Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
Loading...
HomeMy WebLinkAbout224-066Originated: Delivered to:5-Nov-25Alaska Oil & Gas Conservation Commiss05Nov25-NR
! "# $$%$ !&$$'($)*%+
($)*%,- .WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED3T-730 50-103-20907-00-00 225-010 Kuparuk River WL TTiX-IPROF FINAL FIELD 6-Oct-253J-03 50-029-21399-00-00 185-164 Kuparuk River WL PPROF FINAL FIELD 7-Oct-252X-01 50-029-20963-00-00 183-084 Kuparuk River WL IPROF FINAL FIELD 10-Oct-252Z-07 50-029-20946-00-00 183-064 Kuparuk River WL CBP FINAL FIELD 11-Oct-252Z-03 50-029-20964-00-00 183-085 Kuparuk River WL IPROF FINAL FIELD 14-Oct-253R-17 50-029-22242-00-00 192-005 Kuparuk River WL LDL FINAL FIELD 16-Oct-253S-722 50-103-20886-00-00 224-066 Kuparuk River WL TTiX-IPROF FINAL FIELD 20-Oct-252U-06 50-029-21282-00-00 185-019 Kuparuk River WL RBP FINAL FIELD 25-Oct-253T-731 50-103-20905-00-00 224-156 Kuparuk River WL Cutter FINAL FIELD 2-Nov-25Transmittal Receipt//////////////////////////////// 0/////////////////////////////////
+
! 1 Please return via courier or sign/scan and email a copy to Schlumberger. " 2"3 +45
%TRANSMITTAL DATETRANSMITTAL #1
67
8 "
! -
+" 8 # !(3 . 8 ) "3
8 # !9
3 :
8" +8 6 8
8 " 8 # !;" " 3
-
3 " 3 ""+
3 +
< +3!%
T41052T41053T41054T41055T41056T41057T41058T41059T410603S-72250-103-20886-00-00224-066Kuparuk RiverWLTTiX-IPROFFINAL FIELD20-Oct-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.11.05 12:45:23 -09'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, March 18, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Bob Noble
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
ConocoPhillips Alaska, Inc.
3S-722
KUPARUK RIV UNIT 3S-722
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 03/18/2025
3S-722
50-103-20886-00-00
224-066-0
W
SPT
4134
2240660 1500
135 135 135 135
688 710 707 706
INITAL P
Bob Noble
2/2/2025
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:KUPARUK RIV UNIT 3S-722
Inspection Date:
Tubing
OA
Packer Depth
1060 1815 1765 1765IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitRCN250202153833
BBL Pumped:0.8 BBL Returned:0.8
Tuesday, March 18, 2025 Page 1 of 1
9
9
9
99
9
9999
99
9 9
9
9
James B. Regg Digitally signed by James B. Regg
Date: 2025.03.18 09:41:18 -08'00'
224-066: T39789
224-074: T39790
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.11.20 08:09:32 -09'00'
39789224-066: T3
39790224 074 T3
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 18,894 feet feet
true vertical 4,184 feet feet
Effective Depth measured 18,894 feet 8,583 & 8,715 feet
true vertical 4,184 feet 4,133 & 4,163 feet
17,535-17,545
Perforation depth Measured depth 12,615-12,625 feet
4234
True Vertical depth 4193 feet
Tubing (size, grade, measured and true vertical depth) 4.5" L-80 8,720' MD 4,164' TVD
HES TNT Prod Pkr 8,583' MD 4,133' TVD
Packers and SSSV (type, measured and true vertical depth) Baker LTP 8,715' MD 4,163' TVD
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:KRU Undefined 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:
3562 2595
Burst Collapse
2470
4790
7850
5210
6890
10860
measured
TVD
Production
Liner
7914
975
10175
Casing
Structural
3925
4197
4.5"
7914
8889
18890 4184
Plugs
Junk measured
6.106MMlbs 16/20 Wanli LWC prpppant, 84,378 lbs 100M, DHG 2716 psi
Length
130
3562
130Conductor
Surface
Intermediate
20"
10.75"
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL380107, ADL380106
KRU Undefined Pool
ConocoPhillips Alaska, Inc.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
224-066
50-103-20886-00-00
Size
130
7.625"
11590
7.625"
P.O. Box 100360 Anchorage, Alaska, 99510-03603. Address:
KRU 3S-722
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
Gas-Mcf
MD
18,634-9,299ft
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
324-508
Sr Pet Eng:
9210
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.
Madeline Woodard
madeline.e.woodard@cop.com
907-265-6086
p
k
ft
t
Fra
O
s O
224
6. A
G
L
PG
,
C
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 8:22 am, Oct 31, 2024
Digitally signed by Madeline Woodard
DN: CN=Madeline Woodard, E=
madeline.e.woodard@conocophillips.com
Reason: I am the author of this document
Location:
Date: 2024.10.30 16:39:58-08'00'
Foxit PDF Editor Version: 13.0.0
Madeline
Woodard
Page 1/2
3S-722
Report Printed: 10/29/2024
AOGCC Well History Report
Daily Operations
Start Date End Date AFE / RFE Last 24hr Sum
10/12/2024 00:00 10/12/2024 23:59 10451699 COMPLETE RIG DOWN, COMPLETE EVACUATING TANK BOTTOMS, BROKE DOWN TANK FARM
10/11/2024 00:00 10/11/2024 23:59 10451699 RIG DOWN THE LAUNCHER STACK, GOAT HEAD, AND LAUNCH LINE OFF THE WELL RIG DOWN
HARD LINE, BREAK DOWN PUMP IRON, RACK UP SUCK SIDE
10/10/2024 00:00 10/10/2024 23:59 10451699 STAGE 16 COMPLETED AS DESIGNED,DART SEATED 7 BBL EARLY DIFFERENTIAL PSI 3338
TOTAL CLEAN VOLUME PUMPED 1959 BBL, TOTAL PROPPANT PLACED 309,855, AVG PSI 2,164
AVG RATE 19.4 BPM
STAGE 17 COMPLETED AS DESIGNED,DART SEAT 13 BBL EARLY DIFFERENTIAL 4935 PSI
SURFACE, TOTAL CLEAN VOLUME PUMPED 1578 BBL, TOTAL PROPPANT PLACED 306,902, AVG
PSI 2,736 AVG RATE 19.4 BPM
STAGE 18 COMPLETED AS DESIGNED, DART SEAT 16 BBL EARLY DIFFERENTIAL 3547 PSI
SURFACE, TOTAL CLEAN VOLUME PUMPED 15894 BBL, TOTAL PROPPANT PLACED 302,994, AVG
PSI 2,152 AVG RATE 19.6 BPM
STAGE 19 COMPLETED AS DESIGNED, DART SEAT 8 BBL EARLY DIFFERENTIAL 4881 PSI
SURFACE, TOTAL CLEAN VOLUME PUMPED 1,666 BBL, TOTAL PROPPANT PLACED 310,800, AVG
PSI 1,886 AVG RATE 19.5 BPM
STAGE 20 COMPLETED AS DESIGNED, DART SEAT 11 BBL EARLY DIFFERENTIAL 3849 PSI
SURFACE, TOTAL CLEAN VOLUME PUMPED 1,612 BBL, TOTAL PROPPANT PLACED 297,441 AVG
PSI 2,375 AVG RATE 19.3 BBL
THE WELL WAS UNDER FLUSHED BY 21 BBLS LEAVING -570 LBS OF PROPPANT IN THE
WELLBORE., APPROXIMATELY 1300 FEET
LRS COMPLETED 35 BBL FREEZE PROTECT
10/9/2024 11:30 10/9/2024 23:59 10451699 RIG UP DART LAUNCHER/REVOLVER, RIG UP FRONT YARD
STIMULATE STAGE 13 - 15 PER DESIGN w/ 12089 LBS OF 100 MESH & 883687 LBS OF 16/20
PROPPANT, TOTAL PROPPANT 895776 LBS. 5334 BBL FLUID PUMPED
10/9/2024 00:00 10/9/2024 11:30 10451699 ***JOB CONTINUED FROM 09-OCT-2024***
CONTINUE RIH WITH TTIX CONVEYED PERFORATION W/ 10' OF S2906D RDX HSD GUNS, 6 SPF,
60 DEG PHASE.
PERFORATED INTERVAL = 12615' - 12625'
CCL TO TOP SHOT= 16.1'
CCL STOP DEPTH=12598.9'
JOB COMPLETE, READ FOR FRAC.
10/8/2024 10:30 10/9/2024 00:00 10451699 RIG UP SLB ELINE FOR TTIX CONVEYED PERFORATION W/ 10' OF S2906D RDX HSD GUNS, 6
SPF, 60 DEG PHASE. RIH TO TOOL STALL OUT AT 3180 FT. ENGAGE TRACTOR AND CONTINUE
RIH.
***JOB ONGOING***
10/7/2024 00:00 10/7/2024 23:59 10451699 STIMULATE STAGE 12 PER DESIGN w/ 2449 LBS OF 100 MESH & 302027 LBS OF 16/20
PROPPANT UP TO 10 PPG. 1651 BBL CLEAN FLUID PUMPED
LAUNCHED DART 12 FOR STAGE 13 @ 1972 JSV, LANDED 7 BBL EARLY @ 2157 JSV. DART LAND
2482 SURFACE PSI/ 3518 PSI BHP, PSI SPIKE TO 6486 SURFACE PSI AND 7486 PSI BHP.
ATTEMPTED PUMP IN 8 TIMES BLEED OFF THROUGH HES CHOKE. NO INJECTIVITY
TOTAL CLEAN VOLUME PUMPED 210 BBL
DECISION MADE TO HAVE ELINE PERF
10/6/2024 00:00 10/6/2024 23:59 10451699 STIMULATE STAGE 9 - 11 PER DESIGN w/ 8615 LBS OF 100 MESH & 902263 LBS OF 16/20
PROPPANT UP TO 10 PPG. 5710 BBL JCV
10/5/2024 00:00 10/5/2024 23:59 10451699 STIMULATE STAGE 5 - 8 PER DESIGN w/ 10,609 LBS OF 100 MESH & 1,201,744 LBS OF 16/20
PROPPANT UP TO 10 PPG. 7155 BBL FLUID PUMPED
10/4/2024 06:00 10/4/2024 23:59 10451699 RIG UP DART LAUNCH STACK AND REVOLVER, HES RIG UP FRONT YARD. CHECK COMMS ON
EQUIPMENT
9/21/2024 00:00 10/4/2024 05:59 10451699 WAIT ON COIL
9/20/2024 00:00 9/20/2024 23:59 10451699 STAGE 5 - EQUALIZE TO 1097 PSI, OPENING PSI 375. ATTEMPT TO ESTABLISH RATE AT 1.5 BPM,
MAX PSI OF 7998. PRESSURED UP 5 TIMES WITH NO LEAK OFF, FLOW BACK THROUGH HES
CHOKE 2 TIMES FOR TOTAL OF 50BBL RETURNED TO SURFACE. HES RIG DOWN DART
LAUNCHER AND STAND PIPE. JOB ON HOLD
9/19/2024 00:00 9/19/2024 23:59 10451699 STAGE 5 - EQUALIZED TO 900 PSI, OPEN AT 435 PSI. UNABLE TO ESTABLISH INJECTION TO
LAUNCH DART, PRESSURE UP TO 8000 PSI, ALLOW TO LEAK OFF TO 1000PSI, REPEATED 21
TIMES, ONLY ABLE TO GET 12 BBL FREEZE PROTECT AWAY DUE TO LACK OF INJECTIVITY
9/18/2024 10:00 9/18/2024 23:59 10451699 STAGE 3 COMPLETED THROUGH PERFORATIONS, TOTAL CLEAN VOLUME PUMPED 2336 BBL,
TOTAL PROPPANT PLACED 306,413 , AVG PSI 3,706 AVG RATE 17.9 BPM
STAGE 4 DART SEAT 12 BBL EARLY DIFFERENTIAL 3831 PSI SURFACE, MINI-FRAC
PERFORMED, TOTAL CLEAN VOLUME PUMPED 2645 BBL, TOTAL PROPPANT PLACED 304,081,
AVG PSI 3092 AVG RATE 19.7 BPM
Page 2/2
3S-722
Report Printed: 10/29/2024
AOGCC Well History Report
Daily Operations
Start Date End Date AFE / RFE Last 24hr Sum
9/18/2024 04:00 9/18/2024 07:30 10451699 INJECTIVITY TEST / FREEZE PROTECT
PUMPED 40 BBLS DSL DWN TBG
9/18/2024 00:00 9/18/2024 10:00 10451699 ***JOB CONTINUED FROM 17-SEP-24***
SHOT 2.875" HSD AT 17535' - 17545'. POOH AND STANDBY FOR LRS, CONFIRM GUN SHOT,
RDMO, READY FOR FRAC
***JOB COMPLETED***
9/17/2024 00:00 9/17/2024 23:59 10451699 ***JOB CONTINUED FROM 16-SEP-24***
CONTINUE STANDING BY FOR TOOLS RECEIVING MAINTENANCE. RU AND RIH WITH 2.875" HSD
ON TRACTOR. TAG HIGH AT 17576'. LOG UP TO SHOOTING DEPTH OF17535'.
***JOB IN PROGRESS***
9/16/2024 15:00 9/16/2024 23:59 10451699 MOBILZE EQUIPMENT FROM 2A, SPOT IN EQUIPMENT. STACK LUBRICATOR AND WLV.
PERFORM PASSING PRESSURE TEST. STANDBY FOR TOOLS RECEIVING MAINTENANCE
***JOB IN PROGRESS***
9/16/2024 00:00 9/16/2024 15:06 10451699 EQUALIZED TO 800 PSI OPENED @ 425 PSI, ESTABLISHED INJECTION, CONTINUED
PRESSURING UP TO 8500PSI, PUMP KICKED, CONTINUED PRESSURING UP TO 8500 PS, 14
TIMES, CONTINUED FALL OFF OF 1000 PSI IN 3 MINUTES, TOTAL INJECTION 31 BBL, SHUT
DOWN, RIG OFF,HAND OVER TO WIRE LINE.
9/15/2024 00:00 9/15/2024 23:59 10451699 EQUALIZE TO 1000, WELL OPEN 448 PSI, LAUNCHED DART 1 FOR STAGE 2 @ 47 JSV, LANDED 5
BBL EARLY @ 317 JSV, DIFFERENTIAL 4015 PSI SURFACE, 158 PSI BH TOTAL CLEAN VOLUME
PUMPED 1917 BBL,TOTAL PROPPANT PLACED 309,587, AVG PSI 3,353, AVG RATE19.6 BPM
STAGE 3 DART SEAT 19 BBL EARLY,DART LANDED NO SHIFT, LET PSI FALL OFF, BUMPED PSI
UP, NO SHIFT PSI HELD NO BLEED OFF. BLED DOWN TO 5000PSI, CAME BACK UP TO 8500 PSI,
NO SHIFT REPEATED BLEEDING DOWN TO 0 BUMPING UP TO 8500 PSI SEVRAL TIMES, NO
SHIFT, DECISION MADE TO SHUT DOWN LET DART DISSOLUTION OCCUR, TRY INFECTIVITY IN
THE AM.
9/14/2024 00:00 9/14/2024 23:59 10451699 DURING START UP OPERATIONS A WATER QUALITY ISSUE WAS DISCOVERED, COMPLETED A
CHANDLER TEST AND RETESTED NEWLY PRODUCED FRAC TANKS, FINAL RESULT FLUID
RHEOLOGY WAS ACCEPTABLE.
