
Calcium magnesium carbonate 16389-88-1 1.00%0.00179%14
Corundum 1302-74-5 65.00%8.04166%59150
Crystalline silica, quartz 14808-60-7 100.00%0.54498%4009
Distillates (petroleum),
hydrotreated light 64742-47-8 100.00%0.94080%6920
EDTA/Copper chelate Proprietary 30.00%0.00680%51 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Ethanol 64-17-5 60.00%0.04501%332
Gluteraldehyde 111-30-8 1.00%0.00179%14
Guar gum 9000-30-0 100.00%0.29611%2178
Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.02250%166
Inorganic mineral 1317-65-3 5.00%0.00895%66
Inorganic mineral Proprietary 1.00%0.00179%14 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%0.00018%2
Mullite 1302-93-8 45.00%5.56730%40950
Naphthalene 91-20-3 5.00%0.00375%28
Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.02250%166 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Oxyalkylated phenolic resin Proprietary 10.00%0.00750%56 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Oxylated phenolic resin Proprietary 30.00%0.00148%11 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%0.00375%28
Polymer Proprietary 1.00%0.00179%14 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Potassium chloride 7447-40-7 5.00%0.00895%66
Sodium bisulfate 7681-38-1 0.10%0.00018%2
Sodium chloride 7647-14-5 5.00%4.20601%30938
Sodium hydroxide 1310-73-2 30.00%0.02147%158
Water 7732-18-5 100.00%0.20161%1483
* 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:
TreatmentCUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.28725159TRUELEASE2B-03BSALES ORDERBHST (°F)LONG-149.938252560FORMATIONKuparukDATE Max Pressure (psi)7000*Exceeds 80% of burst pressure*24Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-IIBE-67TreatmentStage 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)11-1 Shut-In Shut-In1:31:54 11-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:31:54 11-3 Shut-In Shut-In1:27:09 11-4 30# Linear DFIT 15 1,680 40 40 0:02:40 1:27:09 1.00 30.00 2.00 0.250.1511-5 Shut-In Shut-In1:24:29 11-6 30# Linear Step Rate Test 15 3,360 80 80 0:05:20 1:24:29 1.00 30.00 2.00 0.250.1511-7 30# Hybor G Minifrac - Establish Fluid 15 8,400 200 200 0:13:20 1:19:09 2.00 1.00 0.80 30.00 2.00 0.250.1511-8 30# Hybor G Minifrac - Treatment 25 8,350 199 199 0:07:57 1:05:49 2.00 1.00 0.80 30.00 2.00 0.250.1511-9 30# Linear Minifrac - Flush 25 2,710 65 65 0:02:35 0:57:52 1.00 30.00 2.00 0.250.1511-10 Shut-In Shut-In 0.410:55:17 11-11 30# Hybor G Establish Stable Fluid 15 8,400 200 200 0:13:20 0:55:17 2.00 1.00 0.80 30.00 2.00 0.250.1511-12 30# Hybor G Pad 25 12,700 302 302 0:12:06 0:41:57 2.00 1.00 0.80 30.00 2.00 0.250.1511-13 30# Hybor G Conditioning Pad 100M 1.00 25 4,000 95 100 4,000 0:03:59 0:29:51 2.00 1.00 0.80 30.00 2.00 0.250.1511-14 30# Hybor G Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 25 3,200 76 83 6,400 0:03:20 0:25:52 2.00 1.00 0.80 30.00 2.00 0.250.1511-15 30# Hybor G Proppant Laden Fluid Wanli 16/20 Ceramic 3.00 25 3,300 79 89 9,900 0:03:34 0:22:32 2.00 1.00 0.80 30.00 2.00 0.250.1511-16 30# Hybor G Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 25 3,600 86 101 14,400 0:04:03 0:18:58 2.00 1.00 0.80 30.00 2.00 0.250.1511-17 30# Hybor G Proppant Laden Fluid Wanli 16/20 Ceramic 5.00 25 3,700 88 108 18,500 0:04:20 0:14:55 2.00 1.00 0.80 30.00 2.00 0.250.1511-18 30# Hybor G Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 25 3,700 88 112 22,200 0:04:29 0:10:35 2.00 1.00 0.80 30.00 2.00 0.250.1511-19 30# Hybor G Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 25 2,800 67 87 19,600 0:03:31 0:06:06 2.00 1.00 0.80 30.00 2.00 0.250.1511-20 30# Linear Flush 25 2,710 65 65 0:02:35 0:02:35 1.00 30.00 2.00 0.250.151 1-21 Shut-In Shut-In300773,610 1,753 1,854 95,000Design Total (gal)Design Total (lbs)CL-28M Losurf-300D MO-67 WG-36 OPTIFLO-III OPTIFLO-II BE-662,15091,000(gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)10,4604,000Initial Design Material Volume 124.3 72.6 49.7 2,178.3 145.2 18.2 10.9-1,000-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 2.1 1.1 0.8 31.5 2.1 2.1 0.2-Min Additive RateLiquid AdditivesDry Additives50-029-21151Fluid Type30# Hybor G30# LinearSeawaterFreeze Protect----Proppant TypeWanli 16/20 Ceramic100M---Interval 1@ 8039 - 8136 ft - °F1:31:54 Conoco Phillips - 2B-03BPlanned Design1
Originated: Delivered to:2ͲMayͲ24Halliburton Alaska Oil and Gas Conservation Comm.Wireline & PerforatingAttn.:Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska99501Anchorage, Alaska 99518Office: 907Ͳ275Ͳ2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET#11DͲ117 50Ͳ029Ͳ22844Ͳ00 n/a Kuparuk River Plug Setting Record FieldͲFinal 21ͲAprͲ24 0 121EͲ05A 50Ͳ029Ͳ20479Ͳ01 n/a Kuparuk River Plug Setting Record FieldͲFinal 2ͲAprͲ24 0 131HͲ102 50Ͳ029Ͳ23580Ͳ00 909266407 Kuparuk River Multi Finger Caliper Field & Processed 22ͲAprͲ24 0 142BͲ03B 50Ͳ029Ͳ21151Ͳ02 909270379 Kuparuk River Perforation Record FieldͲFinal 11ͲAprͲ24 0 152CͲ12 50Ͳ029Ͳ21222Ͳ00 n/a Kuparuk River Leak Detect Log FieldͲFinal 29ͲAprͲ24 0 162DͲ13 50Ͳ029Ͳ21070Ͳ00 909258948 Kuparuk River Leak Detect Log FieldͲFinal 11ͲAprͲ24 0 172DͲ13 50Ͳ029Ͳ21070Ͳ00 909258948 Kuparuk River Multi Finger Caliper Field & Processed 9ͲAprͲ24 0 183GͲ24 50Ͳ103Ͳ20145Ͳ00 n/a Kuparuk River Plug Setting Record FieldͲFinal 8ͲAprͲ24 0 193JͲ14 50Ͳ029Ͳ21496Ͳ00 909238639 Kuparuk River Leak Detect Log FieldͲFinal 7ͲAprͲ24 0 110 3JͲ14 50Ͳ029Ͳ21496Ͳ00 909238639 Kuparuk River Multi Finger Caliper Field & Processed 6ͲAprͲ24 0 1PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date:T38757T38758T38759T38760T38761T38762T38762T38763T38764T3876450Ͳ029Ͳ21151Ͳ02 909270379KuparukRiverPerforationRecordFieldͲFinal11ͲAprͲ240142BͲ03B
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: Replace Tubing
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?