STAGE 1, ARSENAL DISC BROKE @6680, ALPHA SLEEVE SHIFTED @ 6693 TOTAL CLEAN
VOLUME PUMPED 3,102 BBL, TOTAL PROPPANT PLACED 312,006, AVG PSI 2929 SURFACE ,
AVG RATE 19.3 BPM
9/13/2024 06:00 9/13/2024 23:59 10451699 RIGGED IN IRON, SPOTTED FUEL SYSTEM, SPOTTED IN POP AND BLEED TANKS, STACKED THE
LAUNCH STACK
9/12/2024 06:00 9/12/2024 18:00 10451699 PREPARED FRAC EQUIPMENT FOR RIG UP, SPOTTED IN CHEMS
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Set GLV, pulled plug 3S-722 10/17/2024 rogerba
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 20 18.50 37.8 130.8 130.8 78.85 X65 Welded
Surface 10 3/4 9.95 37.7 3,562.1 2,595.8 45.50 L-80 Hydril 563
Intermediate 7 5/8 6.87 37.5 8,889.2 4,197.4 29.70 L-80 Hydril 563
Liner 4 1/2 3.96 8,716.3 18,890.8 4,184.4 12.60 P110-S Hydril 563
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
36.3
Set Depth
8,722.6
String Max No
4 1/2
Set Depth
4,164.9
Tubing Description
Tubing Completion Upper
Wt (lb/ft)
12.60
Grade
L-80
Top Connection
Hydril 563
ID (in)
3.96
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)
36.3 36.3 0.00 Hanger 10.850 StreamFlo SF DMLX 3.910
2,976.5 2,441.4 70.80 GLM 4.500 SLB KBG-4-5 3.865
8,371.9 4,075.7 73.01 Sliding Sleeve 5.500 CMU SLB NEXA-2 3.813
8,479.3 4,106.3 74.05 Gauge Mandrel 4.500 Single HAL OPSIS 3.833
8,585.7 4,133.6 76.14 PACKER 6.600 HAL TNT 3.800
8,652.1 4,149.2 76.67 Nipple - DB 4.500 SLB DB-6 3.750
8,702.2 4,160.5 77.43 Shear Out Sub 4.500 5500 psi shear Arsenal 3.833
8,713.8 4,163.0 77.66 Locator 6.360 Shear Type Locator Baker 3.890
8,714.4 4,163.1 77.67 Locator 4.500 3.890
8,719.4 4,164.2 77.77 Mule Shoe 4.500 Self-aligned Mule Shoe HAL 3.900
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)
2,976.5 2,441.4 70.80 1 INJ GLV BK 1 1,600.0 10/17/2024 CAMCO DCK-2 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)
8,716.3 4,163.6 77.71 PACKER 5.500 H296450629 Baker ZXP 4.750
8,736.2 4,167.7 78.11 Nipple - RS 5.500 10644478 Baker 10644478 4.250
8,746.9 4,169.9 78.32 XO Reducing 5.500 Baker 3.900
9,299.4 4,242.4 88.00 Sleeve - Frac #19 5.500 AU 109280 3.500
9,788.1 4,242.0 90.32 Sleeve - Frac #18 5.500 AU 109280 3.500
10,241.7 4,240.4 89.93 Sleeve - Frac #17 5.500 AU 109280 3.500
10,780.0 4,241.3 89.91 Sleeve - Frac #16 5.500 AU 109280 3.500
11,278.0 4,242.1 90.35 Sleeve - Frac #15 5.500 AU 109280 3.500
11,730.0 4,239.2 90.45 Sleeve - Frac #14 5.500 AU 109280 3.500
12,225.6 4,235.8 90.28 Sleeve - Frac #13 5.500 AU 109280 3.500
12,641.2 4,233.9 90.37 Sleeve - Frac #12 5.500 AU 109280 3.500
13,136.1 4,231.8 90.22 Sleeve - Frac #11 5.500 AU 109280 3.500
13,631.5 4,228.6 90.34 Sleeve - Frac #10 5.500 AU 109280 3.500
14,126.5 4,224.9 90.21 Sleeve - Frac #9 5.500 AU 109280 3.500
14,622.9 4,221.5 90.37 Sleeve - Frac #8 5.500 AU 109280 3.500
15,119.6 4,218.1 90.56 Sleeve - Frac #7 5.500 AU 109280 3.500
15,615.1 4,214.7 90.43 Sleeve - Frac #6 5.500 AU 109280 3.500
16,111.0 4,210.3 90.60 Sleeve - Frac #5 5.500 AU 109280 3.500
16,607.6 4,205.3 90.86 Sleeve - Frac #4 5.500 AU 109280 3.500
17,103.8 4,197.5 90.80 Sleeve - Frac #3 5.500 AU 109280 3.500
17,597.9 4,192.3 90.32 Sleeve - Frac #2 5.500 AU 109280 3.500
18,092.7 4,189.8 90.24 Sleeve - Frac #1 5.500 AU 109280 3.500
18,589.2 4,185.9 90.38 Sleeve - Setting 5.640 Rupture Disc 16 8911 psi Baker Alpha
Sleeve
3.000
18,634.4 4,185.5 90.47 Sleeve - Setting 5.640 Rupture Disc 15 8386 psi Baker Alpha
Sleeve
3.000
18,803.2 4,184.2 90.10 Collar - Landing 5.190 Landing Collar Baker Alpha Type
II
3.890
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
12,615.0 12,625.0 4,234.1 4,234.0 10/9/2024 6.0 IPERF 2-7/8" HSD, S2906D, RDX,
15.4 g, 60 Deg Phasing
17,535.0 17,545.0 4,192.8 4,192.7 9/18/2024 6.0 IPERF 2-7/8" HSD, S2906D, RDX,
15.4 g, 60 Deg Phasing
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
18,589.0 18,592.0 1 Hydraulic
fracture
9/14/2024 308,000.0 312,006.0 3,101.93 3,433.43
HORIZONTAL, 3S-722, 10/30/2024 4:20:41 PM
M
D
(ft
KB
)
-33,910.1
-21,305.8
-24.3
-22.3
-20.3
-17.7
-15.7
-13.8
-11.8
-6.2
-1.0
37.1
38.7
130.9
1,731.0
2,966.9
2,993.1
3,480.6
4,040.0
8,372.0
8,479.3
8,585.6
8,652.2
8,702.1
8,715.9
8,736.2
8,752.3
8,797.9
8,894.0
9,787.1
10,241.1
10,779.9
11,279.9
11,732.0
12,228.0
12,643.4
13,138.5
14,126.0
14,622.7
15,122.0
15,617.5
16,113.2
17,103.0
17,544.9
18,092.8
18,591.9
18,803.2
18,890.7
Vertical schematic (actual)
PERMA
UGNU UGNU
UGNU A WEST S
WEST S
CAMP_
COYOT
Float Shoe; 18,887.0-18,890.8; 3.85; 4-53; 5.200
Blank Liner; 18,804.9-18,887.0; 82.05; 4-52; 4.500; 3.958
Collar - Landing; 18,803.2-18,804.9; 1.70; 4-51; 5.190; 3.890
Blank Liner; 18,638.1-18,803.2; 165.12; 4-50; 4.500; 3.958
Sleeve - Setting; 18,634.4-18,638.1; 3.70; 4-49; 5.640; 3.000
Blank Liner; 18,592.9-18,634.4; 41.48; 4-48; 4.500; 3.958
Sleeve - Setting; 18,589.2-18,592.9; 3.70; 4-47; 5.640; 3.000
Blank Liner; 18,095.0-18,589.2; 494.17; 4-46; 4.500; 3.958
Sleeve - Frac #1; 18,092.7-18,095.0; 2.30; 4-45; 5.500; 3.500
Blank Liner; 17,600.2-18,092.7; 492.55; 4-44; 4.500; 3.958
Sleeve - Frac #2; 17,597.9-17,600.2; 2.30; 4-43; 5.500; 3.500
IPERF; 17,535.0-17,545.0; 9/18/2024
Blank Liner; 17,106.1-17,597.9; 491.77; 4-42; 4.500; 3.958
Sleeve - Frac #3 ; 17,103.8-17,106.1; 2.30; 4-41; 5.500; 3.500
Blank Liner; 16,609.9-17,103.8; 493.93; 4-40; 4.500; 3.958
Sleeve - Frac #4; 16,607.6-16,609.9; 2.30; 4-39; 5.500; 3.500
Blank Liner; 16,113.3-16,607.6; 494.31; 4-38; 4.500; 3.958
Sleeve - Frac #5; 16,111.0-16,113.3; 2.30; 4-37; 5.500; 3.500
Blank Liner; 15,617.4-16,111.0; 493.59; 4-36; 4.500; 3.958
Sleeve - Frac #6; 15,615.1-15,617.4; 2.30; 4-35; 5.500; 3.500
Blank Liner; 15,121.9-15,615.1; 493.19; 4-34; 4.500; 3.958
Sleeve - Frac #7; 15,119.6-15,121.9; 2.30; 4-33; 5.500; 3.500
Blank Liner; 14,625.2-15,119.6; 494.44; 4-32; 4.500; 3.958
Sleeve - Frac #8; 14,622.9-14,625.2; 2.30; 4-31; 5.500; 3.500
Blank Liner; 14,128.8-14,622.9; 494.03; 4-30; 4.500; 3.958
Sleeve - Frac #9; 14,126.5-14,128.8; 2.30; 4-29; 5.500; 3.500
Blank Liner; 13,633.8-14,126.5; 492.76; 4-28; 4.500; 3.958
Sleeve - Frac #10; 13,631.5-13,633.8; 2.30; 4-27; 5.500; 3.500
Blank Liner; 13,138.4-13,631.5; 493.04; 4-26; 4.500; 3.958
Sleeve - Frac #11; 13,136.1-13,138.4; 2.30; 4-25; 5.500; 3.500
Blank Liner; 12,643.5-13,136.1; 492.60; 4-24; 4.500; 3.958
Sleeve - Frac #12; 12,641.2-12,643.5; 2.30; 4-23; 5.500; 3.500
IPERF; 12,615.0-12,625.0; 10/9/2024
Blank Liner; 12,227.9-12,641.2; 413.34; 4-22; 4.500; 3.958
Sleeve - Frac #13; 12,225.6-12,227.9; 2.30; 4-21; 5.500; 3.500
Blank Liner; 11,732.3-12,225.6; 493.27; 4-20; 4.500; 3.958
Sleeve - Frac #14; 11,730.0-11,732.3; 2.30; 4-19; 5.500; 3.500
Blank Liner; 11,280.3-11,730.0; 449.73; 4-18; 4.500; 3.958
Sleeve - Frac #15; 11,278.0-11,280.3; 2.30; 4-17; 5.500; 3.500
Blank Liner; 10,782.3-11,278.0; 495.67; 4-16; 4.500; 3.958
Sleeve - Frac #16; 10,780.0-10,782.3; 2.30; 4-15; 5.500; 3.500
Blank Liner; 10,244.0-10,780.0; 535.98; 4-14; 4.500; 3.958
Sleeve - Frac #17; 10,241.7-10,244.0; 2.30; 4-13; 5.500; 3.500
Blank Liner; 9,790.4-10,241.7; 451.34; 4-12; 4.500; 3.958
Sleeve - Frac #18; 9,788.1-9,790.4; 2.30; 4-11; 5.500; 3.500
Blank Liner; 9,301.7-9,788.1; 486.35; 4-10; 4.500; 3.958
Sleeve - Frac #19; 9,299.4-9,301.7; 2.30; 4-9; 5.500; 3.500
Blank Liner; 8,766.1-9,299.4; 533.35; 4-8; 4.500; 3.958
Shoe; 8,886.1-8,889.2; 3.10; 3-7; 7.625
Casing Jts; 8,800.7-8,886.1; 85.38; 3-6; 7.625; 6.875
Collar - Float; 8,798.0-8,800.7; 2.73; 3-5; 7.625
Casing Jts; 8,757.3-8,798.0; 40.70; 3-4; 7.625; 6.875
Liner Pup Joint; 8,756.2-8,766.1; 9.86; 4-7; 4.500; 3.958
Liner Pup Joint; 8,752.4-8,756.2; 3.84; 4-6; 4.500; 3.958
Liner Pup Joint; 8,748.6-8,752.4; 3.83; 4-5; 4.500; 3.958
XO Reducing; 8,746.9-8,748.6; 1.68; 4-4; 5.500; 3.900
Hanger; 8,738.5-8,746.9; 8.34; 4-3; 5.500; 4.780
Nipple - RS; 8,736.2-8,738.5; 2.33; 4-2; 5.500; 4.250
PACKER; 8,716.3-8,736.2; 19.88; 4-1; 5.500; 4.750
Mule Shoe; 8,719.4-8,722.6; 3.25; 1-29; 4.500; 3.900
Tubing - Pup Joint; 8,716.3-8,719.4; 3.07; 1-28; 4.500; 3.958
Locator; 8,714.4-8,716.3; 1.88; 1-27; 4.500; 3.890
Locator; 8,713.8-8,714.4; 0.63; 1-26; 6.360; 3.890
Tubing - Pup Joint; 8,704.0-8,713.8; 9.73; 1-25; 4.500; 3.958
Shear Out Sub; 8,702.2-8,704.0; 1.86; 1-24; 4.500; 3.833
Tubing; 8,663.5-8,702.2; 38.69; 1-23; 4.500; 3.958
Tubing - Pup Joint; 8,653.7-8,663.5; 9.74; 1-22; 4.500; 3.958
Nipple - DB; 8,652.1-8,653.7; 1.61; 1-21; 4.500; 3.750
Tubing - Pup Joint; 8,642.3-8,652.1; 9.82; 1-20; 4.500; 3.958
Tubing; 8,600.8-8,642.3; 41.47; 1-19; 4.500; 3.958
Tubing - Pup Joint; 8,591.1-8,600.8; 9.71; 1-18; 4.500; 3.958
PACKER; 8,585.7-8,591.1; 5.42; 1-17; 6.600; 3.800
Tubing - Pup Joint; 8,576.0-8,585.7; 9.70; 1-16; 4.500; 3.958
Tubing; 8,493.3-8,576.0; 82.74; 1-15; 4.500; 3.958
Tubing - Pup Joint; 8,483.5-8,493.3; 9.74; 1-14; 4.500; 3.958
Gauge Mandrel; 8,479.3-8,483.5; 4.24; 1-13; 4.500; 3.833
Tubing - Pup Joint; 8,469.6-8,479.3; 9.72; 1-12; 4.500; 3.958
Tubing; 8,386.6-8,469.6; 82.97; 1-11; 4.500; 3.958
Tubing - Pup Joint; 8,376.9-8,386.6; 9.74; 1-10; 4.500; 3.958
Sliding Sleeve; 8,371.9-8,376.9; 4.95; 1-9; 5.500; 3.813
Tubing - Pup Joint; 8,362.2-8,371.9; 9.72; 1-8; 4.500; 3.958
Casing Jts; 7,914.5-8,757.3; 842.84; 3-3; 7.625; 6.765
Tubing; 2,993.2-8,362.2; 5,368.97; 1-7; 4.500; 3.958
Casing Jts; 38.1-7,914.5; 7,876.35; 3-2; 7.625; 6.875
Float Shoe; 3,559.7-3,562.1; 2.40; 2-10; 10.750; 9.950
Casing Jts; 3,480.6-3,559.7; 79.07; 2-9; 10.750; 9.950
Float Collar; 3,477.4-3,480.6; 3.18; 2-8; 10.750; 9.950
Casing Jts; 3,437.1-3,477.4; 40.32; 2-7; 10.750; 9.950
Tubing - Pup Joint; 2,983.5-2,993.2; 9.71; 1-6; 4.500; 3.958
GLM; 2,976.5-2,983.5; 7.05; 1-5; 4.500; 3.865
Tubing - Pup Joint; 2,966.8-2,976.5; 9.69; 1-4; 4.500; 3.958
Casing Jts; 164.4-3,437.1; 3,272.68; 2-6; 10.750; 9.950
Tubing; 58.1-2,966.8; 2,908.73; 1-3; 4.500; 3.958
Casing Pup; 154.6-164.4; 9.87; 2-5; 10.750; 9.950
Casing Jts A; 117.1-154.6; 37.51; 2-4; 10.750; 9.950
Casing Jts B; 78.1-117.1; 39.00; 2-3; 10.750; 9.950Casing Jts; 37.8-130.8; 93.00; 1-1; 20.000; 18.500
Casing Jts C; 38.6-78.1; 39.43; 2-2; 10.750; 9.950
Tubing - Pup Joint; 36.9-58.1; 21.11; 1-2; 4.500; 3.958
Hanger; 37.7-38.6; 0.90; 2-1; 18.940; 9.950
Hanger; 37.5-38.1; 0.63; 3-1; 7.625; 6.875
Hanger; 36.3-36.9; 0.67; 1-1; 10.850; 3.910
KUP PROD
KB-Grd (ft)
38.62
RR Date
9/6/2024
Other Elev
3S-722
...
TD
Act Btm (ftKB)
18,894.0
Well Attributes
Field Name Wellbore API/UWI
501032088600
Wellbore Status
PROD
Max Angle & MD
Incl (°)
91.10
MD (ftKB)
16,957.90
WELLNAME WELLBORE3S-722
Annotation End DateH2S (ppm) DateComment
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
18,092.0 18,095.0 2 Hydraulic
fracture
9/15/2024 304,000.0 309,587.0 1,916.36 2,245.20
17,535.0 17,545.0 3 Hydraulic
fracture
9/18/2024 304,000.0 306,413.0 2,335.59 2,661.06
17,103.0 17,106.0 4 Hydraulic
fracture
9/18/2024 304,000.0 304,081.0 2,644.60 2,967.58
16,607.0 16,610.0 5 Hydraulic
fracture
10/5/2024 304,000.0 303,670.0 2,208.79 2,531.32
16,110.0 16,113.0 6 Hydraulic
fracture
10/5/2024 304,000.0 302,348.0 1,725.45 2,046.59
15,614.0 15,617.0 7 Hydraulic
fracture
10/5/2024 304,000.0 304,260.0 1,662.31 1,985.48
15,119.0 15,122.0 8 Hydraulic
fracture
10/5/2024 304,000.0 301,991.0 1,882.74 2,203.47
14,622.0 14,625.0 9 Hydraulic
fracture
10/6/2024 304,000.0 302,799.0 2,094.12 2,415.72
14,126.0 14,129.0 10 Hydraulic
fracture
10/6/2024 304,000.0 305,604.0 1,782.60 2,107.19
13,631.0 13,634.0 11 Hydraulic
fracture
10/6/2024 304,000.0 304,377.0 1,873.90 2,197.20
13,135.0 13,138.0 12 Hydraulic
fracture
10/7/2024 304,000.0 304,462.0 1,664.98 1,988.34
12,615.0 12,625.0 13 Hydraulic
fracture
10/9/2024 304,000.0 298,850.0 2,171.12 2,488.56
12,225.0 12,228.0 14 Hydraulic
fracture
10/9/2024 304,000.0 304,301.0 1,604.60 1,927.84
11,729.0 11,732.0 15 Hydraulic
fracture
10/9/2024 304,000.0 294,630.0 1,782.24 2,095.20
11,277.0 11,280.0 16 Hydraulic
fracture
10/10/2024 304,000.0 309,855.0 1,972.76 2,301.87
10,779.0 10,782.0 17 Hydraulic
fracture
10/10/2024 304,000.0 306,902.0 1,577.69 1,903.67
10,241.0 10,244.0 18 Hydraulic
fracture
10/10/2024 304,000.0 302,994.0 1,584.07 1,905.92
9,787.0 9,790.0 19 Hydraulic
fracture
10/10/2024 304,000.0 310,800.0 1,665.88 1,996.01
9,299.0 9,302.0 20 Hydraulic
fracture
10/10/2024 304,000.0 297,441.0 1,612.00 1,928.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
37.5 3,562.0 37.5 2,595.8 Surface String
Cement
505 BBLS 10.7 PPG lead, 61 BBLS 15.8 PPG tail.
Reciprocate pipe for entire job. Bumped plugs as
calculated. Floats held. 255 BBLS good cement
dumped at surface.
8/15/2024
7,261.0 8,889.0 3,670.9 4,197.4 Intermediate
String 1
Cement
72 bbls 15.3 ppg BM11 47 bbls with out BM11 25
bbls 15.3 ppg primary cement
8/24/2024
8,716.0 18,890.0 4,163.5 4,184.4 Production
String 1
Cement
Pump 60 bbls 10.5 ppg tuned prime spacer @ 3.5
bpm, 1060 psi. Cement wet @ 15:08 hrs. Pump 245
bbls 15.3 ppg slurry cement @ 3.8 bpm, 830 psi.
Shut down. Line up to flush cement lines to the pits.
Flush with 10 bbls of water. Observe 100% flow line
packoff. Decision made to take returns to the cellar.
Drop DP dart plug. Displace cement with 9.5
inhibitive FWP @ 2.5 bpm, 1510 psi. Observe Baker
dart latch at 725 stks. At 1430 stks pumped, pump
29 bbls of 10 ppg tuned spacer @ 2.5 bpm, 1365 psi.
Continue to chase cement with 9.5 inhibitive FWP @
2.5 bpm. Bump plug @ 2273 stks w/ 1960 psi.
Pressure up to 2200 psi for 5 min. Bleed off check
floats (holding) CIP @ 18:13 hrs.