Will planned perforations require a spacing exception? Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Plugs (MD): Junk (MD):
8350' None
Casing Collapse
Conductor
Surface
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
15. Well Status after proposed work:
OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
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
None
8363'
3-1/2""
None
8350'2172'
3-1/2"
6255'
7"
16"
9-5/8"
75'
3127'
Perforation Depth MD (ft):
MD
110'
2748'
110'
3161'
6286'8395'
Length Size
Proposed Pools:
TVD Burst
PRESENT WELL CONDITION SUMMARY
6103' 8350 6103' None
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025655, ADL0025656
223-080
P.O. Box 100360, Anchorage, AK 99510 50-029-21151-02-00
ConocoPhillips Alaska, Inc.
KRU 2B-03B
Kuparuk River OilKuparuk Oil PoolKuparuk River Field
N/A
Tubing Grade: Tubing MD (ft):
Packer: 7141'MD/5475'TVD
Perforation Depth TVD (ft): Tubing Size:
L-80 7197'
Packer: Baker ZXP
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
Dusty Ward
dusty.ward@conocophillips.com
(907) 265-6531
Wells Engineer
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
MPSP (psi):
3043
14. Estimated Date for Commencing Operations: ~3/26/2024
or as soon as approval is granted.
By Grace Christianson at 9:11 am, Mar 13, 2024
Perforate
SFD 3/19/2024
Obsolete form. SFD
DSR-3/14/24
X
VTL 4/2/2024
10-404
JLC 4/2/2024
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
March 12, 2024
Commissioner
State of Alaska
Alaska Oil & Gas Conservation
Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
Dusty K Ward
Staff Wells Engineer
CPAI Drilling and Wells
ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to perforate KUP Producer 2B-03B
(PTD# 223-080).
Well 2B-03B was recently rotary sidetracked from 2B-03A. After post-rig logging of CBL (attached) and checking
formation depths with gamma ray for the new cemented 3.5" liner, perforation depths were confirmed.
If you have any questions or require any further information, please contact me at +1503-476-2519.
The plan is to perforate 2B-03B in the A4 and A5 Kuparuk sands. Post-rig CBL of the cemented 3.5" liner confirms
adequate TOC of the 3.5" liner.
2B-03B Perforating Procedure
Kuparuk Producer
PTD #223-080
Page 1 of 1
Well Work
1. RU eline.
a. RIH to desired depths ~ 8095 MD (5962 TVDSS) to ~8136 MD (5990 TVDSS) and perforate A4.
MD to N7ES.
b. POOH. LD BHA.
c. RIH to desired depths ~ 8069 MD (5945 TVDSS) to ~8080 MD (5952 TVDSS) and perforate A5.
MD to N7ES.
d. RD eline.
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB 7,705.0 2B-03B 2/19/2024 rogerba
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Added RWO date 2B-03B 2/22/2024 fergusp
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 35.0 110.0 110.0 55.00 H-90 WELDED
SURFACE 9 5/8 8.92 34.1 3,161.3 2,751.2 36.00 J-55 BUTT
PRODUCTION 7 6.28 32.0 8,395.2 6,100.8 26.00 J-55 BTC
Liner - Lower
completion work over
2024
3 1/2 2.99 7,141.0 8,350.0 6,103.0 9.20 L-80 Hyd 563
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
32.0
Set Depth
7,196.7
String Max No
3 1/2
Set Depth
5,514.1
Tubing Description
Tubing Completion Upper
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE 8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
32.0 32.0 0.04 Hanger 6.997 3.5" tubing hanger w/pup Camero
n/Vault
S-218 6"
x 3-1/2"
EUE
8RD
4.500
3,195.3 2,774.8 46.13 Mandrel GAS
LIFT
4.757 3.5" x 1.5" MMG DV (Target 3168') MMG
DV
SLB 2.818
6,515.2 5,070.7 48.26 Mandrel GAS
LIFT
4.757 3.5" x 1.5" MMG 110SKI HYD 563
(Target 6500')
MMG
SOV
SLB 2.818
7,153.8 5,486.5 49.84 Seal Assembly 3.500 3.5" 80-40 Seal Assembly (space
out 2')
HES HES 2.984
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
3,195.3 2,774.8 46.13 1 GAS LIFT GLV RK 1 1/2 1,260.0 2/19/2024 SLB MMG 0.188
6,515.2 5,070.7 48.26 2 GAS LIFT OV RK 1 1/2 2/19/2024 SLB MMG 0.250
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
7,141.0 5,478.2 49.78 Packer 5.980 4.15 4.170
7,208.2 5,521.5 50.08 Nipple - X 4.300 2.80 2.813
8,250.6 6,112.7 94.47 Collar - Landing 4.290 2.86 2.860
2B-03B, 2/23/2024 9:54:45 AM
Vertical schematic (actual)
PRODUCTION; 32.0-8,395.2
Liner - Lower completion work
over 2024; 7,141.0-8,350.0
Production String 1 Cement;
7,141.0 ftKB
Seal Assembly; 7,153.8
Mandrel GAS LIFT; 6,515.2
Mandrel GAS LIFT; 3,195.3
SURFACE; 34.1-3,161.3
CONDUCTOR; 35.0-110.0
Hanger; 32.0
KUP PROD
KB-Grd (ft)
28.00
RR Date
8/15/1984
Other Elev
2B-03B
...
TD
Act Btm (ftKB)
8,350.0
Well Attributes
Field Name
KUPARUK RIVER UNIT
Wellbore API/UWI
500292115102
Wellbore Status
PROD
Max Angle & MD
Incl (°)
96.12
MD (ftKB)
8,299.11
WELLNAME WELLBORE2B-03B
Annotation
Last Workover:
End Date
2/10/2024
H2S (ppm)
90
Date
12/3/2016
Comment
T + 1 337.856-7201
1058 Baker Hughes Drive
Broussard, LA 70518, USA
Feb 21, 2024
AOGCC
Attention: Kayla Junke
333 W. 7th Ave., Suite 100
Anchorage, Alaska 99501-3539
Subject:Final Log Distribution for ConocoPhillips Alaska, Inc.
KRU 2B-03B
Kuparuk River
API #: 50-029-21151-02-00
Permit No: 223-080
Rig: Nabors 7ES
The final Coil deliverables were uploaded via https://copsftp.sharefile.com/ for the above well.
Items delivered: Digital Las Data, Graphic Images CGM/PDF and Survey Files.
Thank you.
Signature of receiver & date received:
Please return transmittal letter to:
Jenny Jones
Jenny.E.Jones@conocophillips.com
Luis G Arismendi
Luis.arismendi@bakerhughes.com
PTD: 223-080
T38522
2/22/2023
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.02.22
09:24:07 -09'00'
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
'XVW\:DUG
'ULOOLQJ EngineeU
Conoco Phillips Alaska, Inc.
700 G Street
Anchorage, AK, 99501
Re: Kuparuk River Field, Kuparuk Oil Pool, KRU 2B-03B
Conoco Phillips Alaska, Inc.
Permit to Drill Number: 223-080
Surface Location: 689' FSL, 249' FEL, Sec 19, T11N, R9E, UM
Bottomhole Location: 4143' FNL, 857' FEL, SEC 30, T11N, R9E, UM
Dear Mr.:DUG:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCCreserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCCspecifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCCorder, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of November 2023.
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.11.27 15:29:34 -09'00'
27
1c. Specify if well is proposed for:Service - DispService - WAG1b. Proposed Well Class: Exploratory - Gas1a. Type of Work:
Coalbed Gas Gas HydratesSingle ZoneService - WinjDevelopment - OilStratigraphic TestLateralDrill
Geothermal Shale GasMultiple ZoneService - SupplyDevelopment - GasExploratory - OilReentryRedrill
11. Well Name and Number:Single WellBlanket5. Bond:2. Operator Name:
Bond No.
12. Field/Pool(s):6. Proposed Depth:3. Address:
MD: 8350'TVD:6257'
7. Property Designation:4a. Location of Well (Governmental Section):
Surface:
13. Approximate Spud Date:Top of Productive Horizon:
10/21/2023
Total Depth: 9. Acres in Property:
2560
126'10. KB Elevation above MSL (ft):4b. Location of Well (State Base Plane Coordinates - NAD 27):
Surface: x- 508396 y- 88'5954835 Zone-4
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)feet16. Deviated wells:
Downhole: Surface:degrees
TVDMDTVDMDLengthCouplingGradeWeightCasingHole
110'110'SurfaceSurfaceWeldH-905516"24"
J-55369-5/8"12.25"BUTT 2751'3161'SurfaceSurface
8395'SurfaceSurfaceBTC MODJ-55267"8.5"
SurfaceSurfaceEUE 8rdL-809.33-1/2"
5516'7200'HYD563L-809.33-1/2"6-1/8"
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
None
TVD
110'
2751'
6034'
6119'
NoYesHydraulic Fracture planned?
Shallow Hazard AnalysisTime v. Depth PlotDrilling ProgramBOP SketchProperty Plat20. Attachments:
20 AAC 25.050 requirementsDrilling Fluid ProgramSeabed ReportDiverter Sketch
Contact Name: Dusty Ward
Dusty Ward Contact Email:dusty.ward@conocophillips.com
Drilling Engineer Contact Phone:907-503-476-2519
Date:
Permit ApprovalAPI Number:Permit to Drill
Date:Number:
If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:Conditions of approval :
NoMud log req'd: YesSamples req'd: Yes No
H2 NoDirectional svy req'd: YesS measures: Yes No
Spacing exception req'd: Yes No NoInclination-only svy req'd: Yes
NoPost initial injection MIT req'd: Yes
APPROVED BY
Date:THE COMMISSIONCOMMISSIONERApproved by:
Sr Res EngSr Pet GeoSr Pet EngComm.Comm.
110'
3161'800 SX cold set III, 500 SX cold set9-5/8"
II
Effect. Depth TVD (ft):Effect. Depth MD (ft):
MD
Plugs (measured):
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
3127'
233 sx Cold Set II16"75'Conductor/Structural
10165'6119'
LengthCasing
None
Cement VolumeSize
Authorized Title:
Authorized Signature:
2-3/8"
8395'
25 sx Class G
Tubing
Liner
8363'
7975'
2172'
Production
Authorized Name:
7939-7958'
Slotted Liner: 8409'-10165'
(including stage data)
6088'8100'
137 sx of 15.8ppg Class G
Top - Setting Depth - Bottom18. Casing Program:Specifications
3645psi
Cement Quantity, c.f. or sacks
Total Depth TVD (ft):Total Depth MD (ft):
5952180
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
3043psi
3912' FNL, 1003'FEL, SEC 30, T11N, R9E, UM
4143'FNL, 857'FEL, SEC 30, T11N, R9E, UM
P.O. Box 100360 Anchorage, AK 99510
ConocoPhillips Alaska, Inc.
ADL 0025586, ADL0025655689' FSL, 249' FWL, Sec 19, T11N, R9E, UM
KRU 2B-03B
Kuparuk River Field/ Kuparuk River Oil
Pool
5990-6002'
Slotted Liner: 6101'-6119'
Commission Use Only
See cover letter for other
requirements.
350 SX Class G, 250 sx cold set I
8007'3-1/2"
7"
10165'
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
Kickoff depth: 7250'
Maximum Hole Angle:58.39 @ 7500'
8. DNR Approval Number:
81-172
14. Distance to Nearest Property:
27,100'
15. Distance to Nearest Well Open
to Same Pool:1800'
72 500'516'
6257'8350'
6280'
6280''
75'
3127'
7168'
1150
8363'
By Grace Christianson at 12:32 pm, Sep 01, 2023
223-080
VTL 11/27/2023
ADL0025656 SFD
FEL SFD
DSR-9/1/23
50-029-21151-02-00
BOP test to 3500 psig
Annular preventer test to 2500 psig
SFD 9/21/2023
X
*&:JLC 11/27/2023
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.11.27 15:29:54 -09'00'
11/27/23
11/27/23
ConocoPhillips Alaska, Inc.
Post Office Box 100360
Anchorage, Alaska 99510-0360
Telephone 907-276-1215
August 24, 2023
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Application for Permit to Drill 2B-03B
Dear Sir or Madam:
ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore, slot recovery to reacquire the Kuparuk formation,
sidetracking out of the existing 2B-03A well, from the existing 2B pad in Kuparuk. The intended spud date for this well is
10/21/2023. It is intended that Nabors 7ES be used to drill the well.
2B-03B will sidetrack out of the existing 7” intermediate casing in the 2B-03A wellbore. A 6-1/8” hole will be drilled to the
planned TD, and a 3-1/2” liner will be run and cemented back into the 7” casing, with the top planned approximately 885’MD
or ~555’ TVD above the top of the Kuparuk resevoir.