9/3/2024
HORIZONTAL, 3S-722, 10/30/2024 4:20:42 PM
M
D
(ft
KB
)
-33,910.1
-21,305.8
-24.3
-22.3
-20.3
-17.7
-15.7
-13.8
-11.8
-6.2
-1.0
37.1
38.7
130.9
1,731.0
2,966.9
2,993.1
3,480.6
4,040.0
8,372.0
8,479.3
8,585.6
8,652.2
8,702.1
8,715.9
8,736.2
8,752.3
8,797.9
8,894.0
9,787.1
10,241.1
10,779.9
11,279.9
11,732.0
12,228.0
12,643.4
13,138.5
14,126.0
14,622.7
15,122.0
15,617.5
16,113.2
17,103.0
17,544.9
18,092.8
18,591.9
18,803.2
18,890.7
Vertical schematic (actual)
PERMA
UGNU UGNU
UGNU A WEST S
WEST S
CAMP_
COYOT
Float Shoe; 18,887.0-18,890.8; 3.85; 4-53; 5.200
Blank Liner; 18,804.9-18,887.0; 82.05; 4-52; 4.500; 3.958
Collar - Landing; 18,803.2-18,804.9; 1.70; 4-51; 5.190; 3.890
Blank Liner; 18,638.1-18,803.2; 165.12; 4-50; 4.500; 3.958
Sleeve - Setting; 18,634.4-18,638.1; 3.70; 4-49; 5.640; 3.000
Blank Liner; 18,592.9-18,634.4; 41.48; 4-48; 4.500; 3.958
Sleeve - Setting; 18,589.2-18,592.9; 3.70; 4-47; 5.640; 3.000
Blank Liner; 18,095.0-18,589.2; 494.17; 4-46; 4.500; 3.958
Sleeve - Frac #1; 18,092.7-18,095.0; 2.30; 4-45; 5.500; 3.500
Blank Liner; 17,600.2-18,092.7; 492.55; 4-44; 4.500; 3.958
Sleeve - Frac #2; 17,597.9-17,600.2; 2.30; 4-43; 5.500; 3.500
IPERF; 17,535.0-17,545.0; 9/18/2024
Blank Liner; 17,106.1-17,597.9; 491.77; 4-42; 4.500; 3.958
Sleeve - Frac #3 ; 17,103.8-17,106.1; 2.30; 4-41; 5.500; 3.500
Blank Liner; 16,609.9-17,103.8; 493.93; 4-40; 4.500; 3.958
Sleeve - Frac #4; 16,607.6-16,609.9; 2.30; 4-39; 5.500; 3.500
Blank Liner; 16,113.3-16,607.6; 494.31; 4-38; 4.500; 3.958
Sleeve - Frac #5; 16,111.0-16,113.3; 2.30; 4-37; 5.500; 3.500
Blank Liner; 15,617.4-16,111.0; 493.59; 4-36; 4.500; 3.958
Sleeve - Frac #6; 15,615.1-15,617.4; 2.30; 4-35; 5.500; 3.500
Blank Liner; 15,121.9-15,615.1; 493.19; 4-34; 4.500; 3.958
Sleeve - Frac #7; 15,119.6-15,121.9; 2.30; 4-33; 5.500; 3.500
Blank Liner; 14,625.2-15,119.6; 494.44; 4-32; 4.500; 3.958
Sleeve - Frac #8; 14,622.9-14,625.2; 2.30; 4-31; 5.500; 3.500
Blank Liner; 14,128.8-14,622.9; 494.03; 4-30; 4.500; 3.958
Sleeve - Frac #9; 14,126.5-14,128.8; 2.30; 4-29; 5.500; 3.500
Blank Liner; 13,633.8-14,126.5; 492.76; 4-28; 4.500; 3.958
Sleeve - Frac #10; 13,631.5-13,633.8; 2.30; 4-27; 5.500; 3.500
Blank Liner; 13,138.4-13,631.5; 493.04; 4-26; 4.500; 3.958
Sleeve - Frac #11; 13,136.1-13,138.4; 2.30; 4-25; 5.500; 3.500
Blank Liner; 12,643.5-13,136.1; 492.60; 4-24; 4.500; 3.958
Sleeve - Frac #12; 12,641.2-12,643.5; 2.30; 4-23; 5.500; 3.500
IPERF; 12,615.0-12,625.0; 10/9/2024
Blank Liner; 12,227.9-12,641.2; 413.34; 4-22; 4.500; 3.958
Sleeve - Frac #13; 12,225.6-12,227.9; 2.30; 4-21; 5.500; 3.500
Blank Liner; 11,732.3-12,225.6; 493.27; 4-20; 4.500; 3.958
Sleeve - Frac #14; 11,730.0-11,732.3; 2.30; 4-19; 5.500; 3.500
Blank Liner; 11,280.3-11,730.0; 449.73; 4-18; 4.500; 3.958
Sleeve - Frac #15; 11,278.0-11,280.3; 2.30; 4-17; 5.500; 3.500
Blank Liner; 10,782.3-11,278.0; 495.67; 4-16; 4.500; 3.958
Sleeve - Frac #16; 10,780.0-10,782.3; 2.30; 4-15; 5.500; 3.500
Blank Liner; 10,244.0-10,780.0; 535.98; 4-14; 4.500; 3.958
Sleeve - Frac #17; 10,241.7-10,244.0; 2.30; 4-13; 5.500; 3.500
Blank Liner; 9,790.4-10,241.7; 451.34; 4-12; 4.500; 3.958
Sleeve - Frac #18; 9,788.1-9,790.4; 2.30; 4-11; 5.500; 3.500
Blank Liner; 9,301.7-9,788.1; 486.35; 4-10; 4.500; 3.958
Sleeve - Frac #19; 9,299.4-9,301.7; 2.30; 4-9; 5.500; 3.500
Blank Liner; 8,766.1-9,299.4; 533.35; 4-8; 4.500; 3.958
Shoe; 8,886.1-8,889.2; 3.10; 3-7; 7.625
Casing Jts; 8,800.7-8,886.1; 85.38; 3-6; 7.625; 6.875
Collar - Float; 8,798.0-8,800.7; 2.73; 3-5; 7.625
Casing Jts; 8,757.3-8,798.0; 40.70; 3-4; 7.625; 6.875
Liner Pup Joint; 8,756.2-8,766.1; 9.86; 4-7; 4.500; 3.958
Liner Pup Joint; 8,752.4-8,756.2; 3.84; 4-6; 4.500; 3.958
Liner Pup Joint; 8,748.6-8,752.4; 3.83; 4-5; 4.500; 3.958
XO Reducing; 8,746.9-8,748.6; 1.68; 4-4; 5.500; 3.900
Hanger; 8,738.5-8,746.9; 8.34; 4-3; 5.500; 4.780
Nipple - RS; 8,736.2-8,738.5; 2.33; 4-2; 5.500; 4.250
PACKER; 8,716.3-8,736.2; 19.88; 4-1; 5.500; 4.750
Mule Shoe; 8,719.4-8,722.6; 3.25; 1-29; 4.500; 3.900
Tubing - Pup Joint; 8,716.3-8,719.4; 3.07; 1-28; 4.500; 3.958
Locator; 8,714.4-8,716.3; 1.88; 1-27; 4.500; 3.890
Locator; 8,713.8-8,714.4; 0.63; 1-26; 6.360; 3.890
Tubing - Pup Joint; 8,704.0-8,713.8; 9.73; 1-25; 4.500; 3.958
Shear Out Sub; 8,702.2-8,704.0; 1.86; 1-24; 4.500; 3.833
Tubing; 8,663.5-8,702.2; 38.69; 1-23; 4.500; 3.958
Tubing - Pup Joint; 8,653.7-8,663.5; 9.74; 1-22; 4.500; 3.958
Nipple - DB; 8,652.1-8,653.7; 1.61; 1-21; 4.500; 3.750
Tubing - Pup Joint; 8,642.3-8,652.1; 9.82; 1-20; 4.500; 3.958
Tubing; 8,600.8-8,642.3; 41.47; 1-19; 4.500; 3.958
Tubing - Pup Joint; 8,591.1-8,600.8; 9.71; 1-18; 4.500; 3.958
PACKER; 8,585.7-8,591.1; 5.42; 1-17; 6.600; 3.800
Tubing - Pup Joint; 8,576.0-8,585.7; 9.70; 1-16; 4.500; 3.958
Tubing; 8,493.3-8,576.0; 82.74; 1-15; 4.500; 3.958
Tubing - Pup Joint; 8,483.5-8,493.3; 9.74; 1-14; 4.500; 3.958
Gauge Mandrel; 8,479.3-8,483.5; 4.24; 1-13; 4.500; 3.833
Tubing - Pup Joint; 8,469.6-8,479.3; 9.72; 1-12; 4.500; 3.958
Tubing; 8,386.6-8,469.6; 82.97; 1-11; 4.500; 3.958
Tubing - Pup Joint; 8,376.9-8,386.6; 9.74; 1-10; 4.500; 3.958
Sliding Sleeve; 8,371.9-8,376.9; 4.95; 1-9; 5.500; 3.813
Tubing - Pup Joint; 8,362.2-8,371.9; 9.72; 1-8; 4.500; 3.958
Casing Jts; 7,914.5-8,757.3; 842.84; 3-3; 7.625; 6.765
Tubing; 2,993.2-8,362.2; 5,368.97; 1-7; 4.500; 3.958
Casing Jts; 38.1-7,914.5; 7,876.35; 3-2; 7.625; 6.875
Float Shoe; 3,559.7-3,562.1; 2.40; 2-10; 10.750; 9.950
Casing Jts; 3,480.6-3,559.7; 79.07; 2-9; 10.750; 9.950
Float Collar; 3,477.4-3,480.6; 3.18; 2-8; 10.750; 9.950
Casing Jts; 3,437.1-3,477.4; 40.32; 2-7; 10.750; 9.950
Tubing - Pup Joint; 2,983.5-2,993.2; 9.71; 1-6; 4.500; 3.958
GLM; 2,976.5-2,983.5; 7.05; 1-5; 4.500; 3.865
Tubing - Pup Joint; 2,966.8-2,976.5; 9.69; 1-4; 4.500; 3.958
Casing Jts; 164.4-3,437.1; 3,272.68; 2-6; 10.750; 9.950
Tubing; 58.1-2,966.8; 2,908.73; 1-3; 4.500; 3.958
Casing Pup; 154.6-164.4; 9.87; 2-5; 10.750; 9.950
Casing Jts A; 117.1-154.6; 37.51; 2-4; 10.750; 9.950
Casing Jts B; 78.1-117.1; 39.00; 2-3; 10.750; 9.950Casing Jts; 37.8-130.8; 93.00; 1-1; 20.000; 18.500
Casing Jts C; 38.6-78.1; 39.43; 2-2; 10.750; 9.950
Tubing - Pup Joint; 36.9-58.1; 21.11; 1-2; 4.500; 3.958
Hanger; 37.7-38.6; 0.90; 2-1; 18.940; 9.950
Hanger; 37.5-38.1; 0.63; 3-1; 7.625; 6.875
Hanger; 36.3-36.9; 0.67; 1-1; 10.850; 3.910
KUP PROD 3S-722
...
WELLNAME WELLBORE3S-722
Hydraulic Fracturing Fluid Product Component Information Disclosure
Job Start Date: 09/14/2024
Job End Date: 10/10/2024
State: Alaska
County: Harrison Bay
API Number: 50-103-20886-00-00
Operator Name:ConocoPhillips
Company/Burlington Resources
Well Name and Number: 3S-722
Latitude: 70.394359
Longitude: -150.194961
Datum: NAD27
Federal Well: NO
Indian Well: NO
True Vertical Depth: 4244
Total Base Water Volume (gal)*: 1612844
Total Base Non Water Volume: 0
Water Source Percent
Other, > 1000TDS 100.00%
Hydraulic Fracturing Fluid Composition:
Trade Name Supplier Purpose Ingredients
Chemical
Abstract
Service
Number
(CAS #)
Maximum
Ingredient
Concentration
in Additive
(% by
mass)**
Maximum
Ingredient
Concentration
in HF Fluid
(% by
mass)**
Comments
AS-7 ANTI-
SLUDGING
AGENT
Halliburton Anti-sludging Agent
BA-20
BUFFERING
AGENT
Halliburton Buffer
BC-140 X2 Halliburton Initiator
BE-6(TM)
Bactericide Halliburton Microbiocide
Calcium Chloride ConocoPhillips Salt Solution
CAT-3
ACTIVATOR Halliburton Activator
Ceramic Proppant -
Wanli Wanli Proppant
FE-1A
ACIDIZING
COMPOSITION
Halliburton Additive
FE-2A Halliburton Additive
Flow Insurance
Copper Patina Energy Tracer
HAI-404M Halliburton Corrosion Inhibitor
HYDROCHLORIC
ACID, 10-30%Halliburton Solvent
LoSurf-300D Halliburton Non-ionic Surfactant
LVT-200 Baker Hughes Additive
MO-67 Halliburton pH Control
OPT 2002-2054 ResMetrics Tracer
OPTIFLO-HTE Halliburton Breaker
OPTIFLO-II
DELAYED
RELEASE
BREAKER
Halliburton Breaker
WPT 1001-1052 ResMetrics Tracer
SP BREAKER Halliburton Breaker
WG-36 GELLING
AGENT Halliburton Gelling Agent
Oxygon HES Scavenger
Potassium Formate
Brine MI Swaco Completion/Stimulation
Sand-Common
White-100 Mesh,
SSA-2
Halliburton Proppant
Items above are Trade Names. Items below are the individual ingredients.
Water 7732-18-5 100.00000 66.29340
Corundum 1302-74-5 65.00000 19.19180
Mullite 1302-93-8 45.00000 13.28670
Crystalline silica,
quartz 14808-60-7 100.00000 0.42572
Guar gum 9000-30-0 100.00000 0.21865
Ethanol 64-17-5 60.00000 0.05717
Ammonium acetate 631-61-8 100.00000 0.04605
EDTA/Copper chelate Proprietary 30.00000 0.03873
Monoethanolamine
borate 26038-87-9 100.00000 0.03332
Sodium hydroxide 1310-73-2 30.00000 0.03210
Heavy aromatic
petroleum naphtha 64742-94-5 30.00000 0.02859
Oxyalkylated nonyl
phenolic resin Proprietary 30.00000 0.02859
Ammonium persulfate 7727-54-0 100.00000 0.02346
Acetic acid 64-19-7 60.00000 0.01382
Ethylene glycol 107-21-1 30.00000 0.01000
Oxyalkylated
phenolic resin Proprietary 10.00000 0.00953
Hulls Proprietary 100.00000 0.00740
Oxylated phenolic
resin Proprietary 30.00000 0.00704
Ammonium chloride 12125-02-9 5.00000 0.00645
Poly(oxy-1,2-
ethanediyl), alpha-(4-
nonylphenyl)-omega-
hydroxy-, branched
127087-87-
0 5.00000 0.00476
Naphthalene 91-20-3 5.00000 0.00476
Polyamine Proprietary 30.00000 0.00222
Flow Insurance
Copper Proprietary 100.00000 0.00220
2-Bromo-2-nitro-1,3-
propanediol 52-51-7 100.00000 0.00155
Ammonia 7664-41-7 1.00000 0.00129
Sodium chloride 7647-14-5 1.00000 0.00107
1,2,4
Trimethylbenzene 95-63-6 1.00000 0.00095
Glycol Ether Proprietary 85.00000 0.00058
Hemicellulase 9025-56-3 5.00000 0.00037
C.I. pigment Orange 5 3468-63-1 1.00000 0.00023
Proprietary Confidential 20.00000 0.00021
Ethylene glycol 107-21-1 20.00000 0.00014
C.I. Pigment red 5 6410-41-9 1.00000 0.00007
Cured acrylic resin Proprietary 1.00000 0.00007
2,7-
Naphthalenedisulfonic
acid, 3-hydroxy-4-(4-
sulfor-1-naphthalenyl)
azo -, trisodium salt
915-67-3 0.10000 0.00003
* Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water
** Information is based on the maximum potential for concentration and thus the total may be over 100%
Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided.
Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS)
C:\Users\grgluyas\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\R97USUAM\2024-10-26_21186_KRU_3S-722_CoilFlag_Transmittal.docx
DELIVERABLE DISCRIPTION
Ticket # Field Well # API # Log Description Log Date
21186 KRU 3S-722 50-103-20886-00 Coil Flag 26-Oct-24
DELIVERED TO
Company & Address
DIGITAL FILE
# of Copies
LOG PRINTS
# of Prints
CD’s
# of Copies
1
AOGCC
Attn: Natural Resources Technician
333 W. 7th Ave., Suite 100
Anchorage, Ak. 99501-3539
Delivered By: CPAI Sharefile
______________________________ _____________________________________
Date received Signature
______________________________ ______________________________________
PLEASE RETURN COPY VIA EMAIL TO:
DIANE.WILLIAMS@READCASEDHOLE.COM
READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503
PHONE: (907)245-8951
E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM
224-066
T39720
10/29/2024
Gavin
Gluyas
Digitally signed by
Gavin Gluyas
Date: 2024.10.29
14:53:47 -08'00'
Originated: Delivered to:10-Oct-24
Alaska Oil & Gas Conservation Commiss 10Oct24-NR
ATTN: Meredith Guhl
333 W. 7th Ave., Suite 100
600 E 57th Place Anchorage, Alaska 99501-3539
Anchorage, AK 99518
(907) 273-1700 main (907)273-4760 fax
WELL NAME API #
SERVICE ORDER
#FIELD NAME
SERVICE
DESCRIPTION
DELIVERABLE
DESCRIPTION DATA TYPE DATE LOGGED
3T-621 50-103-20882-00-00 224-022 Kuparuk River WL FMI-MSIP-PEX-ZAIT-XPT FINAL FIELD 11-Mar-24
3S-722 50-103-20886-00-00 224-066 Kuparuk River WL HSD FINAL FIELD 18-Sep-24
1C-152 50-029-23548-00-00 215-114 Kuparuk River WL TTiX-IPROF FINAL FIELD 22-Sep-24
1J-154 50-029-23254-00-00 205-035 Kuparuk River WL TTiX-WFL FINAL FIELD 25-Sep-24
1C-152 50-029-23548-00-00 215-114 Kuparuk River WL IPROF FINAL FIELD 27-Sep-24
1D-05 50-029-20417-00-00 179-095 Kuparuk River WL SCMT FINAL FIELD 28-Sep-24
2K-07 50-029-21351-00-00 189-071 Kuparuk River WL PPROF FINAL FIELD 1-Oct-24
1R-08 50-029-21333-00-00 185-073 Kuparuk River WL IPROF FINAL FIELD 5-Oct-24
1R-10 50-029-21351-00-00 185-096 Kuparuk River WL IPROF FINAL FIELD 6-Oct-24
3S-722 50-103-20886-00-00 224-066 Kuparuk River WL TTiX-Perf FINAL FIELD 9-Oct-24
Transmittal Receipt
________________________________ X_________________________________
Print Name Signature Date
Please return via courier or sign/scan and email a copy to Schlumberger.
Nraasch@slb.com SLB Auditor -
TRANSMITTAL DATE
TRANSMITTAL #
A Delivery Receipt signature confirms that a package (box, envelope,
etc.) has been received. The package will be handled/delivered per
standard company reception procedures. The package's contents have
not been verified but should be assumed to contain the above noted
media.