The well will be completed as a fracture stimulated Producer with a single stage frac job planned in the A Sand, Kuparuk
formation. A frac sundry will follow this PTD.
Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information
attached to this application includes the following:
1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a)
2.A proposed drilling program
3. A proposed completion diagram
4.A drilling fluids program summary
5.Pressure information as required by 20 ACC 25.035 (d)(2)
6. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b)
Information pertinent to the application that is presently on file at the AOGCC:
1. Diagrams of the BOP equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b).
2. A description of the drilling fluids handling system.
3.Diagram of riser set up.
If you have any questions or require further information, please contact Dusty Ward at 503-476-2519
(dusty.ward@conocophillips.com) or Jonathan Coberly at 265-1013.
Sincerely,
Dusty Ward
Drilling Engineer
a single stage frac job planned in the A Sand, Kuparuk
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 1 of 7
Printed: 30-Aug-23
2B-03B
Application for Permit to Drill Document
Table of Contents
1.Well Name (Requirements of 20 AAC 25.005 (f)) ........................................................... 2
2.Location Summary (Requirements of 20 AAC 25.005(c)(2)) ......................................... 2
3.Proposed Drilling Program ...................................................................................... 3
4.Diverter and Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(7)) ......... 4
5.MASP Calculations (Requirements of 20 AAC 25.005(c)(4)) ............................................... 4
6.Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5))5
7.Casing and Cementing Program ..................................................................................... 5
8.Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8))........................................... 5
9.Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) ...... 6
10. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) ................................................ 6
11. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) ................................. 6
12. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) .......................................... 6
13.Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC
25.005 (c)(14)) .............................................................................................................. 6
14. Drilling Hazards Summary ............................................................................................. 6
15. Proposed Completion Schematic ........................................................................... 8
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 2 of 7
Printed: 30-Aug-23
1.Well Name (Requirements of 20 AAC 25.005 (f))
The well for which this application is submitted will be designated as 2B-03B.
2.Location Summary (Requirements of 20 AAC 25.005(c)(2))
Location at Surface 689‘ FSL, 249‘ FWL, SEC 19, T11N, R9E, UM
NAD 1927
Northings: 5954835
Eastings: 508396
RKB Elevation 126’ AMSL
Pad Elevation 88’ AMSL
Location at Sidetrack KOP 3374‘ FNL, 1123‘ FEL, SEC 30, T11N, R9E, UM
NAD 1927
Northings: 5950772
Eastings: 507541
Measured Depth, RKB:7250’
Total Vertical Depth, RKB:5548’
Total Vertical Depth, SS:5422’
Top of Productive Horizon 3912‘ FNL, 1003‘ FEL, SEC 30, T11N, R9E, UM
NAD 1927
Northings: 5950234
Eastings: 507663
Measured Depth, RKB:7967’
Total Vertical Depth, RKB:5988’
Total Vertical Depth, SS:5862’
Total Depth 4143‘ FNL, 857‘ FEL, SEC 30, T11N, R9E, UM
NAD 1927
Northings: 5950004
Eastings: 507810
Measured Depth, RKB:8350’
Total Vertical Depth, RKB:6257’
Total Vertical Depth, SS:6131’
FEL SFD
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 3 of 7
Printed: 30-Aug-23
3. Proposed Drilling Program
The proposed drilling program is listed below. Please refer to Completion Schematic in section 15.
Remaining Pre-Rig Work
1. Finish suspend of well. (Separate sundry 323-310)
2. Dummy off GLMs.
3. Perform tubing cut at ~7260’ RKB.
a. Punch tubing above tubing cut as needed.
Rig Work
MIRU
1. MIRU Nabors 7ES on 2B-03A. (No BPV will be installed for MIRU due to internal risk assessment on N7ES.)
2. Circulate well over to seawater.
3. Record shut-in pressures on the T & IA. If there is pressure, bleed off IA and/or tubing pressure and complete 30-
minute NFT. Verify well is dead. Circulate KWF as needed.
4. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/3,500 psi. Test annular 250/3,500 psi.
Retrieve Tubing, Grow PC, Set whipstock
5. Pull BPV, MU landing joint and BOLDS.
6. Pull 3-1/2” tubing down to pre-rig cut.
a. Grow and stretch of 7” production casing if experience any drift issues: set plug/ storm packer near surface,
pressure test plug. ND to casing head and let grow, pull 7” casing and re-land slips and PO, nipple up new
tubing spool and BOP’s, test flange break and IC packoffs.
b. Continue to lay down tubing.
7. Set Whipstock at 7250’ TOWS oriented high side.
8. Mill window in 7” casing.
9. Drill 6-1/8” hole to TD.
10. Circulate hole clean and pull out of hole with drilling BHA.
11. Run 3.5” liner TD.
12. Cement liner, bringing cement above liner top. Set liner top hanger/packer and circulate cement out of hole from
above top of liner.
13. Perform pressure test on 7” casing / 3-1/2” liner to 2000 psi (to ensure no casing integrity issues were caused during
drilling/liner running).
a. If pressure test does not pass, run 5-1/2” tie-back string and re-test.
14. Run 3.5” gas lift upper completion
15. Pressure test hanger seals to 5,000 psi.
16. Test tubing to 3000 psi, chart test.
17. Test IA to 2500 psi, chart test. Drop tubing pressure and shear SOV.
18. Install BPV and test to 1000 psi in the direction of flow.
19. Nipple down BOP.
20. Install tubing head adapter assembly. N/U tree and test to 5000 psi/10 minutes.
21. Freeze protect down annulus through SOV, RU TxIA cross, let u-tube.
22. Secure well. RDMO.
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 4 of 7
Printed: 30-Aug-23
4.Diverter and Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(7))
Please reference BOP schematics on file for Nabors 7ES. As this well is a sidetrack below the surface casing, no
diverter will be used.
5.MASP Calculations (Requirements of 20 AAC 25.005(c)(4))
The following presents data used for calculation of anticipated surface pressure (ASP) during drilling of this well:
Casing Size
(in)
Casing/Window Depth
MD/TVD(ft)
Fracture
Gradient (ppg)
Pore pressure
(psi)
ASP Drilling
(psi)
7 7250 / 5548 15.8 2444 1889
3.5 7967 / 5988 15.2 2771 2172
PROCEDURE FOR CALCULATING ANTICPATED SURFACE PRESSURE (ASP)
ASP is determined as the lesser of 1) surface pressure at breakdown of the formation casing seat with a gas
gradient to the surface, or 2) formation pore pressure at the next casing point less a gas gradient to the surface as
follows:
1) ASP = [(FG x 0.052) - 0.1]*D
Where: ASP = Anticipated Surface pressure in psi
FG = Fracture gradient at the casing seat in lb/gal
0.052 = Conversion from lb./gal to psi/ft
0.1 = Gas gradient in psi/ft
D = true Vertical depth of casing seat in ft RKB
OR
2) ASP = FPP – (0.1 x D)
Where: FPP = Formation Pore Pressure at the next casing point
1. ASP CALCULATIONS
Drilling 6-1/8” hole out of 7” intermediate casing
ASP = [(FG x 0.052) – 0.1] D
= [(15.8 x 0.052) – 0.1] x 5548’ = 4003 psi
OR
ASP = FPP – (0.1 x D)
= 2444 – (0.1 x 5548') = 1889 psi
Drilling 6-1/8” hole at top of Kuparuk Reservoir
ASP = [(FG x 0.052) – 0.1] D
= [(15.2 x 0.052) – 0.1] x 5988 = 4134 psi
OR
ASP = FPP – (0.1 x D)
= 2771 – (0.1 x 5988) = 2172 psi
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 5 of 7
Printed: 30-Aug-23
(B) data on potential gas zones;
The well bore is not expected to penetrate any gas zones.
(C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation
zones, and zones that have a propensity for differential sticking;
Please see Drilling Hazards Summary
6. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5))
A FIT to 12.5 EMW at the Surface casing shoe (3161’ RKB/ 2751’ TVD) was performed on original drill on
8/10/1984. Additionally, the CBL of 7” from 9/19/1984 shows estimated TOC near 6734’ RKB, which is above
planned KOP. No FIT/LOT is planned as part of this sidetrack.
7. Casing and Cementing Program
Casing and Cementing Program
Csg/Tbg
OD (in)
Hole Size
(in)
Weight
(lb/ft) Grade Conn. Cement Program
3.5 6.125 9.3 L-80 Hyd563 Cemented liner – 5.5” OD Centralizers planned
Cementing Calculations
3-1/2” production liner run to 8350’ MD / 6257’ TVD
Top of slurry is designed to be at ~7200’ MD, the top of the 3-1/2” liner, which is 767’ MD / 472’ TVD above the
top of the Kuparuk interval. Assume 20% excess annular volume.
Tail slurry from 8350’ MD to 7200’ MD with a 14.0 ppg to 15.8 ppg range Class G + Add's
Total Volume = 159ft3 =>
137 sx of 15.8 ppg Class G + Add's @ 1.16 ft3/sk
95 sx of 14.0 ppg Class G + Add's @ 1.68 ft3/sk
8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8))
Production
Hole Size in. 6.125
Casing Size in. 3.5
Density PPG 11.0-12.5
PV cP 10
YP lb./100 ft2 10 - 15
Funnel Viscosity s/qt. 40 - 50
Initial Gels lb./100 ft2 6
10 Minute Gels lb./100 ft2 8
API Fluid Loss cc/30 min. 4.0
HPHT Fluid Loss cc/30 min. 10.0
pH 9.0 – 9.5
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 6 of 7
Printed: 30-Aug-23
The interval will be drilled with a water-based mud (LSND) weighted to 11.0-12.5 ppg. Fluid hydraulic modeling
has been performed.
Diagram of Nabors 7ES Mud System on file.
Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033.
9.Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9))
N/A – No abnormally pressured formations expected
10.Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10))
N/A – No seismic to be performed, drilling in well developed area.
11.Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11))
N/A - Application is not for an offshore well.
12.Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12))
Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission.
13.Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005
(c)(14))
Incidental fluids developed from drilling operations on well 2B-03B will be injected into a permitted annulus on 1B
pad.
14.Drilling Hazards Summary
(To be posted in Rig Floor Doghouse Prior to Spud)
6.125” Hole / 3.5” Liner - Slant Production Hole
Event Risk Level Mitigation Strategy
Lost circulation high Reduce pump rates, reduce trip speeds, real time ECD
monitoring, mud rheology, add lost circulation material
Hole swabbing on trips Low Reduce trip speeds, condition mud properties, proper
hole filling, pump out of hole, real time ECD monitoring
Abnormal Reservoir Pressure Low Well control drills, check for flow during connections,
increased mud weight
Differential Sticking Low Keep pipe moving, control mud weight
Hydrogen Sulfide gas Low H2S drills, detection systems, alarms, standard well
control practices, mud scavengers
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 7 of 7
Printed: 30-Aug-23
Well Proximity Risks:
No collision risks exist in the planned 2B-03B wellbore. Directional drilling / collision avoidance information as
required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments.
Drilling Area Risks:
Lost returns are possible if weaker than expected formations or stringers are encountered. LCM material will be
available to seal in losses if needed.
Good drilling practices will be stressed to minimize the potential of taking swabbed kicks.
Application for Permit to Drill, 2B-03B
Saved: 30-Aug-23
2B-03B
Page 8 of 7
Printed: 30-Aug-23
15. Proposed Completion Schematic
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NADCONVERSION
------------------------------------------------------------------------------------------------------------------------------------------