# Schlumberger-Private
T39651
T39652
T39652
T39653
T39653
T39654
T39655
T39656
T39657
T39658
3S-722 50-103-20886-00-00 224-066 Kuparuk River WL HSD FINAL FIELD 18-Sep-24
3S-722 50-103-20886-00-00 224-066 Kuparuk River WL TTiX-Perf FINAL FIELD 9-Oct-24
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.10.11 08:44:58 -08'00'
a;2q- 0((,:::)
SAMPLE TRANSMITTAL
TO: AOGCC
333 WEST 7TH SUITE 100
ANCH. AK. 99501
279-1433
OPERATOR: CPAI
SAMPLE TYPE: Dry Cuttings
SAMPLES SENT:
3S-722
3565-18894
3 Boxes
SENT BY: M. McCRACKEN
1189q
DATE: 09/30/2024
AIR BILL: NIA
CPAI: CPA12024093021
CHARGE CODE: NIA
NAME: 3S-722
NUMBER OF BOXES: 3 Boxes
UPON RECEIPT OF THESE SAMPLES, PLEASE NOTE ANY DISCREPANCIES AND RETURN A SIGNED COPY
OF THIS FORM TO:
RECEIVED: �
SEP ? 0 2024
AOGGC>
CONOCOPHILLIPS, ALASKA
700 G ST
ATO-380
ANCHORAGE, AK. 99510
ATTN:MIKE McCRACKEN
Mike.mccracken@conocophillips.com
t >>ED W/η
^ Zs/ KZ Z
η&/ >ED
^ Zs/
^Z/Wd/KE >/s Z> ^Z/Wd/KE ddzW d >K''
K>KZ
WZ/Ed^ ͲĞůŝǀĞƌLJ
3S-722 50-103-20886-00-00 224-066 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 1-Sep-24 1
dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚ
ͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ yͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ
WƌŝŶƚEĂŵĞ ^ŝŐŶĂƚƵƌĞ ĂƚĞ
WůĞĂƐĞƌĞƚƵƌŶǀŝĂĐŽƵƌŝĞƌŽƌƐŝŐŶͬƐĐĂŶĂŶĚĞŵĂŝůĂĐŽƉLJƚŽ^ĐŚůƵŵďĞƌŐĞƌ͘
ďŚĂƚƚĂĐŚĂƌLJĂΛƐůď͘ĐŽŵ ^>ƵĚŝƚŽƌͲ
dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚƐŝŐŶĂƚƵƌĞĐŽŶĨŝƌŵƐƚŚĂƚĂƉĂĐŬĂŐĞ;ďŽdž͕
ĞŶǀĞůŽƉĞ͕ĞƚĐ͘ͿŚĂƐďĞĞŶƌĞĐĞŝǀĞĚĂŶĚƚŚĞĐŽŶƚĞŶƚƐŽĨƚŚĞƉĂĐŬĂŐĞ
ŚĂǀĞďĞĞŶǀĞƌŝĨŝĞĚƚŽŵĂƚĐŚƚŚĞŵĞĚŝĂŶŽƚĞĚĂďŽǀĞ͘dŚĞƐƉĞĐŝĨŝĐ
ĐŽŶƚĞŶƚŽĨƚŚĞƐĂŶĚͬŽƌŚĂƌĚĐŽƉLJƉƌŝŶƚƐŵĂLJŽƌŵĂLJŶŽƚŚĂǀĞďĞĞŶ
ǀĞƌŝĨŝĞĚĨŽƌĐŽƌƌĞĐƚŶĞƐƐŽƌƋƵĂůŝƚLJůĞǀĞůĂƚƚŚŝƐƉŽŝŶƚ͘
η^ĐŚůƵŵďĞƌŐĞƌͲWƌŝǀĂƚĞ
224-066
T39580
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.23 08:05:39 -08'00'
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
18894 18894
Casing Collapse
Structural
Conductor
Surface 2470
Intermediate 4790
Production 7850
Liner 9210
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
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 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 3S-722
Undefined Pool
Madeline Woodard
madeline.e.woodard@cop.com
907-265-6086
4197
Subsequent Form Required:
Suspension Expiration Date:
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
AOGCC USE ONLY
11590
Tubing Grade:Tubing MD (ft):
TNT Pkr: 8,583 ' MD / 4,133' TVD
LTP: 8,715' MD / 4,163' TVD
Perforation Depth TVD (ft):
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL380107, ADL380106 KRU
224-066
P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20886-00-00
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
L-80
TVD Burst
8720
10860
MD
6890
5210
130
2595
3925
130
3562
20"
10.75"
130
7.625"7914
3562
Perforation Depth MD (ft):
7914
4.5"
7.625"
Senior Completions Engineer
N/A
10175
9/13/2024
18890
975
4-1/2"
4184
Halliburton TNT Production Packer
Baker ZXP Liner top packer (LTP)
8889
m
n
P
2
66
t
_
N
55
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 8:02 am, Sep 06, 2024
Digitally signed by Madeline Woodard
DN: CN=Madeline Woodard, E=madeline.e.woodard@
conocophillips.com
Reason: I am the author of this document
Location:
Date: 2024.09.05 16:25:21-08'00'
Foxit PDF Editor Version: 13.0.0
Madeline
Woodard
324-508
10-404
VTL 9/11/2024
9/13/2024
SFD 9/11/2024 DSR-9/11/24
X
CDW 09/11/2024
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.09.12 13:20:30 -05'00'09/12/24
RBDMS JSB 091624
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).
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)
API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer
501032043900 3S-14 PA Plugged and Abandoned
501032044000 3S-10 PA Plugged and Abandoned Yes - P&A Yes - P&A
501032044400 3S-15 PA Plugged and Abandoned
501032044500 3S-16 ACTIVE Injector Miscible Water Alternating Gas
501032044600 3S-22 PA Plugged and Abandoned
501032043000 3S-07 ACTIVE Oil
501032043200 3S-09 ACTIVE Injector Miscible Water Alternating Gas Yes Yes
501032043300 3S-18 PA Plugged and Abandoned
501032044800 3S-17 PA Plugged and Abandoned
501032044801 3S-17A PA Plugged and Abandoned
501032045000 3S-08 PA Plugged and Abandoned Yes-P&A Yes-P&A
501032045001 3S-08A PA Plugged and Abandoned Yes-P&A Yes-P&A
501032045002 3S-08B PA Plugged and Abandoned Yes - P&A Yes - P&A
501032045003 3S-08C ACTIVE Oil Yes Yes
501032045060 3S-08CL1 ACTIVE Oil Yes Yes
501032036100 PALM 1 PA Plugged and Abandoned
501032036101 3S-26 PA Plugged and Abandoned Yes-P&A Yes-P&A
501032080100 3G-27 ACTIVE Injector Produced Water
501032045070 3S-08CL1PB1 PA Plugged and Abandoned
501032045200 3S-21 PA Plugged and Abandoned
501032045300 3S-23 PA Plugged and Abandoned
501032045301 3S-23A SUSP Suspended
501032045400 3S-06 PA Plugged and Abandoned
501032045401 3S-06A PA Plugged and Abandoned
501032045600 3S-24 PA Plugged and Abandoned
501032045601 3S-24A PA Plugged and Abandoned
501032045800 3S-03 SUSP Suspended
501032046000 3S-19 SUSP Suspended
501032045602 3S-24B PA Plugged and Abandoned
501032084700 3S-701 PA Plugged and Abandoned
501032084701 3S-701A ACTIVE Injector Produced Water
501032084800 3S-704 ACTIVE Oil
501032088400 3S-718 ACTIVE Producer Yes Yes
501032069500 3S-620 ACTIVE Oil
501032073500 3S-613 ACTIVE Injector Produced Water
501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas
501032077400 3S-611 ACTIVE Oil
501032077470 3S-611PB1 PROP Proposed
501032084400 3S-615 ACTIVE Oil
501032084200 3S-625 ACTIVE Injector Produced Water
501032086800 3S-624 ACTIVE Oil
501032087000 3S-606 ACTIVE Injector Produced Water
501032087500 3S-610 ACTIVE Oil
501032086400 3S-617 ACTIVE Injector Produced Water
501032087800 3S-626 PROP Proposed
501032087870 3S-626PB1 PROP Proposed
SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3)
There are no freshwater aquifers or underground sources of drinking water within a one-half mile radius of the
current or proposed wellbore trajectory.
None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), “That portions of the aquifers on the North Slope
described by a ¼ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field”.
SECTION 4 – PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20
AAC 25.283(a)(4)
There are no water wells located within one-half mile of the current or proposed wellbore trajectory and
fracturing interval.
A water well sampling plan is not applicable.
SECTION 5 – DETAILED CEMENTING AND CASING INFORMATION
20 AAC 25.283(a)(5)
All casing is cemented and tested in accordance with 20 AAC 25.030.
See Wellbore schematic for casing details.
SECTION 6 – ASSESSMENT OF EACH CASING AND CEMENTING OPERATION
TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC
25.283(a)(6)
Casing & Cement Assessments:
The 10-3/4” casing cement pump report on 8/15/2024 shows that the original job pumped as designed. The
cement job was pumped with 505 barrels of 10.7 ppg lead cement and 61 barrels 15.8 ppg tail cement, displaced
with 9.8 ppg mud. The plug bumped at 900 psi and the floats held. Cement returned to surface.
The 7-5/8” casing cement report on 8/24/2024 shows that the job was pumped as designed, indicating competent
cementing operations. The cement job was pumped with 69 barrels of 15.3 ppg cement. The plugs bumped with
pressure increasing to 1059 psi and held for 5 minutes. Floats held. A cement bond log indicates competent
cement with a cement top @ 7,261’ MD (3,671’ TVD).
The 4-1/2” liner cement report on 9/3/2024 shows that the job was pumped as designed, indicating competent
cementing operations. The cement job was pumped with 245 barrels of 15.3 ppg cement. The cement was
displaced with 9.5 ppg mud and the plugs bumped at 2,200 psi and held for 5 minutes. Floats held.
Summary
All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is
isolated.
Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that
this well can be successfully fractured within its design limits.
ppg
Cement returned to surface.
Estimated cement top for the production liner is 10,040' MD (4,283' TVD).SFD
gp
cement top @ 7,261’ MD (3,671’ TVD).
SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST
CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7)
On 8/17/2024 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes
On 8/24/2024 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes.
On 9/4/2024 the 7-5/8” casing, 4-1/2” production liner, and liner top packer were pressure tested to 3,850 psi
for 30 minutes.
The 4-1/2” tubing will be pressure tested to 4,550 psi for 30 minutes prior to RDMO.
The 7-5/8” casing by 4-1/2” tubing annulus will be pressure tested to 3,850 psi for 30 minutes prior to RDMO.
AOGCC Required Pressures [all in psi]
Maximum Predicted Treating Pressure (MPTP) 7,075
Annulus pressure during frac 3,500
Annulus PRV setpoint during frac 3,600
7-5/8" Annulus pressure test 3,850
4-1/2" Tubing pressure Test 4,075
Electronic PRV 8,075
Highest pump trip 7,575
SECTION 8 – PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE,
WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8)
Size Weight, ppf Grade API Burst, psi API Collapse, psi
10-3/4” 45.5 L-80 5,209 2,474
7-5/8” 29.7 L-80 6,885 4,789
7-5/8” 33.7 P-110S 10,860 7,870
4-1/2” 12.6 P-110S 11,590 9,210
4-1/2” 12.6 L-80 8,430 7,500
Table 2: Wellbore pressure ratings
Stimulation Surface Rig-Up
Kuparuk 10K Frac Tree
SECTION 9 – DATA FOR FRACTURING ZONE AND CONFINING
ZONES 20 AAC 25.283(a)(9)
CPAI has formed the opinion, based on seismic, well, and other subsurface information
currently available that:
The fracturing zone, the gross Coyote interval, has an average thickness greater than 600 ft TVD over the course
of the lateral section of well 3S-722, from where it intersects the top formation at 8,742’ MD to TD of the well.
The Coyote interval is comprised of thinly interbedded sandstone and siltstone layers. The sandstone and
siltstone components are litharenites, moderately to well sorted, and are of the size range from silt to very fine
sand. The estimated fracture pressure for the Coyote interval is approximately 12.9-16.1 ppg.
The overlying confining interval is represented by distal toe of slope (deep marine) claystone with thin siltstone
beds of the Cretaceous Seabee Formation. This interval is present in thicknesses of more than 350’ TVD across
the area. The top of the confining intervals starts at ~3,514’ TVDSS (7,015’ MD). Currently, there is no data of
the fracture gradient of the overlying Seabee formation, however, CPAI estimates the fracture closure pressure
gradient to be 0.67 psi/ft based on diagnostic fracture injection testing (DFIT). The fracture gradient of the
overlying Seabee formation will be greater than the fracture closure pressure gradient of 0.67 psi/ft.
The lower confining interval of the Coyote comprises slope to basin floor mudstones of the Torok
formation, which are present in thicknesses greater than 300’ TVD across the area. This same confining
zone forms the upper confining interval of the Kuparuk River Unit, Torok Oil Pool. The estimated fracture gradient
for this section ranges from 15-18 ppg. The base of the gross Coyote interval is estimated from seismic to be at
4,950 ft TVDSS at the heel, and 4,660’ ft TVDSS at the toe of the well.
The estimated formation pressure within the Coyote interval is 1,800 – 1,840 psi at a depth of 4,150’ TVDSS.
Clarification regarding fracture pressure provided in CPAI email dated 9/10/2024.SFD
SECTION 10 –LOCATION, ORIENTATION AND A REPORT ON MECHANICAL
CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC
25.283(a)(10)
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:
3S-26:This well has been plugged and abandoned per state regulations with AOGCC witness of cement at
surface for all strings and marker plate in place as of 10/29/2023. Perforate, wash, and cement operations were
performed with a CBL completed to show good cement through the interval of 4,706’ MD to 4,850’ MD. A CIBP
was placed at 4,833’ MD with cement tagged at 3,786’ MD and pressure tested to 1,500 psi. Cement was then
placed from 3,770’ MD to surface with returns observed at surface.
Source:201-040 - Laserfiche WebLink (alaska.gov)
3S-09:This well is an active Kuparuk injector. The cement report from 12/15/2002 shows that 63 bbls of 15.8ppg
Class G cement was pumped and no losses were observed during the job. However, the top of cement is below
the Coyote formation. The outer annulus of this well (7” x 9-5/8”) will be monitored during the stimulation of 3S-
718. Given the longitudinal orientation of the planned stimulation operations, it is not foreseen that the hydraulic
fractures will intersect the 3S-09 in the Coyote sand.
3S-08/3S-08A/3S-08B:This well is a plugged and abandoned Kuparuk C sand producer. The mainbore (3S-08)
and re-drill (3S-08A) were plugged back prior to drilling the 3S-08B due to poor reservoir quality. The 3S-08 was
plugged back with 42 bbls of 15.8 ppg Class G cement by balance plug on 3/8/2003. TOC was not tagged but
calculated to be at 11,200’MD / 5,681’TVD. The 3S-08A was plugged back with 48.5 bbls of 15.8 ppg Class G
cement by balance plug on 3/13/2003. TOC was not tagged but calculated to be at 7,968’MD / 5,701’TVD or
161’TVD above the Kuparuk C sand. The 3S-08B was completed with 7”casing set at 8,802’MD. The 7”
production casing was cemented with 52.6 bbls of 15.8 ppg Class G cement. No losses were observed during
the job, plugs bumped with 1900 psi, and floats held. The calculated TOC is 6,473’MD / 4,531’TVD.
3S-08C:This well was sidetracked from 3S-08B. A cast iron bridge plug was set in the 7”production casing at
4,663’MD / 2,885’TVD and tested to 3,000 psi for 30 minutes. The 7”production casing was then cut and pulled
from 4,463’MD (200’MD below the surface shoe) to surface. A 17ppg kick off plug was pumped and tagged at
3,826’MD. Intermediate casing was then run and set at 8,795’MD. It was cemented with 38 bbls of 15.8 ppg
Class G cement on 12/19/2007. No losses were observed during the job, plugs were bumped with 1,800 psi,
and floats held. The calculated top of cement is 7,113’MD / 4,929’TVD which is below the Coyote formation.
The outer annulus of this well (7” x 9-5/8”) will be monitored during the stimulation of 3S-722. Given the
longitudinal orientation of the planned stimulation operations, it is not foreseen that the hydraulic fractures will
intersect the 3S-08C in the Coyote sand.
3S-08CL1:This well is an active Kuparuk C sand producer that was sidetracked from the 3S-08C via coil tubing
drilling. The 3S-08CL1 was kicked off from the 4-1/2”slotted liner at 10,700’MD. Intermediate casing is the same
as the above in the 3S-08C well.
3S-10:This well has been plugged and abandoned per state regulations with AOGCC witness of cement at
surface for all strings and marker plate in place as of 10/21/2023. Perforate, wash, and cement operations were
performed with a CBL completed to show good cement through the interval of 5,704’MD to 5,815’MD. A CIBP
was placed at 5,884’MD with cement tagged 5,197’MD and pressure tested to 1,700 psi. An additional 143 bbls
of cement was laid in the production casing with cement top tagged at 2,123’MD and witnessed by AOGCC on
10/3/23. The production casing was then perforated from 2,070’to 2,075’MD and cement circulated to surface.
3S-718: This well is a Coyote producer offset to the 3S-722 injector. This well was completed in August 2024
and has been fracture stimulated and is awaiting a coil tubing clean out and flowback. The 7-5/8” casing cement
report on 7/28/2024 shows that the job was pumped as designed, indicating competent cementing operations.
The cement job was pumped with 66 barrels of 15.3 ppg cement. The plugs bumped with pressure increasing to
1080 psi and held for 5 minutes. Floats held. A cement bond log indicates competent cement with a cement top
@ 7,651’ MD (3,736’ TVD) above the Coyote. Also, the 4-1/2” liner cement report on 8/6/2024 shows that the
job was pumped as designed, indicating competent cementing operations. The cement job was pumped with
202 barrels of 15.3 ppg cement. The cement was displaced with 9.3 ppg mud and the plugs bumped at 1,600
psi and held for 5 minutes. Floats held.
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
one fault transects the Coyote reservoir within one half mile radius of the 3S-722 wellbore trajectory. The fault
intersects the 3S-722 wellbore trajectory at its heel. This fault is interpreted to have approximately 8’ of throw at
this location (8,688’ MD). This fault has a SW – NE strike and is downthrown to the SE.
The interpreted fault should not affect overburden integrity and therefore its presence should not interfere with
containment. If there is any indication that a fracture has intersected the mapped fault (or any other faults
unmapped to date) during fracturing operations, ConocoPhillips will go to flush and terminate the stage
immediately.
SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM
20 AAC 25.283(a)(12)
3S-722 was completed in 2024 as a horizontal injector in the Coyote formation. The well was completed with a
4.5” tubing upper completion and a 4.5” liner with a dart actuated sliding sleeve lower completion. The first stage
will be pumped through a toe initiator valve in the toe of the lateral. After the 1st stage, a dart will be dropped to
shift open the 2nd stage sleeve and isolate the first stage. The 2nd stage will then be pumped and a dart will be
dropped for each subsequent stage. These darts will provide isolation from the previous stage and allow
fracturing from the toe of the well towards the heel.
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 the frac tree was tested to 10,000 psi on the rig.
3. 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.
4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC.
5. MIRU 25 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank
volume plus 10%. Load tanks with 100ºF seawater.
6. MIRU HES Frac Equipment.
7. PT Surface lines to 10,000 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 to 3,500 psi as the tubing pressures up.
10. Pump the frac job per the attached Halliburton pump schedule at 20-22 bpm with a maximum expected
treating pressure of 7,075 psi.
11. RDMO Halliburton Equipment. Freeze Protect the tubing and wellhead if not able to complete following
the flush.
12. The well is ready for post-frac well prep/production tree installation and flowback (after Slickline and
Coiled Tubing Cleanout).
Stage Job Size
(lb)
Top MD
(ft)
Top TVD
(ft)
Propped Half-
Length (ft)
Fracture
Height (ft)
Avg Fracture
Width (in)
1 304,000 18,588 4,006 660 180 0.341
2 304,000 18,092 4,010 690 180 0.338
3 304,000 17,597 4,012 680 180 0.353
4 304,000 17,103 4,018 670 180 0.336
5 304,000 16,607 4,025 630 180 0.345
6 304,000 16,110 4,030 650 180 0.345
7 304,000 15,614 4,015 600 200 0.345
8 304,000 15,119 4,028 650 190 0.342
9 304,000 14,622 4,031 590 190 0.373
10 304,000 14,126 4,040 660 185 0.351
11 304,000 13,631 4,049 610 180 0.343
12 304,000 13,135 4,052 600 180 0.347
13 304,000 12,640 4,049 580 185 0.352
14 304,000 12,225 4,056 670 180 0.376
15 304,000 11,729 4,059 640 180 0.344
16 304,000 11,277 4,062 590 180 0.350
17 304,000 10,779 4,061 650 180 0.340
18 304,000 10,241 4,060 630 180 0.341
19 304,000 9,787 4,062 680 180 0.347
20 304,000 9,299 4,062 610 180 0.352
Disclaimer Notice:
KRU 3S-722
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
NOTE: Based on tiltmeter and image log analysis in this area, CPAI expects the induced fractures to grow
along the trend of NNW-SSE. (See email from M. Woodard dated Sept. 11, 2024.) SFD
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT 70.3940498LEASE3S-722SALES ORDERBHST (°F)105LONG-150.19809FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In2:41:32 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:41:32 1-3 Shut-In Shut-In2:36:46 1-4 30# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 2:36:46 1.00 2.00 0.40 30.00 3.00 0.151-5 30# Linear Scour 100M 0.50 20 8,000 190 195 4,000 0:09:44 2:30:46 1.00 2.00 0.40 30.00 3.00 0.151-6 30# Linear Displacement 20 12,722 303 303 0:15:09 2:21:02 1.00 2.00 0.40 30.00 3.00 0.151-7 30# Linear Step Rate Test 20 8,400 200 200 0:10:00 2:05:53 1.00 2.00 0.40 30.00 3.00 0.151-8 30# Linear DFIT 20 1,680 40 40 0:02:00 1:55:53 1.00 2.00 0.40 30.00 3.00 0.151-9 Shut-In Shut-In1:53:53 1-10 Shut-In Shut-In1:53:53 1-11 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:53 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.151-12 30# Delta Frac Pad 20 16,690 397 397 0:19:52 1:40:33 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.151-13 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.151-14 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.151-15 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.151-16 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.151-17 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.151-18 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.151-19 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.151-20 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.151-21 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.152-1 30# Delta Frac Minifrac - Treatment 20 12,345 294 294 0:14:42 2:23:21 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.152-2 30# Linear Minifrac - Flush 20 12,404 295 295 0:14:46 2:08:39 1.00 2.00 0.40 30.00 3.00 0.152-3 Shut-In Shut-In1:53:53 2-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:53 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.152-5 30# Delta Frac Pad 20 16,690 397 397 0:19:52 1:40:33 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.152-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.152-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.152-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.152-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.152-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.152-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.152-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 2.003.00 0.152-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 2.003.00 0.152-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-1 30# Delta Frac Pad 20 16,690 397 397 0:19:52 1:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:37:04 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:27:20 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.153-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:22:20 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:13:19 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:03:55 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:48:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:34:33 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:24:29 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-10 30# Delta Frac Flush 20 12,088 288 288 0:14:23 0:17:53 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.153-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 3-12 Shut-In Shut-InInterval 1Coyote@ 18588.4 - 18592.1 ft 104 °FInterval 2Coyote@ 18091.93 - 18094.23 ft 104 °FInterval 3Coyote@ 17597.08 - 17599.38 ft 104 °FLiquid AdditivesDry Additives50-103-20886Conoco Phillips - 3S-722Planned Design1
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT 70.3940498LEASE3S-722SALES ORDERBHST (°F)105LONG-150.19809FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-208864-1 Shut-In Shut-In1:58:39 4-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:58:39 4-3 Shut-In Shut-In1:53:53 4-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:53:53 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.154-5 30# Delta Frac Pad 20 16,690 397 397 0:19:52 1:40:33 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.154-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.154-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.154-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.154-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.154-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.154-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.154-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.154-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.154-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-2 30# Delta Frac Conditioning Pad 100M 0.500 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.155-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.155-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.156-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.156-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:52:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-2 30# Delta Frac Conditioning Pad 100M 0.5000 20 8,000 190 195 4,000 0:09:44 1:35:34 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:25:49 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.157-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:20:49 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:11:49 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:02:25 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:47:11 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:33:03 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:22:58 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.157-10 30# Linear Flush 20 10,821 258 258 0:12:53 0:16:23 1.00 2.00 0.40 30.00 3.00 0.157-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 7-12 Shut-In Shut-InInterval 4Coyote@ 17103.01 - 17105.31 ft 104.1 °FInterval 5Coyote@ 16606.78 - 16609.08 ft 104.2 °FInterval 6Coyote@ 16110.17 - 16112.47 ft 104.2 °FInterval 7Coyote@ 15614.28 - 15616.58 ft 104.3 °FConoco Phillips - 3S-722Planned Design2
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT 70.3940498LEASE3S-722SALES ORDERBHST (°F)105LONG-150.19809FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-208868-1 Shut-In Shut-In1:55:54 8-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:55:54 8-3 Shut-In Shut-In1:51:08 8-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:08 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.158-5 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.158-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.158-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.158-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.158-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.158-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.158-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.158-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.158-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.158-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.000.159-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.159-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1510-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1510-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1510-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1510-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1510-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1510-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1510-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1510-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1510-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1510-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1511-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:51:11 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1511-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:34:03 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1511-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:24:19 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1511-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:19:19 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1511-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:10:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1511-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 1:00:54 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1511-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:45:40 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1511-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:31:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1511-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:21:28 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1511-10 30# Linear Flush 20 9,553 227 227 0:11:22 0:14:52 1.00 2.00 0.40 30.00 3.00 0.1511-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 11-12 Shut-In Shut-InInterval 9Coyote@ 14622.05 - 14624.35 ft 104.3 °FInterval 10Coyote@ 14125.72 - 14128.02 ft 104.4 °FInterval 11Coyote@ 13630.66 - 13632.96 ft 104.4 °FInterval 8Coyote@ 15118.79 - 15121.09 ft 104.3 °FConoco Phillips - 3S-722Planned Design3
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT 70.3940498LEASE3S-722SALES ORDERBHST (°F)105LONG-150.19809FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2088612-1 Shut-In Shut-In1:55:54 12-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:55:54 12-3 Shut-In Shut-In1:51:08 12-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:08 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1512-5 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1512-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1512-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1512-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1512-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1512-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.000.1512-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.000.1512-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.000.1512-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.000.1512-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1513-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1513-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1513-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1513-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1513-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1513-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1513-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1513-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1513-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1513-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1514-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1514-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1514-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1514-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1514-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1514-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1514-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1514-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1514-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1514-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1515-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:49:44 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1515-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:32:36 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1515-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:22:52 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1515-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:17:52 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1515-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:08:51 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1515-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:59:27 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1515-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:44:13 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1515-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:30:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1515-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:20:01 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1515-10 30# Linear Flush 20 8,337 199 199 0:09:56 0:13:26 1.00 2.00 0.40 30.00 3.00 0.1515-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 15-12 Shut-In Shut-InInterval 12Coyote@ 13135.32 - 13137.62 ft 104.4 °FInterval 13Coyote@ 12640.42 - 12642.72 ft 104.5 °FInterval 14Coyote@ 12224.78 - 12227.08 ft 104.5 °FInterval 15Coyote@ 11729.21 - 11731.51 ft 104.5 °FConoco Phillips - 3S-722Planned Design4
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT 70.3940498LEASE3S-722SALES ORDERBHST (°F)105LONG-150.19809FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst Buffer Gel Breaker Breaker BiocideInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2088616-1 Shut-In Shut-In1:55:54 16-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:55:54 16-3 Shut-In Shut-In1:51:08 16-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:51:08 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-5 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1516-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1516-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1516-14 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1517-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1517-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1517-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1517-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1517-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1517-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1517-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1517-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1517-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1517-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1518-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:37:48 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1518-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:20:41 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1518-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:10:56 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1518-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:05:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1518-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 0:56:56 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1518-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:47:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1518-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:32:18 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1518-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1518-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:08:05 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1518-10 30# Delta Frac Spacer and Dart Drop 20 1,260 30 30 0:01:30 0:01:30 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1519-1 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:48:15 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1519-2 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:31:08 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1519-3 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:21:23 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1519-4 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:16:23 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1519-5 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:07:23 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1519-6 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:57:59 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1519-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:42:45 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1519-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:28:37 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1519-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:18:32 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1519-10 30# Linear Flush 20 7,096 169 169 0:08:27 0:11:57 1.00 2.00 0.40 30.00 3.00 0.1519-11 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 19-12 Shut-In Shut-In20-1 Shut-In Shut-In2:05:59 20-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:05:59 20-3 Shut-In Shut-In2:01:13 20-4 30# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 2:01:13 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1520-5 30# Delta Frac Pad 20 14,385 342 342 0:17:07 1:47:53 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1520-6 30# Delta Frac Conditioning Pad 100M 0.50 20 8,000 190 195 4,000 0:09:44 1:30:45 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1520-7 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 3,850 92 100 7,700 0:05:00 1:21:01 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1520-8 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 6,400 152 180 25,600 0:09:01 1:16:01 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1520-9 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 6,200 148 187 37,200 0:09:24 1:07:00 0.45 1.00 1.10 2.00 0.40 30.00 1.003.00 0.1520-10 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 9,700 231 303 67,900 0:15:14 0:57:36 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1520-11 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 8,700 207 281 69,600 0:14:08 0:42:22 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1520-12 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 6,000 143 200 54,000 0:10:04 0:28:14 0.45 1.00 1.10 2.00 0.40 30.00 1.00 3.00 0.1520-13 30# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 3,800 90 131 38,000 0:06:35 0:18:10 0.45 1.00 1.10 2.00 0.40 30.00 1.003.000.1520-14 30# Linear Flush 20 6,784 162 162 0:08:05 0:11:35 1.00 2.00 0.40 30.00 3.00 0.1520-15 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 20-16 Shut-In Shut-In1,552,667 36,968 43,431 6,084,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-61,450,7916,000,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)87,05684,000Initial Design Material Volume 652.9 1,537.8 1,595.9 3,075.7 615.1 46,135.4 1,460.6 4,613.5 230.7-14,820- 0.2552 Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 Cat-3 BA-20 WG-36 OPTIFLO-HTE OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm ppm-Max Additive Rate 0.4 0.8 0.9 1.7 0.3 25.2 1.7 2.5 0.1-Min Additive Rate13:18:27 Interval 16Coyote@ 11277.18 - 11279.48 ft 104.5 °FInterval 17Coyote@ 10779.21 - 10781.51 ft 104.5 °FInterval 18Coyote@ 10240.93 - 10243.23 ft 104.5 °FInterval 19Coyote@ 9787.29 - 9789.59 ft 104.5 °FInterval 20Coyote@ 9298.64 - 9300.94 ft 104.5 °FProppant TypeWanli 16/20 Ceramic100M---Fluid Type30# Delta Frac30# LinearProduced WaterFreeze Protect----Conoco Phillips - 3S-722Planned Design5
SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY
PLAN 20 AAC 25.283(a)(13)
After the fracture stimulation, ConocoPhillips (“CPAI”) plans to flowback the well for cleanup purposes for an
estimated 7 to 14 days. Expro will be the flowback company utilized for the flowback. The flowback liquids will
be routed through a portable test separator then onto either CPF3 or Drill Site 3S’s facilities. Once the well’s
flowback liquids meet CPF3 criteria all liquids will be routed to CPF3. CPAI plans to limit the flowback time to
what is necessary to achieve conforming production liquids.
Hydraulic Fracturing Fluid Product Component Information Disclosure
9/3/2024
Alaska
HARRISON BAY
50-103-20886-00-00
CONOCOPHILLIPS
3S 722
-150.1981
70.3941
NAD83
none
Oil
4285
1367464
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
Produced Water
(Density 8.5)Operator Base Fluid Density = 8.50
SEAWATER (SG
8.52)Operator Base Fluid Density = 8.52
AS-7 ANTI-
SLUDGING
AGENT Halliburton Anti-sludging Agent
BA-20
BUFFERING
AGENT Halliburton Buffer
BC-140 X2 Halliburton Initiator
BE-6(TM)
Bactericide Halliburton Microbiocide
CAT-3
ACTIVATOR Halliburton Activator
FE-1A
ACIDIZING
COMPOSITION Halliburton Additive
FE-2A Halliburton Additive
HAI-404M Halliburton Corrosion Inhibitor
HYDROCHLORI
C ACID, 10-30%Halliburton Solvent
LoSurf-300D Halliburton Non-ionic Surfactant
LVT-200
Baker
Hughes Additive
MO-67 Halliburton pH Control
OPTIFLO-HTE Halliburton Breaker
OPTIFLO-II
DELAYED
RELEASE
BREAKER Halliburton Breaker
OXYGON Halliburton Oxygen Scavenger
WG-36 GELLING
AGENT Halliburton Gelling Agent
Ceramic Proppant
- Wanli Wanli Proppant
Sand-Common
White-100 Mesh,
SSA-2 Halliburton Proppant
Calcium Chloride Customer Salt Solution
OPT 2002-2054 ResMetrics Tracer
Flow Insurance
Copper
Patina
Energy Tracer
Formate Brine MI Swaco n
WPT 1001-1052 ResMetrics Tracer
Ingredients Water 7732-18-5 100.00%68.69874%11623359
Corundum 1302-74-5 65.00%19.59299%3315000
Mullite 1302-93-8 45.00%13.56437%2295000
Crystalline silica, quartz 14808-60-7 100.00%0.43026%72798
Water 7732-18-5 100.00%0.28142%47614
Guar gum 9000-30-0 100.00%0.24246%41023
Calcium Chloride 10043-52-4 100.00%0.05910%10000
EDTA/Copper chelate Proprietary 30.00%0.03743%6333
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%0.03711%6280
Monoethanolamine borate 26038-87-9 100.00%0.03462%5859
Hydrochloric acid 7647-01-0 60.00%0.03429%5802
Ammonium acetate 631-61-8 100.00%0.02600%4399
Ammonium persulfate 7727-54-0 100.00%0.02424%4102
Sodium hydroxide 1310-73-2 30.00%0.02405%4070
Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01856%3140
Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01856%3140 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Ethylene glycol 107-21-1 30.00%0.01039%1758
Potassium Formate 590-29-4 100.00%0.00875%1480
Acetic acid 64-19-7 60.00%0.00812%1374
Walnut hulls NA 100.00%0.00763%1291 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Oxylated phenolic resin Proprietary 30.00%0.00727%1231 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Ammonium chloride 12125-02-9 5.00%0.00624%1056
Oxyalkylated phenolic resin Proprietary 10.00%0.00619%1047 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Naphthalene 91-20-3 5.00%0.00309%524
Poly(oxy-1,2-ethanediyl), alpha-(4-
nonylphenyl)-omega-hydroxy-,
branched 127087-87-0 5.00%0.00309%524
Flow Insurance Copper Proprietary 100.00%0.26100%442 Patina Energy Product Stewardship
Test@patina
energy.com 7205324886
Polyamine Proprietary 30.00%0.00229%388 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Ammonia 7664-41-7 1.00%0.00125%212
2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00121%205
Sodium chloride 7647-14-5 1.00%0.00080%136
Methanol 67-56-1 30.00%0.00077%131
Glycol Ether Proprietary 85.00%0.00068%116 ResMetrics Product Stewardship
info@resmetri
cs.com 8325921900
1,2,4 Trimethylbenzene 95-63-6 1.00%0.00062%105
Acetic anhydride 108-24-7 100.00%0.00053%90
Water 7732-18-5 100.00%0.00050%86
Distillates (petroleum),
hydrotreated light 64742-47-8 100.00%0.00041%70
Hemicellulase 9025-56-3 5.00%0.00038%65
Citric acid 77-92-9 60.00%0.00037%63
Ethoxylated alcohol Proprietary 60.00%0.00031%52 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Benzenesulfonic acid, dodecyl-,
compd. with morpholine 12068-08-5 60.00%0.00031%52
Confidential Proprietary 20.00%0.00024%42 ResMetrics Product Stewardship
info@resmetri
cs.com 8325921900
C.I. pigment Orange 5 3468-63-1 1.00%0.00024%42
Ethylene Glycol 107-21-1 20.00%0.00017%29
Aldehyde Proprietary 30.00%0.00015%25 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Cycloaliphatic alkyoxylate Proprietary 30.00%0.00015%25 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Isopropanol 67-63-0 30.00%0.00015%25
Cured acrylic resin Proprietary 1.00%0.00008%13 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
C.I. Pigment Red 5 6410-41-9 1.00%0.00008%13
Sodium erytorbate 6381-77-7 100.00%0.00006%10
Fatty acids, tall oil Proprietary 10.00%0.00005%9 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Polyethoxylated fatty amine salt 61791-26-2 10.00%0.00005%9
Benzylheteropolycycle salt Proprietary 10.00%0.00005%9 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
1-(Benzyl)quinolinium chloride 15619-48-4 10.00%0.00005%9
Ethoxylated alcohols Proprietary 10.00%0.00005%9 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
2,7-Naphthalenedisulfonic acid, 3-
hydroxy-4-[(4-sulfor-1-
naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%6
Morpholine 110-91-8 5.00%0.00003%5
Sodium chloride 7647-14-5 5.00%0.00003%5
Ethoxylated alkyl amines Proprietary 5.00%0.00002%5 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com
281-871-
6226
Potassium acetate 127-08-2 1.00%0.00001%1
Sodium iodide 7681-82-5 1.00%0.00000%1
Ammonium phosphate 7722-76-1 1.00%0.00000%1
* 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
Fracture Date
State:
County:
API Number:
Operator Name:
Well Name and Number:
Longitude:
Latitude:
Long/Lat Projection:
Indian/Federal:
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
From:Woodard, Madeline E
To:Davies, Stephen F (OGC)
Cc:Dewhurst, Andrew D (OGC); Loepp, Victoria T (OGC); Wallace, Chris D (OGC); Hobbs, Greg S
Subject:RE: [EXTERNAL]RE: KRU 3S-722 (PTD 224-066, Sundry 324-508) - Questions
Date:Tuesday, September 10, 2024 12:18:50 PM
Attachments:image001.png
image002.png
image003.png
3S-722 Surface Cement Report.pdf
3S-722 Surface Cement Time Log.pdf
Steve,
Sorry to miss the surface job report. We do not have logs of the surface cement job, but 255bbls of good cement returns were observed at surface. I have included the
WellView reports from the surface job, please let me know if there is anything additional needed.
Please also see my answers to your questions below in red.
CPAI’s application was received on 9/6. Is the estimated start date of 9/13 listed on the application accurate? 9/13 is the scheduled start date of the stimulation
operations. The rig secured the well and moved in the afternoon on 9/6 and there are no SIMOPS concerns in accessing the well. At last week’s check-in meeting
our upcoming program of drilling immediately followed by stimulation operations for Coyote (3S) and Nuna (3T) was discussed and how CPAI can more
efficiently provide frac sundry information to meet the future schedule.
Please confirm the estimated fracture pressure range for the Coyote interval and the value provided for the Seabee Formation. (The values provided in the
application are 12.9 -16.1 ppg and greater than 0.67 psi/ft, respectively.)
If the Coyote fracture pressure is indeed 16.1 ppg, how can CPAI be confident that the upper confining Seabee Formation will not be fractured? This range
is based on FIT/LOT data from the wells we have drilled (3S-701A, -704, -718, -722) and is lower than our formation breakdown pressure (FBP), as shown
in the pressure vs. volume plots below. Our DFITs (Pc) we have collected in the frac jobs to date have been at the 0.62 psi/ft range in the Coyote.
Based on our dynamic fracture modeling the fracture could propagate into the overlying interval, which was observed in the 3S-24B vertical well. The
log results from the 3S-24B showed 34’ of potential fracture growth into the overburden compared to the ~350’ of TVT of the overlying zone.
Additionally, geomechanical testing completed on the overburden core proved there is no remaining conductivity within a fracture that propagates into
the overlying zone due to proppant embedment and interaction of the frac fluid with the rock. Post-frac injection will be at or below the fracture closure
pressure (Pc) of the overlying seal which is less than the fracture propagation pressure (FPP).
If the Coyote fracture pressure is indeed 16.1 ppg, how can CPAI be confident that the lower confining Torok Formation will not be fractured if the fracture
gradient for the Torok is less than 16.1 ppg? (The range given in the application is 15-18 ppg.) Based on our dynamic modeling we do not expect to grow
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.
into the underlying seal. We are targeting the upper 200’ of the Coyote interval for development.
Thanks,
Madeline
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Tuesday, September 10, 2024 11:36 AM
To: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Wallace, Chris D (OGC)
<chris.wallace@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>
Subject: RE: [EXTERNAL]RE: KRU 3S-722 (PTD 224-066, Sundry 324-508) - Questions
Thank you, Madeline. Since our review time is short, my request was broad. Is information for the surface casing cement job included as well?
Thanks again,
Steve Davies
AOGCC
From: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com>
Sent: Tuesday, September 10, 2024 9:54 AM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Wallace, Chris D (OGC)
<chris.wallace@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>
Subject: RE: [EXTERNAL]RE: KRU 3S-722 (PTD 224-066, Sundry 324-508) - Questions
Steve,
I am working on a response to your questions below.
I sent an email with the SonicScope log and cement evaluation and the cementing report on Friday, 9/6. Is there additional information outside of those attachments
you are looking for?
Thanks,
Madeline
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Tuesday, September 10, 2024 9:47 AM
To: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Wallace, Chris D (OGC)
<chris.wallace@alaska.gov>
Subject: [EXTERNAL]RE: KRU 3S-722 (PTD 224-066, Sundry 324-508) - Questions
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.
Madeline,
In addition to my questions below, to expedite processing of CPAI’s Sundry Application to fracture 3S-722, could you please provide electronic images (in pdf format)
of all cement evaluation logs recorded in 3S-722 along with all cementing reports and corresponding daily operations summaries that describe all cementing
operations in the well?
Thanks for Your Help and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please
delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov.
From: Davies, Stephen F (OGC)
Sent: Monday, September 9, 2024 7:53 PM
To: madeline.e.woodard@conocophillips.com
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: KRU 3S-722 (PTD 224-066, Sundry 324-508) - Questions
Madeline,
I’m reviewing CPAI’s Sundry Application to fracture stimulate KRU 3S-722.
CPAI’s application was received on 9/6. Is the estimated start date of 9/13 listed on the application accurate?
Please confirm the estimated fracture pressure range for the Coyote interval and the value provided for the Seabee Formation. (The values provided in the
application are 12.9 -16.1 ppg and greater than 0.67 psi/ft, respectively.)
If the Coyote fracture pressure is indeed 16.1 ppg, how can CPAI be confident that the upper confining Seabee Formation will not be fractured?
If the Coyote fracture pressure is indeed 16.1 ppg, how can CPAI be confident that the lower confining Torok Formation will not be fractured if the
fracture gradient for the Torok is less than 16.1 ppg? (The range given in the application is 15-18 ppg.)
Thanks and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete
it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________KUPARUK RIV UNIT 3S-722
JBR 10/16/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Tested with 5" and 7 5/8" test joints, Choke Line flange was tighted nad passed retest, Flange on Stack below rams was
tightened and passed retest. Precharge Bottles = 1 @ 900psi, 13 @ 1000psi and 1 @ 1050psi
Test Results
TEST DATA
Rig Rep:Z. Coleman / K. HaugOperator:ConocoPhillips Alaska, Inc.Operator Rep:A. Door / M. Aurthur
Rig Owner/Rig No.:Doyon 142 PTD#:2240660 DATE:8/16/2024
Type Operation:DRILL Annular:
250/3500Type Test:INIT
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopBDB240817161951
Inspector Brian Bixby
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 10
MASP:
1457
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
1 FPCH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8"P
#1 Rams 1 7 5/8"P
#2 Rams 1 Blind/Shear P
#3 Rams 1 3 1/2"x6"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8"P
HCR Valves 2 3 1/8"P
Kill Line Valves 3 3 1/8"P
Check Valve 0 NA
BOP Misc 1 Flange FP
System Pressure P3000
Pressure After Closure P1800
200 PSI Attained P10
Full Pressure Attained P54
Blind Switch Covers:PYES
Bottle precharge P
Nitgn Btls# &psi (avg)P6@1966
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P17
#1 Rams P7
#2 Rams P7
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9999
9
9
9
FP
FP
Choke Line flange was tighted Flange on Stack below rams was
tightened
DOYON RIG 142 ACCUMULATOR DRAW DOWN WORKSHEET
3S-722 DATE: 8/16/24
ACCUMULATOR PSI 3000
MANIFOLD PSI 1350
FUNCTION RAMS/ANNULAR/ HCR'S, DON'T FUNCTION BLINDS! FUNCTION ONE RAM
TWICE LET PRSSURE STABILIZE AND RECORD BACK UP NITROGEN BOTTLE'S
ACCUMULATOR PSI 1800
NITROGEN BOTTLE'S PSI
BOTTLE # 1 2000
BOTTLE # 2 2000
BOTTLE # 3 2000
BOTTLE # 4 2000
BOTTLE # 5 2000
BOTTLE # 6 1800
AVG FOR 6 BOTTLE'S =1966
TURN ON ELEC. PUMP, SEC FOR 200 PSI =10
TURN ON AIR PUMP'S
TIME FOR FULL CHARAGE =54
Annular 17
UPR 7
Blind/ Shear 7
LPR 7
KILL HCR 1
Choke HCR 1
Test Bope 7-5/8” & 5” 250/3500 On The Annular
Both Test Joints
250/5000 On Everything Else
1. 7-5/8” TJ, Annular 250/3500
2. 7-5/8” TJ, UPR’s CMV’s #’s 1, 12, 13, 14, Upper IBOP
250/5000
3. CMV’s #’s 9, 11, Lower IBOP, 250/5000
4. CMV’s #’s 8, 10, 5” Dart valve 250/5000
5. CMV’s #’s 6, 7, 5” TIW #1 250/5000
6. CMV’s #’s 2, 5, 5” TIW #2 250/5000
7. Manual Choke Super Choke / 250/ 3000
8. HCR Choke 250/5000
9. Manual Choke 250/5000
Remove 7-5/8”Test Joint
10. CMV’s #’s 3, 4, Blind rams, 250/5000
Install 5” Test joint
11. 5” TJ Annular 250/3500
12. 5” TJ 3-1/2” X 6” Lower VBR’s, 250/5000
13.Rig floor Kill Valve
14. Mezz Kill Valve
15.HCR Kill Valve ( Mud Cross )
16.Manual Kill Valve ( Mud Cross )
Koomey Draw Down
Annular=2, UPR’s=1, Blind/Shears=1, LPR’s=1, Top Drive IBOP’s=2, Dart valve=1, TIW’s=2, Mud Cross=6,
CMV’s=14, Super hyd Choke=1, Manual Choke=1, / Total 32
Test Bope 7-5/8” & 5” 250/3500 On The Annular
Both Test Joints
250/5000 On Everything Else
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
Chris Billon
Wells Engineering Manager
ConocoPhillips Alaska, Inc.
PO Box 100306
Anchorage, AK 99510-0360
Re: Kuparuk River Field, Torok Oil Pool, KRU 3S-722
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 224-066
Surface Location: 2725' FSL, 3584 FWL, SENW, Sec. 18, T12N, R8E
Bottomhole Location: 1051' FSL, 2790' FWL, SWSE, Sec. 5, T12N, R8E
Dear Mr. Brillon:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this ___ day of July, 2024. 19
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2024.07.19
09:38:30 -08'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address: 6. Proposed Depth: 12. Field/Pool(s):
MD: 18864 TVD: 4194
4a. Location of Well (Governmental Section): 7.Property Designation:
Surface:
Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date:
6/15/2024
Total Depth:9. Acres in Property:14. Distance to Nearest Property:
2489' to ADL025532
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 67 15. Distance to Nearest Well Open
Surface: x-476038 y- 5993862 Zone- 4 28 to Same Pool: 9290' to 3S-704
16. Deviated wells: Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 90 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
42" 20" 94 H-40 Welded 81 39 39 120 120
13.5" 10.75" 45.5 L-80 Hyd563 3647 39 39 3686 2593
9.875" 7.625" 29.7 L80 Hyd563 8252 39 39 8291 4806
9.875" 7.625" 33.7 P110S Hyd563 800 8291 4806 9091 4268
6.5" 4.5" 12.6 P110S Hyd563 9923 8941 5091 18864 4194
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name: Matt Smith
Chris Brillon Contact Email:matt.smith2@cop.com
Wells Engineering Manager Contact Phone:907-263-4324
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Perforation Depth MD (ft): Perforation Depth TVD (ft):
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Authorized Name:
Authorized Title:
Authorized Signature:
Commission Use Only
See cover letter for other
requirements.
Intermediate
Production
Liner
Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft):
Surface
Conductor/Structural
Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks
1110 sx 15.3 ppg w/ frac sleeves
Casing Length Size Cement Volume MD
Total Depth MD (ft): Total Depth TVD (ft):
940sks 10.7ppg, 280sks 15.8ppg
320sks 15.3ppg
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
ConocoPhillips Alaska, Inc. 59-52-180 KRU 3S-722
10 yds
P.O. Box 100360 Anchorage, Alaska, 99510-0360 Coyote (Undefined Oil Reservoir)
2725' FSL, 3584' FWL, SENW S18 T12N R8E ADL380107 / ADL380106
(including stage data)
1474' FSL, 4138' FWL, NESE S17 T12N R8E LONS 01-013
1051' FSL, 2790' FWL, SWSE S5 T12N R8E 2448 / 2437
GL / BF Elevation above MSL (ft):
1877 1457
18. Casing Program:
Stratigraphic Test
No Mud log req'd: Yes No
No Directional svy req'd: Yes No
Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements
BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis
Single Well
Gas Hydrates
No Inclination-only svy req'd: Yes No
Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal
No
No
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Grace Christianson at 9:21 am, May 20, 2024
July 24, 2024
SFD 5/31/2024
224-066
SFD
DSR-5/20/24
An injection order must be issued by AOGCC before injection operations can begin for 3S-722.
Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig
Annular preventer test to 2500 psig
Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval
Surface casing LOT and annular LOT to the AOGCC as soon as available
VTL 7/17/2024
, UM SFD
50-103-20886-00-00
X
($8
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.07.19 09:38:54 -08'00'07/19/24
RBDMS JSB 072324
<Zhϯ^ͲϳϮϮ
Conditions of Approval:
Approval is granted to run the LWD-Sonic on upcoming well with the following provisions:
1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as
soon as they become available. The evaluation is to include/highlight the intervals of competent
cement that CPAI is using to meet the objective requirements for annular isolation, reservoir
isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation
is not acceptable.
2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must
start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC.
Starting the log below the actual TOC based on calculations predicting a different TOC will not
be acceptable.
3. CPAI will provide a cement job summary report and evaluation along with the cement log and
evaluation to the AOGCC when they become available
4. CPAI will provide the results of the FIT when available.
5. Depending on the cement job results indicated by the cement job report, the logs and the FIT,
remedial measures or additional logging may be required.
ConocoPhillips Alaska, Inc.
Post Office Box 100360
Anchorage, Alaska 99510-0360
Telephone 907-276-1215
May 15, 2024
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Application for Permit to Drill 3S-722
Dear Sir or Madam:
ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Coyote Injector well from the 3S drilling pad. The
intended spud date for this well is 6/15/2024. It is intended that Doyon 142 be used to drill the well.
3S-722 will utilize a 13 1/2” surface hole drilled to TD and 10 3/4” casing will be set and cemented to surface. As noted in
section 4 of the attached proposed drilling program, the low maximum anticipated surface pressure of the well allows use of a
three preventer BOPE per 20 AAC 25.035 (e) (1) (A) (i-iii). The fourth preventer will contain solid body pipe rams that will
be sized for the intermediate casing string. The 9 7/8” intermediate hole will be drilled and set in the Coyote reservoir. A 7 5/8”
casing string will be set and cemented from TD to secure the shoe and cover 250’TVD above any hydrocarbon-bearing zones
(Coyote).
The production interval will be comprised of a 6 1/2” horizontal hole that will be geo-steered in the Coyote formation. The well
will be completed as a cemented, fracture stimulated Injector with 4 1/2” liner and frac sleeves. The upper completion will
include a production packer with GLM’s.
It is requested that a variance of the diverter requirement under 20AAC 25.035(h)(2) is granted for well 3S-722. At 3S, there
has not been a significant indication of shallow gas hydrates though the surface hole interval.
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, diverter 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 Matt Smith at 907-263-4324
(matt.smith2@conocophillips.com) or Chris Brillon at 907-265-6120.
Sincerely, cc:
3S-722 Well File / Jenna Taylor ATO 1560
David Lee ATO 1552
Matt Smith Chris Brillon ATO 1548
Drilling Engineer Pat Perfetta ATO 636
Digitally signed by Matthew SmithDN: CN=Matthew Smith, E=matt.smith2
@conocophillips.com, C=USReason: I am the author of this documentLocation:
Date: 2024.05.15 08:55:49-08'00'Foxit PDF Editor Version: 13.0.0
Matthew
Smith
requested that a variance of the diverter requirement
p
fracture stimulated Injector
qq
has not been a significant indication of shallow gas hydrates
qq
onshore Coyote Injector well
Application for Permit to Drill, 3S-722
Saved: 15-May-24
3S-722 PTD
Page 1 of 9
Printed: 15-May-24
3S-722
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 (Requirements of 20 AAC 25.005(c)(13)) ........................................................................ 4
4. Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(3)) ............................................................. 4
5. Diverter System (Requirements of 20 AAC 25.005(c)(7)) ..................................................................................... 5
6. MASP Calculations (Requirements of 20 AAC 25.005(c)(4)) ................................................................................ 5
7. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5)) ............................ 6
8. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) ........................................................... 6
9. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) .................................................................................. 7
10. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) ........................................ 8
11. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) ................................................................................... 8
12. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) ................................................................... 8
13. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) ............................................................................. 8
14. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005 (c)(14)) ......... 8
15. Drilling Hazards Summary ................................................................................................................................. 8
16. Proposed Completion Schematic ..................................................................................................................... 10
1. Well Name (Requirements of 20 AAC 25.005 (f))
The well for which this application is submitted will be designated as 3S-722
2. Location Summary (Requirements of 20 AAC 25.005(c)(2))
Location at Surface 2,725 FSL, 3,584 FWL, SENW S18 T12N R8E, UM
NAD 1927
Northings: 5993862
Eastings:476038
RKB Elevation 67’AMSL
Pad Elevation 28’AMSL
Top of Productive Horizon
(Heel) 1474‘ FSL, 4138‘ FWL, NESE S17 T12N R8E, UM
NAD 1927
Northings: 5992595
Eastings: 481398
Measured Depth, RKB:
9,091
Total Vertical Depth, RKB:4,268
Total Vertical Depth, SS:4,201
Total Depth (Toe) 1051‘ FSL, 2790‘ FWL, SWSE S5 T12N R8E, UM
NAD 1927
Northings: 6002734
Eastings: 480045
Measured Depth, RKB:18,864
Total Vertical Depth, RKB:4,194
Total Vertical Depth, SS:4,130
Pad Layout
Mechanical Integrity of wells within 1/4 mile Area of Review: One well is currently affected. In nearby P&A'd well KRU 3S-08, surface casing was
set at 4,263' MD (-2,605' TVDSS) and cementing operations had 160 barrels of cement returns to surface. KRU 3S-08 was subsequently drilled to 11,642' MD,
then immediately plugged back and redrilled twice to different bottom-hole locations. In KRU 3S-08, the Coyote interval (top at 7,945' MD, -4,140' TVDSS),
which lies about 1,130' from the top Coyote in KRU 3S-722, is uncemented but that interval is isolated by overlying cement Plug #2 that extends from 4,203' to
4,870' MD. The Coyote intervals in redrilled wells KRU 3S-08A and KRU 3S-08B lie more than 1/4 mile from KRU 3S-722. Nearby planned well KRU 3S-718, if
drilled first, will lie within 1/4 mile of KRU 3S-722. If this occurs, mechanical integrity information will be provided to AOGCC in advance of beginning injection
operations in KRU 3S-722 (see email dated May 22, 2024). SFD
3. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13))
The proposed drilling program is listed below. Please refer to Attachment 3: Completion Schematic.