DESIGN (Da | WELL : 2B-03, 2B-03B RST Project
RIG | SITE
DEPTH DAT | FIELD : Kuparuk River Unit_2
------------------------------------------------------------------------------------------------------------------------------------------
CO-ORDINA | SURFACE LOCATION
SYSTEM (SS | VERTICAL SECTION : 186.92
SECTION (V | MAGNETIC MODEL (D
GEODETIC | MAG DEC | DIP | STRENGTH : 14.57 | 80.60 | 57243.2
SURVEY CA | GRID CONVERGENCE : 0.06 East
------------------------------------------------------------------------------------------------------------------------------------------
SURVEY PROGRAM
H 200.00 - 7200.00 2B-03 : GCT-MS
H 7200.00 - 8350.00 2B-03B EAST WP01 : GCT-MS
------------------------------------------------------------------------------------------------------------------------------------------
MD INC AZI TVD SSTVD ASPY/MAP ASPX/MAP VSAH
usft deg deg usft
126 0 0 126 0 5954835 508395.8 0
127 0 290.62 127 1 5954835 508395.8 0
200 0.28 290.62 200 74 5954836 508395.6 0.18
300 0.22 305.22 300 174 5954836 508395.2 0.61
400 0.12 316.29 400 274 5954836 508395 0.91
500 0.15 296.94 500 374 5954836 508394.8 1.15
600 0.13 302.52 600 474 5954836 508394.6 1.39
700 0.12 271.11 700 574 5954836 508394.4 1.61
800 1.28 196.32 799.99 673.99 5954835 508394 2.83
900 3.05 192.67 899.91 773.91 5954832 508393.1 6.61
1000 5.08 190.62 999.66 873.66 5954825 508391.7 13.7
1100 7.32 191.26 1099.07 973.07 5954814 508389.6 24.5
1200 11.87 195.67 1197.64 1071.64 5954798 508385.6 41.16
1300 15.78 195.07 1294.73 1168.73 5954775 508379.3 65.05
1400 18.97 197.52 1390.15 1264.15 5954746 508370.9 94.91
1500 21.73 196.06 1483.9 1357.9 5954713 508360.9 129.68
1600 25.05 190.99 1575.68 1449.68 5954674 508351.7 169.38
1700 28.77 189.76 1664.84 1538.84 5954630 508343.6 214.63
1800 30.83 195.71 1751.63 1625.63 5954581 508332.6 264.32
1900 34.3 198.76 1835.9 1709.9 5954530 508316.6 318.14
2000 37.42 195.96 1916.94 1790.94 5954474 508299.1 376.71
2100 41.3 195.42 1994.24 1868.24 5954413 508282 440.12
2200 43.23 195.32 2068.24 1942.24 5954348 508264.2 507.37
2300 43.62 195.52 2140.87 2014.87 5954282 508245.9 576.11
2400 43.98 195.84 2213.05 2087.05 5954215 508227.2 645.33
2500 44.15 195.87 2284.9 2158.9 5954148 508208.2 714.87
2600 44.35 195.86 2356.53 2230.53 5954081 508189.1 784.65
2700 44.73 195.84 2427.81 2301.81 5954014 508170 854.79
2800 45.22 196.27 2498.55 2372.55 5953946 508150.4 925.47
2900 45.5 196.31 2568.82 2442.82 5953878 508130.5 996.63
3000 45.68 196.31 2638.79 2512.79 5953809 508110.4 1068.06
3100 45.83 196.26 2708.57 2582.57 5953740 508090.3 1139.7
3161 46.03 196.06 2751 2625 5953698 508078.1 1183.52
3200 46.15 195.94 2778.05 2652.05 5953671 508070.4 1211.62
3300 47.98 195.92 2846.16 2720.16 5953601 508050.3 1284.83
3400 49.45 195.87 2912.14 2786.14 5953529 508029.7 1359.97
3500 49.02 194.66 2977.44 2851.44 5953456 508009.8 1435.71
3600 48.88 193.77 3043.11 2917.11 5953382 507991.3 1511.12
3700 48.02 194.24 3109.43 2983.43 5953310 507973.2 1585.96
3800 46 195.22 3177.62 3051.62 5953239 507954.6 1659.1
3900 43.9 194.59 3248.39 3122.39 5953171 507936.4 1729.75
4000 43.25 193.51 3320.84 3194.84 5953104 507919.7 1798.68
4100 43.93 191.36 3393.27 3267.27 5953037 507904.8 1867.63
4200 43.73 191.02 3465.41 3339.41 5952969 507891.4 1936.88
4300 43.93 191.01 3537.55 3411.55 5952901 507878.2 2006.13
4400 43.98 191.16 3609.54 3483.54 5952833 507864.8 2075.54
4500 44.52 190.92 3681.17 3555.17 5952764 507851.5 2145.32
4600 44.37 190.91 3752.56 3626.56 5952695 507838.2 2215.34
4700 44.33 190.92 3824.07 3698.07 5952627 507825 2285.25
4800 45.02 189.57 3895.18 3769.18 5952558 507812.5 2355.55
4900 45.03 189.16 3965.86 3839.86 5952488 507801 2426.3
5000 44.78 189.14 4036.69 3910.69 5952418 507789.8 2496.89
5100 46.05 187.99 4106.88 3980.88 5952348 507779.2 2568.11
5200 46.25 187.22 4176.16 4050.16 5952276 507769.6 2640.22
5300 45.85 187.21 4245.56 4119.56 5952205 507760.6 2712.22
5400 46.7 186.82 4314.68 4188.68 5952133 507751.8 2784.48
5500 47 186.29 4383.07 4257.07 5952061 507743.4 2857.44
5600 46.67 186.44 4451.48 4325.48 5951988 507735.3 2930.38
5700 47.08 186.82 4519.84 4393.84 5951916 507726.9 3003.37
5800 48.12 187.39 4587.27 4461.27 5951842 507717.8 3077.21
5900 47.97 187.39 4654.13 4528.13 5951769 507708.2 3151.58
6000 47.53 187.52 4721.36 4595.36 5951695 507698.6 3225.6
6100 47.4 187.57 4788.97 4662.97 5951622 507688.9 3299.29
6200 46.5 189.46 4857.23 4731.23 5951550 507678.1 3372.36
6300 46.67 189.91 4925.96 4799.96 5951478 507665.9 3445
6400 47.9 190.49 4993.8 4867.8 5951406 507652.9 3518.47
6500 48.2 190.46 5060.65 4934.65 5951333 507639.4 3592.85
6600 48.62 190.44 5127.02 5001.02 5951259 507625.8 3667.64
6700 49.07 190.26 5192.83 5066.83 5951185 507612.3 3742.93
6800 49.53 190.06 5258.04 5132.04 5951111 507598.9 3818.74
6900 49.82 189.89 5322.76 5196.76 5951036 507585.7 3894.98
7000 50.02 189.87 5387.14 5261.14 5950960 507572.6 3971.5
7100 49.57 189.62 5451.69 5325.69 5950885 507559.7 4047.87
7200 50.07 189.54 5516.21 5390.21 5950810 507547 4124.27
7250 50.07 189.54 5548.31 5422.31 5950772 507540.6 4162.61
7275 51.75 185.95 5564.07 5438.07 5950753 507538 4182.02
7286 52.52 184.43 5570.82 5444.82 5950744 507537.2 4190.7
7300 52.88 183.67 5579.31 5453.31 5950733 507536.4 4201.84
7400 55.53 178.44 5637.82 5511.82 5950652 507535 4282.94
7500 58.39 173.55 5692.37 5566.37 5950568 507540.9 4366.76
7550 56.49 170.79 5719.28 5593.28 5950527 507546.6 4408.89
7600 54.65 167.91 5747.55 5621.55 5950486 507554.2 4450.13
7650 52.89 164.9 5777.1 5651.1 5950447 507563.7 4490.47
7700 51.21 161.76 5807.86 5681.86 5950409 507575 4529.89
7750 49.61 158.46 5839.73 5713.73 5950373 507588.1 4568.42
7800 48.11 155.01 5872.63 5746.63 5950338 507603 4606.07
7850 46.72 151.39 5906.47 5780.47 5950305 507619.5 4642.89
7900 45.45 147.62 5941.15 5815.15 5950274 507637.8 4678.91
8000 45.45 147.62 6011.3 5885.3 5950214 507676 4750.17
8092.23 45.45 147.62 6076 5950 5950159 507711.1 4815.9
8100 45.45 147.62 6081.45 5955.45 5950154 507714.1 4821.44
8200 45.45 147.62 6151.6 6025.6 5950094 507752.3 4892.71
8300 45.45 147.62 6221.75 6095.75 5950034 507790.4 4963.97
8350 45.45 147.62 6256.83 6130.83 5950004 507809.5 4999.6
---------------------
: Kuparuk 2B Pad
---------------------
: 5954835.49 , 508395.79 , -0.00
2 deg (Slot 0.00 usft N, 0.00 usft E)
DATE) : BGGM2023 (05-09-2023)
26
---------------------
---------------------
Dogleg Toolface Comments
00
0 290.62 16" Conductor Casing - GCT-MS -1
0.38 290.62
0.09 140.43
0.1 167.3
0.05 -66.58
0.02 148.49
0.07 -113.8
1.25 -80.09
1.77 -6.28
2.03 -5.12
2.24 2.09
4.61 11.36
3.91 -2.39
3.27 14.09
2.81 -11.11
3.88 -33.57
3.76 -9.06
3.6 57.75
3.84 26.61
3.52 -28.87
3.9 -5.25
1.93 -2.03
0.41 19.49
0.42 31.72
0.17 7.01
0.2 -2
0.38 -2.12
0.58 31.96
0.28 5.82
0.18 0
0.15 -13.45
0.39 -35.84 9-5/8" Surface Casing
0.39 -35.7
1.83 -0.47
1.47 -1.48
1.01 -115.53
0.69 -102.07
0.93 157.91
2.14 160.79
2.15 -168.26
0.99 -131.52
1.63 -66.14
0.31 -130.47
0.2 -1.99
0.12 64.4
0.57 -17.32
0.15 -177.33
0.04 170.09
1.17 -54.47
0.29 -88.17
0.25 -176.77
1.51 -33.22
0.59 -70.46
0.4 -178.97
0.9 -18.48
0.49 -52.38
0.35 161.71
0.49 34.21
1.12 22.23
0.15 180
0.45 167.71
0.14 164.19
1.65 123.73
0.37 62.68
1.3 19.31
0.3 -4.26
0.42 -2.05
0.47 -16.82
0.48 -18.31
0.32 -24.14
0.2 -4.38
0.49 -157.09
0.5 -7
00GCT-MS -2
13 -60
13 -57.74
5-60
5-59.54
5-56.48
6-130
6 -128.52
6 -126.89
6 -125.11
6 -123.17
6 -121.07
6-118.8
6 -116.35
00
00
00
00
00
00
1
Davies, Stephen F (OGC)
From:Ward, Dusty K <Dusty.Ward@conocophillips.com>
Sent:Thursday, September 21, 2023 11:12 AM
To:Davies, Stephen F (OGC)
Cc:Dewhurst, Andrew D (OGC); Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL]KRU-2B-03B (PTD 223-080) - Questions
Steve,
ThanksforyourquesƟons.Pleaseseeanswersbelowinorange.
PleaseletmeknowifyouhaveanyotherquesƟonsorfollowup.
AppreciateyourƟmeandreview.
DustyWard|dustyw
SeniorWellsEngineer
Office:907Ͳ265Ͳ6531
Cell:503Ͳ476Ͳ2519
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Tuesday,September19,20232:11PM
To:Ward,DustyK<Dusty.Ward@conocophillips.com>
Cc:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>
Subject:[EXTERNAL]KRUͲ2BͲ03B(PTD223Ͳ080)ͲQuestions
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.
HiDusty,
I’mreviewingthePermittoDrillapplicaƟonforKRUͲ2BͲ03B,andIhavecoupleofquesƟons.
x TheMASPpressuresgivenontheforminBox17don’tagreewiththosepresentedintheMASPcalculaƟons
secƟon.Whicharecorrect?Theoneinbox17iscorrectandisbasedfromlastSBHPinJulyforMPSP.WeSI
injectorsinthearea,soitshouldbefallingsomesincethen,butthisshoulddictateBOPpressuretests.This
shouldconcurmorewiththeMASPcalculaƟons,seemynoteonbullet3below.
x Ontheform,thecementinformaƟonpresentedis137sacksof15.8ppgClassG,butthecementcalculaƟons
secƟonwithintheapplicaƟonlists137sacksof15.8ppgClassG+addiƟvesand95sacksof14ppgClassG+
addiƟves.Whichiscorrect?IdidnotintendthistobeanAND,butratheranOR.Baseplanisthe15.8ppg.But
wemaylightenuptoa14.0ppgforthatjobdependingonwhatweseeforlossesduringdrilling.Iwastryingto
expresstherangewemayuseandgettherangeapproved.
x IntheMASPcalculaƟonssecƟon,theporepressureisgivenas2771psiat5988’TVD,whichisagradientof0.46
psi/Ōorabout8.9ppgEMW.ThedrillingŇuidprogramliststheplannedmuddensityas11.0to12.5ppg.Why
isthechosenweightsohigh?Holestabilityissues?InoƟcethatthelostcirculaƟonriskisalsolistedashighin
theDrillingHazardsSummary.WillLCMbestockpiledandavailableonsite?ImadeawrongassumpƟonusing
ourgeomodel.IassumeditincludedmostrecentSBHPforreservoircalcs,butthemodelIuseddidn’t.Ididn’t
crossͲreferencemodelatKuparukReservoirtolastSBHPanditesƟmatedporepressurediīerentlyinthemodel
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.
2
Iused,whereasmeasureddatashouldtrumpthemodelinthiscase.Therefore,assumingworstcasetomatch
box17abovenoteabove,updatedMASPatKuparukReservoirthen:
o 3645psi–(0.1x5998)=3045psigforMASPatKuparukreservoir
ForDrilling6Ͳ1/18”holeoutof7”intermediate,I’dstaywithmodelasbestesƟmateoutsideof
7”atwindowasshowninPTDsubmiƩal.
o Theabovehelpsexplainthehighermudweightrangeplanned.Pressureshouldbelesswhenweget
therewithinjectorsoī,butwewillĮndouthowmuchwhiledrilling.Baseplaniscurrentlytoaimforan
11.7Ͳ11.8ppgforthewell.However,thereareshalesaboveusintheHRZthatmaybegintocollapse
around12.1Ͳ12.4ppggradientrangeesƟmated,whichwemayneedtoweightuptoholdback.Onthe
otherhand,ifpressureshavedroppedmorethanexpectedandwestartseeinglosses,andobserve
shalesarestayingadequatelyopen,thenwemayconsidereddroppingweightabittohelpmanage(I
doubtwe’dgetbelow11.0ppgandsƟllholdshalesback,soputthatasboƩomofrange).
o Yes,Ňuidlossmaterialswillbeavailableandwehaveguidelinesastowhattousewhen;dependingon
lossrateandotherholecondiƟonconsideraƟons.Reviewingwiththeteammemberswhohavedrilled
moreKuparuk,itwassuggestedthatwemayhitsomelosszones,butgenerallytheyhealupandare
lowͲvolume.
x TheriskofH2Sislistedas“low”intheDrillingHazardsSummary,buttheH2Svaluesmeasuredduring2022for
otherwellsonthispadrangefrom86to249ppm.WhatH2SmiƟgaƟonmeasuresareplannedforthisdrilling
operaƟon?WehavegasmonitorsontherigandinthepitsandonpersonnelassomeofourcoremiƟgaƟonsto
H2Scurrently.PropercondiƟoninganduseofourŇuidsisalsoakeypieceweaimtoaccomplishwithMISwaco
ourŇuidsvendortoo.Thanks.Goodday.