1. MIRU Doyon 142 onto 3S-722
2. Rig up and test riser, dewater cellar as needed.
3. Drill 13 1/2” hole to the surface casing point as per the directional plan.
4. Run and cement 10 3/4” surface casing to surface.
5. Install BOPE and MPD equipment.
6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr regulatory notice).
7. Pick up and run in hole with 9 7/8” drilling BHA to drill the intermediate hole section.
8. Chart casing pressure test to 3000 psi for 30 minutes.
9. Drill out 20’ of new hole and perform LOT. Maximum LOT to 18 ppg. Minimum LOT required to drill ahead is 11.5
ppg EMW.
10. Drill 9 7/8” hole to section TD, setting pipe in the Coyote Reservoir. (LWD Program: GR/RES).
11. Run 7 5/8” casing and cement to a minimum of 500’ MD or 250’ TVD above any hydrocarbon bearing zones
(cementing schematic attached). Pressure test casing if possible on plug bump to 4000 psi.
12. Test BOPE to 250 psi low / 4,000 psi high (24-48 Regulatory notice).
13. Pick up and run in hole with 6 1/2” drilling BHA. Log top of cement with sonic tool in recorded mode.
14. Chart casing pressure test to 4,000 psi for 30 minutes if not tested on plug bump.
15. Drill out shoe track and 20 feet of new formation. Perform LOT to a maximum of 16 ppg. Minimum required leak-off
value is 11.5 ppg EMW.
16. Drill 6 1/2” hole to section TD (LWD Program: GR/RES/Den/Neu).
17. Pull out of hole with drilling BHA. Review cement job details and sonic log TOC.
18. Run 4 1/2” liner with toe valve, frac sleeves and liner hanger to TD. Cement into place
19. Run 4 1/2” upper completion with glass disk, production packer, landing nipple, downhole gauge, and gas lift
mandrels. Space out and land tubing hanger with pre-installed and pre-tested BPV.
20. Pressure test hanger seals to 3,850 psi.
21. Pressure test against the glass plug to set production packer, test tubing to 3,850 psi, chart test.
22. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test.
23. Install HP-BPV and test to 2500 psi.
24. Nipple down BOP.
25. Install tubing head adapter assembly. N/U tree and test to 5000 psi/10 minutes.
26. Freeze protect down tubing and annulus.
27. Secure well. Rig down and move out.
Please note – This well will be frac’d
4.Blowout Prevention Equipment (Requirements of 20 AAC 25.005(c)(3))
Please reference BOP schematics on file for Doyon 142.
Doyon 142 will use a BOPE stack equipped with an annular preventer, fixed 7 5/8” solid body rams, blind/shear rams and
variable rams while drilling and running casing in the intermediate section of 3S-722.
3S-722 has a MASP of 1,456 psi in the intermediate hole section using the methodology in section 6 MASP calculations.
With a MASP less than 3000 psi ConocoPhillips classifies the operation as a Class 2.
(LWD Program: GR/Res) SFD
LWD Program: GR/RES
This well will be frac’d
sonic
LWD Program: GR/RES/Den/Neu
Per 20AAC 25.035.e.a.A:
For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least
three preventers, including:
i. One equipped with pipe rams that fit the size of drill pipe, tubing or casing begin used, except that
pipe rams need not be sixed to bottom-hole assemblies and drill collars.
ii. One with blind rams
iii. One annular type
Intermediate Drilling/Casing Production
Proposed Configuration: Proposed Configuration:
Annular Preventer (iii) Annular Preventer
7 5/8” fixed rams during drilling Intermediate VBRs in Upper Cavity
Blind/Shear Rams (ii) Blind/Shear Rams
VBRs (i) VBRs in Lower Cavity
5. Diverter System (Requirements of 20 AAC 25.005(c)(7))
It is requested that a variance of the diverter requirement under 20 AAC 25.035(h)(2) is granted. At 3S, there has not been
significant indication of shallow gas or gas hydrates through the surface hole interval. There is 1 previously drilled well
(3S-08) within 500’ of the proposed 3S-722 surface shoe location. This well did not encounter any significant indication of
shallow gas or gas hydrates.
6. 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)
Csg Setting Depth
MD/TVD(ft)
Fracture
Gradient (ppg)
Pore pressure
(psi)
ASP Drilling
(psi)
20 97 / 97 10.9 54 56
10 3/4 3,686 / 2,593 12.5 1,160 1,426
7 5/8 9,091 / 4,268 13.5 1,909 1,456
4 1/2 18,864 / 4,194 13.0 1,876 n/a
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:
Recommend granting diverter variance request per 20 AAC 20.035(h)(2) based on records review of Palm 1,
KRU 3S-08, KRU 3S-620, and KRU 3S-718. SFD
At 3S, there has not beenqq()()
significant indication of shallow gas or gas hydrates through the surface hole interval.
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
FPP = 0.4525 x TVD
1. ASP CALCULATIONS
1. Drilling below 20” conductor
ASP = [(FG x 0.052) – 0.1] D
= [(10.9 x 0.052) – 0.1] x 97 = 56 psi
OR
ASP = FPP – (0.1 x D)
= 1,160 – (0.1 x 2,593 ) = 900 psi
2.Drilling below 10.75” surface casing
ASP = [(FG x 0.052) – 0.1] D
= [(12.5 x 0.052) – 0.1] x 2,593 = 1,426 psi
OR
ASP = FPP – (0.1 x D)
= 1,909 – (0.1 x 4,268 ) = 1,482 psi
3.Drilling below 7.625” intermediate casing
ASP = [(FG x 0.052) – 0.1] D
= [(13.0 x 0.052) – 0.1] x 4,268 = 2,569 psi
OR
ASP = FPP – (0.1 x D)
= 1,876 – (0.1 x 4,194 )= 1,456 psi
(B) data on potential gas zones;
The well bore is not expected to penetrate any shallow 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
7. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005(c)(5))
Drill out the casing shoe and perform LOT/FIT as per the procedure that ConocoPhillips Alaska has on file with
the Commission.
8. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6))
Casing and Cementing Program
Csg/Tbg
OD (in)
Hole Size
(in)
Weight
(lb/ft) Grade Conn. Cement Program
20 42 94 H-40 Welded Cemented to surface with 10 yds slurry, or driven
not expected to penetrate any shallow gas zones
10 3/4 13 1/2 45.50 L-80 Hyd563 Cement to Surface
7 5/8 9 7/8 29.70
33.70
L80
P110S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper
most producing zone (Coyote)
4 1/2 6 1/2 12.60 P110S Hyd563 Cemented liner with frac sleeves
Cementing Calculations
10 3/4” Surface Casing run to 3,686 ’ MD / 2,593 ’ TVD
Cement 3,686 MD to 3,186 (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 3,186' to surface with 10.7 ppg
Arctic Lite Crete. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1,824 ’
MD), zero excess in 20” conductor.
Lead slurry from 3,186’ MD to surface with Arctic Lite Crete @ 10.7 ppg
Total Volume = 2,734ft3 => 940 sx of 10.7 ppg Class G + Add's @ 2.92 ft3 /sk
Tail slurry from 3,686 MD to 3,186’ MD with 15.8 ppg Class G + Add's
Total Volume = 316 ft3 => 280 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk
7 5/8” Intermediate Casing run to 9091’ MD / 4,268 ’ TVD
Top of slurry is designed to be at 7,853 ’ MD, which is 250’ TVD above the prognosis shallowest hydrocarbon bearing
zone, Coyote. If a shallower hydrocarbon zone of producible volumes is encountered while drilling, a 2-stage cement
job will be performed to isolate this zone. Assume 40% excess annular volume.
Tail slurry from 9,091 MD to 7,853’ MD with 15.3 ppg Class G + Add's
Total Volume = 393 ft3 => 320 sx of 15.3 ppg Class G + Add's @ 1.23 ft3/sk
4.5” Production Liner run to 18,864 ’ MD / 4,194 ’ TVD
Top of slurry is designed to be at 8,941’ MD, which is at the liner top hanger set a minimum of 150’ inside the
intermediate casing. Assume 15%% excess annular hole volume, and 0% excess cased hole volume.
Tail slurry from 18,864 ’ MD to 8,941 MD with 15.3 ppg Class G + Add's
Total Volume = 1,364 ft3 => 1,110 sx of 15.3 ppg Class G + Add's@ 1.23 ft3/sk
9. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8))
Surface Intermediate Production
Hole Size in. 13 1/2 9 7/8 6 1/2
Casing Size in. 10 3/4 7 5/8 4 1/2
Density PPG 9.0 – 10.5 9.0 – 10.0 9.0 – 10.0
PV cP 20-50 8-15 7-12
YP lb./100 ft2 30 - 80 20 - 30 15 - 25
Funnel Viscosity s/qt.
250 – 300 to
base perm
200-300 to TD
40-60 35-50
Initial Gels lb./100 ft2 30 - 50 8 - 15 5- 10
10 Minute Gels lb./100 ft2 50 - 70 <20 7 - 15
API Fluid Loss cc/30 min. N.C. – 15.0 < 10.0 < 6.0
HPHT Fluid Loss cc/30 min. N/A N/A < 10.0
pH 9.0 – 10.0 9.0 – 10.0 9.5 – 10.5
Surface Hole:
A water based spud mud will be used for the surface interval. Mud engineer to perform regular mud checks to maintain
proper specifications The mud weight will be maintained at N10.0 ppg by use of solids control system and dilutions
where necessary.
Intermediate:
Inhibited water-based mud drill-in fluid. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid
annular velocity. Maintain mud weight at 9-10 ppg for formation stability and be prepared to add loss circulation
material if necessary. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required)
will all be important. The mud will be maintained at 10 ppg before pulling out of the hole.
Production Hole:
The horizontal production interval will be drilled with an inhibited water-based mud drill-in fluid weighted to 9 – 10 ppg.
MPD will be available for adding backpressure during connections if necessary.
Diagram of Doyon 142 Mud System on file.
Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033.
10. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9))
N/A - Application is not for an exploratory or stratigraphic test well.
11. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10))
N/A - Application is not for an exploratory or stratigraphic test well.
12. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11))
N/A - Application is not for an offshore well.
13. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12))
Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission.
14. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC
25.005 (c)(14))
Waste fluids and cuttings generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II
disposal well at the 1B Facility. If needed, excess cuttings generated will be hauled to Milne Point or Prudhoe Bay Grind
and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored,
tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in
accordance with a permit from the State of Alaska.
15. Drilling Hazards Summary
13 1/2" Hole / 10 3/4” Casing Interval
Event Risk Level Mitigation Strategy
Conductor Broach Low Monitor cellar continuously during interval.
Well Collision Low Follow real time surveys very closely, gyro survey as
needed to ensure survey accuracy.
Gas Hydrates Low If observed – control drill, reduce pump rates and
circulating time, reduce mud temperatures
Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets),
pumping out
Washouts/Hole Sloughing Low Cool mud temperatures, minimize circulating times
when possible
Running sands and gravels Low Maintain planned mud properties, increase mud
weight, use weighted sweeps
9 7/8” Hole / 7 5/8” Liner - Casing Interval
Event Risk Level Mitigation Strategy
Sloughing shale / Tight hole /
Stuck Pipe
Low Good hole cleaning, pre-treatment with LCM, stabilized
BHA, maintain planned mud weights and adjust as
needed, real time equivalent circulating density (ECD)
monitoring
Lost circulation Moderate Reduce pump rates, reduce trip speeds, real time ECD
monitoring, mud rheology, add lost circulation material
Hole swabbing on trips Moderate Reduce trip speeds, condition mud properties, proper
hole filling, pump out of hole, real time ECD monitoring,
Liner will be in place at TD
Abnormal Reservoir Pressure
(Coyote / K3)
Low Well control drills, check for flow during connections,
increase mud weight if necessary
6 1/2” Hole / 4 1/2” Liner - Horizontal Production Hole
Event Risk Level Mitigation Strategy
Lost circulation Moderate Reduce pump rates, real time ECD monitoring,
maintain mud rheology, add lost circulation material
Hole swabbing on trips Moderate 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 Moderate Uniform reservoir pressure along lateral, keep pipe
moving, control mud weight
Running Liner to Bottom Moderate Properly clean hole on the trip out with BHA, perform
clean out run if necessary, utilize super sliders for
weight transfer if needed, monitor T&D real time
Well Proximity Risks:
3S is a multi-well pad. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is
provided in the following attachments.
Drilling Area Risks:
Reservoir Pressure: Offset injection has the potential to increase reservoir pressure over predicted. Although this is unlikely,
the rig will be prepared to weight up if required.
Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate
section.
Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost
circulation if needed.
Good drilling practices will be stressed to minimize the potential of taking swabbed kicks.
H2S on 3S pad – There have been elevated H2S levels noted on the 3S pad post drilling. Lift gas from CPF3 facility has ~200-
250ppm H2S in it. The rig will have H2S sensors which will be tested, escape packs staged around the rig, and personal
monitors will be worn by the core crew members. A detailed emergency operating procedure will be communicated to all
personnel, in the event H2S is encountered
16. Proposed Completion Schematic
H2S on 3S pad
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 39.10 0.00 0.00 39.10 0.00 0.00 0.00 0.00 0.00
2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.50
3 350.00 1.50 140.00 349.99 -1.00 0.84 1.50 140.00 -0.57 Start Build 2.00
4 450.00 3.50 140.00 449.89 -4.34 3.65 2.00 0.00 -2.48 Start Build 2.50
5 1758.57 36.21 140.00 1664.00 -340.23 285.49 2.50 0.00 -193.86 Start 123.94 hold at 1758.57 MD
6 1882.51 36.21 140.00 1764.00 -396.33 332.56 0.00 0.00 -225.83 Start DLS 3.50 TFO -31.16
7 3082.29 74.85 118.99 2435.12 -974.53 1101.61 3.50 -31.16 -439.28 Start 2713.76 hold at 3082.29 MD
8 5796.04 74.85 118.99 3144.50 -2243.86 3392.92 0.00 0.00 -661.45 Start DLS 3.75 TFO -110.20
9 9068.17 82.00 351.88 4264.84 -810.23 5362.97 3.75 -110.20 1452.07 Start Build 2.50
10 9268.17 87.00 351.88 4284.00 -613.21 5334.84 2.50 0.00 1620.39 3S-722 T01 031424 Start 20.00 hold at 9268.17 MD
11 9288.17 87.00 351.88 4285.05 -593.44 5332.02 0.00 0.00 1637.29 Start Build 1.50
12 9539.77 90.77 351.88 4289.93 -344.45 5296.48 1.50 0.00 1850.01 Start 4140.00 hold at 9539.77 MD
1313679.77 90.77 351.88 4234.01 3753.63 4711.48 0.00 0.00 5351.24 Start DLS 1.00 TFO -179.94
1413713.07 90.44 351.88 4233.66 3786.59 4706.78 1.00 -179.94 5379.40 Start 5151.64 hold at 13713.07 MD
1518864.71 90.44 351.88 4194.00 8886.37 3978.76 0.00 0.00 9736.43 3S-722 T02 031424 TD at 18864.71
39 500
500 700
700 900
900 1200
1200 1500
1500 2000
2000 3000
3000 5000
5000 8000
8000 13000
13000 18865
3S-722 wp06 Plan Summary
0
3
Dogleg Severity0 3000 6000 9000 12000 15000 18000
Measured Depth
10-3/4" Surface Casing 7-5/8" Intermediate Casing
4-1/2" Production Liner
15
15
30
30
0
90
180
270
30
210
60
240 120
300
150
330
Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [30 usft/in]
107207
307
407
507
3S-21
107207307
407
506
605
3S-22
109209
309
4083S-23
106206
306
405
613
710
3S-620
97197297
398
497
596
3S-721 (I03) wp04
0
2750
True Vertical Depth0 1500 3000 4500 6000 7500 9000
Vertical Section at 24.12°
10-3/4" Surface Casing
7-5/8" Intermediate Casing 4-1/2" Production Liner
0
30
60
Centre to Centre Separation275 550 825 1100 1375 1650 1925
Measured Depth
Equivalent Magnetic Distance
DDI
7.273
SURVEY PROGRAM
Date: 2022-02-15T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
39.10 1200.00 3S-722 wp06 (3S-722) r.5 SDI_URSA1
1200.00 3670.00 3S-722 wp06 (3S-722) MWD+IFR2+SAG+MS
3670.00 9060.00 3S-722 wp06 (3S-722) MWD+IFR2+SAG+MS
9060.00 18864.71 3S-722 wp06 (3S-722) MWD+IFR2+SAG+MS
Elevation / 24.90
CASING DETAILS
TVD MD
Name
2590.00 3674.77 10-3/4" Surface Casing
4264.84 9068.17 7-5/8" Intermediate Casing
4194.00 18864.71 4-1/2" Production Liner
Mag Model & Date: BGGM2023 01-Jul-24
Magnetic North is 14.18° East of True North (Magnetic Declinat
Mag Dip & Field Strength: 80.63° 57206.97nT
FORMATION TOP DETAILS
TVDPath Formation
1450.00 Top Ugnu
1714.00 Base Perm
2019.00 Top West Sak
2473.00 Base West Sak
2718.00 Campanian Sand (C-80)
3578.00 C-50
4177.00 Fault
4177.00Top Coyote (Nanushuk), K3
By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis
for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance.