ThanksandBeWell,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyaƩachments,containsinformaƟonfromtheAlaskaOilandGasConservaƟonCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).ItmaycontainconĮdenƟaland/orprivilegedinformaƟon.Theunauthorizedreview,use
ordisclosureofsuchinformaƟonmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutĮrstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
223-080
KUPARUK RIVER OIL
KRU 2B-03B
KUPARUK RIVER
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g
p
r
o
t
e
c
t
s
a
l
l
k
n
o
w
n
U
S
D
W
s
NA
20
CM
T
v
o
l
a
d
e
q
u
a
t
e
t
o
c
i
r
c
u
l
a
t
e
o
n
c
o
n
d
u
c
t
o
r
&
s
u
r
f
c
s
g
NA
21
CM
T
v
o
l
a
d
e
q
u
a
t
e
t
o
t
i
e
-
i
n
l
o
n
g
s
t
r
i
n
g
t
o
s
u
r
f
c
s
g
Ye
s
22
CM
T
w
i
l
l
c
o
v
e
r
a
l
l
k
n
o
w
n
p
r
o
d
u
c
t
i
v
e
h
o
r
i
z
o
n
s
Ye
s
23
Ca
s
i
n
g
d
e
s
i
g
n
s
a
d
e
q
u
a
t
e
f
o
r
C
,
T
,
B
&
p
e
r
m
a
f
r
o
s
t
Ye
s
24
Ad
e
q
u
a
t
e
t
a
n
k
a
g
e
o
r
r
e
s
e
r
v
e
p
i
t
Ye
s
PT
D
2
0
3
-
0
0
9
,
S
u
n
d
r
y
3
2
3
-
3
1
0
25
If
a
r
e
-
d
r
i
l
l
,
h
a
s
a
1
0
-
4
0
3
f
o
r
a
b
a
n
d
o
n
m
e
n
t
b
e
e
n
a
p
p
r
o
v
e
d
Ye
s
26
Ad
e
q
u
a
t
e
w
e
l
l
b
o
r
e
s
e
p
a
r
a
t
i
o
n
p
r
o
p
o
s
e
d
NA
27
If
d
i
v
e
r
t
e
r
r
e
q
u
i
r
e
d
,
d
o
e
s
i
t
m
e
e
t
r
e
g
u
l
a
t
i
o
n
s
Ye
s
Ma
x
r
e
s
e
r
v
o
i
r
p
r
e
s
s
u
r
e
i
s
3
6
4
5
p
s
i
g
(
9
.
6
p
p
g
E
M
W
)
;
w
i
l
l
d
r
i
l
l
w
/
1
1
.
0
-
1
2
.
5
p
p
g
E
M
W
28
Dr
i
l
l
i
n
g
f
l
u
i
d
p
r
o
g
r
a
m
s
c
h
e
m
a
t
i
c
&
e
q
u
i
p
l
i
s
t
a
d
e
q
u
a
t
e
Ye
s
29
BO
P
E
s
,
d
o
t
h
e
y
m
e
e
t
r
e
g
u
l
a
t
i
o
n
Ye
s
MP
S
P
i
s
3
0
4
3
p
s
i
g
;
w
i
l
l
t
e
s
t
B
O
P
s
t
o
3
5
0
0
p
s
i
g
30
BO
P
E
p
r
e
s
s
r
a
t
i
n
g
a
p
p
r
o
p
r
i
a
t
e
;
t
e
s
t
t
o
(
p
u
t
p
s
i
g
i
n
c
o
m
m
e
n
t
s
)
Ye
s
31
Ch
o
k
e
m
a
n
i
f
o
l
d
c
o
m
p
l
i
e
s
w
/
A
P
I
R
P
-
5
3
(
M
a
y
8
4
)
Ye
s
32
Wo
r
k
w
i
l
l
o
c
c
u
r
w
i
t
h
o
u
t
o
p
e
r
a
t
i
o
n
s
h
u
t
d
o
w
n
Ye
s
33
Is
p
r
e
s
e
n
c
e
o
f
H
2
S
g
a
s
p
r
o
b
a
b
l
e
NA
34
Me
c
h
a
n
i
c
a
l
c
o
n
d
i
t
i
o
n
o
f
w
e
l
l
s
w
i
t
h
i
n
A
O
R
v
e
r
i
f
i
e
d
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
No
H2
S
m
e
a
s
u
r
e
s
r
e
q
u
i
r
e
d
.
W
e
l
l
s
o
n
2
B
-
P
a
d
a
r
e
H
2
S
-
b
e
a
r
i
n
g
.
R
i
g
h
a
s
s
e
n
s
o
r
s
a
n
d
a
l
a
r
m
s
.
35
Pe
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
i
d
e
m
e
a
s
u
r
e
s
Ye
s
An
t
i
c
i
p
a
t
e
d
p
r
e
s
s
u
r
e
i
s
1
1
.
2
p
p
g
E
W
M
.
P
l
a
n
n
e
d
m
u
d
p
r
o
g
r
a
m
s
p
e
c
i
f
i
e
d
1
1
.
0
t
o
1
2
.
5
.
A
c
t
u
a
l
36
Da
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
e
s
s
u
r
e
z
o
n
e
s
NA
we
i
g
h
t
d
e
p
e
n
d
s
o
n
p
r
e
s
s
u
r
e
s
e
n
c
o
u
n
t
e
r
e
d
d
u
e
t
o
o
f
f
s
e
t
i
n
j
e
c
t
i
o
n
.
H
o
l
e
i
n
s
t
a
b
i
l
i
t
y
a
n
d
37
Se
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
lo
s
t
c
i
r
c
u
l
a
t
i
o
n
a
r
e
p
o
s
s
i
b
l
e
c
o
m
p
l
i
c
a
t
i
o
n
s
.
L
C
M
w
i
l
l
b
e
a
v
a
i
l
a
b
l
e
.
38
Se
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
Co
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
SF
D
Da
t
e
9/
2
1
/
2
0
2
3
Ap
p
r
VT
L
Da
t
e
11
/
2
7
/
2
0
2
3
Ap
p
r
SF
D
Da
t
e
9/
2
1
/
2
0
2
3
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
i
n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
*&:
JL
C
1
1
/
2
7
/
2
0
2
3