Prepared by
SLB DE
Checked by
SLB DEC Mgr
Accepted by
SLB PSD
Approved by
CoP DE
Plan 24.9+39.1 @ 64.00usft (D142)
-15000150030004500True Vertical Depth0 1500 3000 4500 6000 7500 9000Vertical Section at 24.12°10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner10002000300040005000600070008000900010000
11000
12000
13000
1 4000
15000
1600 0
17000
18 00 0
1886 5
0°30°60°75°90°91°
90°
3S-722 wp06
Top UgnuBase PermTop West SakBase West SakCampanian Sand (C-80)C-50FaultTop Coyote (Nanushuk). K33S-722 wp0612:39, May 08 2024Section View
-200002000400060008000South(-)/North(+)-4000 -2000 0 2000 4000 6000 8000 10000West(-)/East(+)3S-722 T01 0314243S-722 T02 03142410-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner50010001500200025003000350 040004194
3S-722 wp063S-722 wp06While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.12:44, May 08 20243ODQ9LHZ
5 4 :
,*- +9:
/,' 5:
&5 :
)):
)) ,. :
4&$+:
.QQA6J?6Q)HE8Q
ECE7E)=>AA>GJQA6J?6Q@C75#LG6HL?Q
#LG6HL?Q+>M9HQ0C>K5Q
#LG6HL?Q,Q)68Q
, Q
, Q
, QNGQ
, ):
,,/ &+ 5 : ! / + :
: " . + :
: " . + :
,2%: ! 1+ :
6.8 9:
) 6) 5&,+: 5%, :
3AAQ, Q
)A6CQ QQ LJ;Q Q
)A6CQ QQ LJ;Q Q
.HL9Q
%>C>BLBQ LHM6KLH9Q
.,' 5:#LG6HL?Q+>M9HQ0C>K5Q'EI=Q,AEG9QA6J?6Q0C>K98Q,K6K9JQ
-:945 *:
,: 56*:
-:,+ :
&5 :
&5 :,4&5&,+:
.,*:
,4&5&,+:+ 2 &+59:
)):
)):,4&5&,+:
#LG6HL?Q,Q)68Q
%6GQ
,
Q
:
:
QLJ;Q
945 *: 56*:%96CQ,96Q$9M9AQ
0J>C<Q3AAQ+9:9H9C79Q)E>CKQ
0J>C<Q<9E89K>7QJ76A9Q:67KEHQ
,4&5&,+:+ 2 &+59:
QLJ;Q
QLJ;Q
F FFQLJ;Q .,6+ : 7 ): QLJ;Q
)) ,1:
$+ 5& 4:
4&$+:
6 &5:,5 4:
04&,+:
2& ): 5&,+:
, Q
, ): * : *-) : 5 :
!!%Q
Q
, NGQ
% 4 :
-5%:
/,*: :
64#:
Q
) +:63 9:,,):.,$. *: 5 :
Q
-5%:
.,*: -5%:,:
64#: 64#:6.8 9: )) ,. :
Q Q , QNGQ, Q
Q Q Q , QNGQ, Q
Q Q Q , QNGQ, Q
Q Q Q , QNGQ, Q
)&+ 5&,+:
Q
Q
&-: +$) :
Q
)$'Q
:
64#:
& :+: -5%:
:
64#:
Q Q
,,): * : * .(4:
H Q, "50+,Q
, "Q0+, Q<OHE%1 Q", 2Q
%1 " +,!%,Q
(2,!Q%1 QQ" +QQ,6<QQPQ
%1 " +,!%,Q
(2,!Q%1 QQ" +QQ,6<QQPQ
%1 " +,!%,Q
(2,!Q%1 QQ" +QQ,6<QQPQ
Q
Q
&. 5&,+:
Q
Q
& ) :5/ +$5%:
D/Q
Q
(&*--Q
/MwMOMuT'10E"*dNvaN=ojR5kPMb,k
kqS^hMwT@TVTqThPT'KddB "
,kemMh~'-jijQj=\_dd_nv*dNvaNciQL4znNozaFH/@TWTpThPT'=dNi & &( zvX0
>qk`TPw'4znNozaA_|UoGi_xL6/@TWTpThPT'=dNi & &( zvX0
C^wT'4znNozaB=NR9ks]@TVTrhPT'EozU
ITbb'B "C{tT~,MbP{bMw^kh6Tw]kS'7_i_fzf-zo|NxzoU
ITbbOkpT'B "
/Tu^Zh'B "}n
>bMhhTSC{tT~
6TMu{pTSHTs^PMb HTs^PMb/kZbTZ+{^bSF{g
/Tmw]3hPb^hMw^kh)^e{w]/Tmw]
9
2
ICTPw^kh @MwT @MwT @MwT
{uY{uY{uY {uY
{uY
;;{uYll{uY;;{uY
&& $$ $ & &""" &
& $$ $ &" &
& $$ $ & & & " &$
& $$ $ $ " $"
& $$ " " $ " "
& $$ &" " "" " $&
& $$ & " "
& $$ &$$ " $
"& $$ " $ " " &
$& $$ &$& $ " " &&&
&& $$ & & $ " ""
" & $$ $ " $ $ &
" & $$ " $ " & $ $ &
" & $$ $ " $ $ $ &
" & $$ " " &&$$ $ "
" & $$ " " $ " $ &"
" & $$ " " $ $
" & $$ " " & " &$ $
" "& $$ &"" "& $ " "
" $& $$ " $$ & $ $ &
" $ & $$ $ " $""$ $ $ $"
!F; %
!F;
" && $$ " &" & $ &
$ & $$ $ " & &
$ & $$ &&$& $ & $ $ & $& "
$ & $$ && $ $ "" & "
$ & $$ &$ $ " $ & $$
$ & $$ &" $ $ &
$ & $$ & $ $ & "&$
$ & $$ & $ " &
$ "& $$ & " $ " & &"
$ $& $$ & $ $ &$"& & $"
$ $ "& $$ & $ $$ " &"$" & "
F/Mw%%! #
>qkS{Pw^kh5^hTp
#F;
F
F
/Tu^ZhFMqZTwu
FMqZTw9MeT
]^ye^uuwMqZTw/^m)hZbT/^m/^p FH/
9
2
I
C]MmT{uY {uY {uY
B "E & $ $$ " &"$"
ndNi\_xvxNo[UxQUixUo
-_oQdUoNR_zv
B "E $ $
ndNi\_xvxNo[UxQUixUo
-_oQdUoNR_zv
.<8?DD
0.000.501.001.502.002.503.003.504.004.505.005.50Separation Factor0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000Measured Depth (2000 usft/in)3S-03/3S-03 3S-08/3S-083S-22/3S-223S-718/3S-71STOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: 3S-722Wellbore: 3S-722Design: 3S-722 wp06
0
35
Centre to Centre Separation0 500 1000 1500 2000 2500
Partial Measured Depth3S-033S-183S-193S-213S-223S-233S-23A3S-243S-24A3S-24B3S-6153S-6203S-6243S-719 (P02) wp053S-721 (I03) wp04Equivalent Magnetic Distance
3S-722 wp06 Ladder View
0
150
300
Centre to Centre Separation0 3000 6000 9000 12000 15000 18000
Measured Depth3S-033S-063S-06A3S-083S-08A3S-08B3S-08C3S-08CL13S-08CL1PB13S-093S-103S-143S-153S-163S-173S-17A3S-183S-193S-213S-223S-233S-23A3S-243S-24A3S-24B3S-26PALM 13S-6063S-6103S-6113S-611PB13S-6123S-6133S-6153S-6173S-6203S-6243S-6253S-6263S-7013S-701A3S-7043S-718 wp063S-705 (I12) wp083S-714 wp073S-719 (P02) wp053S-721 (I03) wp043S-723 wp043S-6263S-626 wp07.1Equivalent Magnetic Distance
SURVEY PROGRAM
Depth From Depth To Survey/Plan Tool
39.10 1200.00 3S-722 wp06 (3S-722) r.5 SDI_URSA1
1200.00 3670.00 3S-722 wp06 (3S-722) MWD+IFR2+SAG+MS
3670.00 9060.00 3S-722 wp06 (3S-722) MWD+IFR2+SAG+MS
9060.0018864.71 3S-722 wp06 (3S-722) MWD+IFR2+SAG+MS
13:16, May 08 2024
CASING DETAILS
TVD MD Name
2590.00 3674.77 10-3/4" Surface Casing
4264.84 9068.177-5/8" Intermediate Casing
4194.00 18864.71 4-1/2" Production Liner
39 500
500 700
700 900
900 1200
1200 1500
1500 2000
2000 3000
3000 5000
5000 8000
8000 13000
13000 18865
3S-722 wp06 TC View
30
30
60
60
90
90
120
120
150
150
0
90
180
270
30
210
60
240 120
300
150
330
Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in]
1324140714831552
1615
3S-03
7851
7890
3S-08108208309
411
512
610
705
3S-14
107207
308
409
509
607
702
794
3S-15
107207308
410511
613
713
811
907
1000
1092
1180
3S-16
108
207
308
408
507
604
698
787
871
3S-17
108
207
308
408
507
604
698
787
871
108208308409
508
606
701
792
878
959
3S-18
108
208308408
507
604
697
786
871
3S-19
107207
307
407
507
607
706
804
900
994
1085
3S-21
107207307407
506
605
702
796
887
974
3S-22
109209
309
408
505
600
690
776
3S-23
106206
306
405
503
597
688
774
108
208
307
406
505
602
697
7893S-24
108
208
307
406
505
602
697
789
108
208
308
407
505
602
697
789
104204303402
500
598
695
791
885
977
10673S-26
104204303402
500
598
695
791
885
977
1067
PALM 1
705
799
890
3S-612
506
609711811
909
1003
1092
1176
1257
3S-613
40103203304406509611712
81391110071097
1184
1266
3S-615
40101201301
403
504
604
702
797
889
978
3S-617
112212312413513613
710
805
897
985
1071
3S-620
40101201
300400
498
594
688
778
864
3S-624
40103203303402
500599696792888981
3S-625
39
100
200
300
398
495
590
682
7713S-626
1205
1291
1371
1445
3S-704
39100200300401503604705806
906
1007
1107
1207
1307
1407
3S-718 wp06
140014861570
1651
3S-705 (I12) wp08
40101201302404
506
606
704
797
3S-714 wp07
97197298398499599
698
796
892
985
1075
1160
3S-719 (P02) wp05
97197297398497
596
692
785
875
960
3S-721 (I03) wp04
97197298400
502
602
699
792
880
3S-723 wp04
39
100
200
300
398
495
590
682
771
100200300
398
496
591
683
773
3S-626 wp07.1
SURVEY PROGRAM
Date: 2022-02-15T00:00:00 Validated: Yes Version:
From To Tool
39.10 1200.00 r.5 SDI_URSA1
1200.00 3670.00 MWD+IFR2+SAG+MS
3670.00 9060.00 MWD+IFR2+SAG+MS
9060.00 18864.71 MWD+IFR2+SAG+MS
CASING DETAILS
TVD MD Name
2590.00 3674.77 10-3/4" Surface Casing
4264.84 9068.17 7-5/8" Intermediate Casing
4194.00 18864.71 4-1/2" Production Liner
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 39.10 0.00 0.00 39.10 0.00 0.00 0.00 0.00 0.00
2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.50
3 350.00 1.50 140.00 349.99 -1.00 0.84 1.50 140.00 -0.57 Start Build 2.00
4 450.00 3.50 140.00 449.89 -4.34 3.65 2.00 0.00 -2.48 Start Build 2.50
5 1758.57 36.21 140.00 1664.00 -340.23 285.49 2.50 0.00 -193.86 Start 123.94 hold at 1758.57 MD
6 1882.51 36.21 140.00 1764.00 -396.33 332.56 0.00 0.00 -225.83 Start DLS 3.50 TFO -31.16
7 3082.29 74.85 118.99 2435.12 -974.53 1101.61 3.50 -31.16 -439.28 Start 2713.76 hold at 3082.29 MD
8 5796.04 74.85 118.99 3144.50 -2243.86 3392.92 0.00 0.00 -661.45 Start DLS 3.75 TFO -110.20
9 9068.17 82.00 351.88 4264.84 -810.23 5362.97 3.75 -110.20 1452.07 Start Build 2.50
10 9268.17 87.00 351.88 4284.00 -613.21 5334.84 2.50 0.00 1620.39 3S-722 T01 031424 Start 20.00 hold at 9268.17 MD
11 9288.17 87.00 351.88 4285.05 -593.44 5332.02 0.00 0.00 1637.29 Start Build 1.50
12 9539.77 90.77 351.88 4289.93 -344.45 5296.48 1.50 0.00 1850.01 Start 4140.00 hold at 9539.77 MD
1313679.77 90.77 351.88 4234.01 3753.63 4711.48 0.00 0.00 5351.24 Start DLS 1.00 TFO -179.94
1413713.07 90.44 351.88 4233.66 3786.59 4706.78 1.00 -179.94 5379.40 Start 5151.64 hold at 13713.07 MD
1518864.71 90.44 351.88 4194.00 8886.37 3978.76 0.00 0.00 9736.43 3S-722 T02 031424 TD at 18864.71
3S-722 wp06AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 1200.00 r.5 SDI_URSA11200.00 3670.00 MWD+IFR2+SAG+MS3670.00 9060.00 MWD+IFR2+SAG+MS9060.00 18864.71 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2590.003674.7710-3/4" Surface Casing4264.849068.177-5/8" Intermediate Casing4194.0018864.714-1/2" Production Liner55101015152020252530300901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [10 usft/in]571071572072573073574074575075573S-21571071572072573073574074565065566056543S-22591091592092593093584083S-2356106156206256306356405105310973S-6155636136627107583S-62047971471972472973483984474975475966443S-721 (I03) wp0439 500500 700700 900900 12001200 15001500 20002000 30003000 50005000 80008000 1300013000 18865From Colour To MD39.10 To 3700.00MD Azi TFace39.10 0.00 0.00250.00 0.00 0.00350.00 140.00 140.00450.00 140.00 0.001758.57 140.00 0.001882.51 140.00 0.003082.29 118.99 -31.165796.04 118.99 0.009068.17 351.88 -110.209268.17 351.88 0.009288.17 351.88 0.009539.77 351.88 0.0013679.77 351.88 0.0013713.07 351.88 -179.9418864.71 351.88 0.00
3S-722 wp06AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 1200.00 r.5 SDI_URSA11200.00 3670.00 MWD+IFR2+SAG+MS3670.00 9060.00 MWD+IFR2+SAG+MS9060.00 18864.71 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2590.003674.7710-3/4" Surface Casing4264.849068.177-5/8" Intermediate Casing4194.0018864.714-1/2" Production Liner2525505075751001001251251501500901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [50 usft/in]78517871789079083S-0839 500500 700700 900900 12001200 15001500 20002000 30003000 50005000 80008000 1300013000 18865From Colour To MD3600.00 To 9100.00MD Azi TFace39.10 0.00 0.00250.00 0.00 0.00350.00 140.00 140.00450.00 140.00 0.001758.57 140.00 0.001882.51 140.00 0.003082.29 118.99 -31.165796.04 118.99 0.009068.17 351.88 -110.209268.17 351.88 0.009288.17 351.88 0.009539.77 351.88 0.0013679.77 351.88 0.0013713.07 351.88 -179.9418864.71 351.88 0.00
3S-722 wp06AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.10 1200.00 r.5 SDI_URSA11200.00 3670.00 MWD+IFR2+SAG+MS3670.00 9060.00 MWD+IFR2+SAG+MS9060.00 18864.71 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2590.003674.7710-3/4" Surface Casing4264.849068.177-5/8" Intermediate Casing4194.0018864.714-1/2" Production Liner454590901351351801802252252702700901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in]39 500500 700700 900900 12001200 15001500 20002000 30003000 50005000 80008000 1300013000 18865From Colour To MD9000.00 To 18865.00MD Azi TFace39.10 0.00 0.00250.00 0.00 0.00350.00 140.00 140.00450.00 140.00 0.001758.57 140.00 0.001882.51 140.00 0.003082.29 118.99 -31.165796.04 118.99 0.009068.17 351.88 -110.209268.17 351.88 0.009288.17 351.88 0.009539.77 351.88 0.0013679.77 351.88 0.0013713.07 351.88 -179.9418864.71 351.88 0.00
3S-722 wp06Spider Plot13:23, May 08 202439.10 To 18864.71Northing (5000 usft/in)Easting (5000 usft/in)303540455055603S-03303540455055603S-0630354045505560303 540455055603S-073035404550553S-083035404550556 03S-08A303540455055603S-08B3035404550553S-08C3035404550553S-08CL13035404550553S-08CL1PB1303540455055603S-09303540455055603S-10303540455055603S-14303540455055603S-15303540455055603S-163035404550553S-17303540455 05 5 60303540455055603S-18303540
455055603S-19303540455055603S-213 0
3 5
4 0
45
5 0
5 5
6 03S-223 0
3 5
4 0
4 5
5 0
5 56 03S-233 0
3 5
4 0
4 5
5 05 53S-23A303540455055603S-24303540455055603S-24A30354 0453S-24B3 035
4 0
4 5
5 0
5 53S-2630354045505560PALM 130354045503S-60630354045503S-61030354045503S-6113S-611PB130354045503S-61230
354045503S-61330354045503S-61530354045503S-61730354045503S-62030354045503S-62430
354045503S-62530354045503S-6263 03 540453S-7013 0
35
403S-701A3 0
3 5 403S-7043035403S-718 wp0630354045503S-602 wp043035403S-703 (P12) wp033035403S-705 (I12) wp083 0 35403S-714 wp073035403S-719 (P02) wp053 0
35403S-721 (I03) wp043 03 5403S-723 wp04303 5403S-722 wp06
3S-722 wp06Spider Plot13:24, May 08 202439.10 To 18864.71Northing (2000 usft/in)Easting (2000 usft/in)303540455055603S-03303540455055603S-0630354045505560303540455055603S-0730354045503S-08303540455055603S-08A303540455055603S-08B3035404550553S-08C3035404550553S-08CL13035404550553S-08CL1PB1303540455055603S-09303540455055603S-10303540455055603S-14303540455055603S-15303540455055603S-163035404550553S-17303540455 0
5 5
60303540455055603S-18303540
453S-1930353S-213 0
3 5
4 0
45
5 0
5 5
6 03S-223 0
3 5
4 0
3S-233 0
3 5
4 0
4 53S-23A3S-243S-24A3S-24B3 035
4 0
4 5
5 0
5 53S-2630354045505560PALM 130354045503S-60630354045503S-6103035403S-6113S-611PB130353S-61230
35403S-61330353S-61530354045503S-617303540453S-62030354045503S-62430
353S-625303540453S-6263 0
3 540453S-7013 0
35
403S-701A3 0
3 5
403S-7043035403S-718 wp0630354045503S-602 wp043035403S-703 (P12) wp033035403S-705 (I12) wp083 0
35403S-714 wp0730353S-719 (P02) wp0530
353S-721 (I03) wp043 0 35403S-723 wp04303 5403S-722 wp06
3S-722 wp06Spider Plot13:25, May 08 202439.10 To 18864.71Northing (700 usft/in)Easting (700 usft/in)20223S-032022243S-0620222420222426283 03234363840423S-072022242628303234363840423S-0820222426283032343638404 244
46485052545 6
58
60
3S-08A20222426283032343638404 244
46485052545658603S-08B20222426283032343638404244464850525456583S-08C20222426283032343638404244464850525456583S-08CL120222426283032343638404244464850525456583S-08CL1PB1203S-09203S-102022243S-14203S-15202224262830323 43 63840424446485052545658603S-163S-173S-183S-193S-213S-223S-233S-23A3S-243S-24A3S-24B2022242628303234
3 6
3 8
4 0
42
4 4
4 63S-26202224262830
3 234
3638PALM 12022243S-60620222426283S-61020223S-61120223S-611PB120223S-6122 0
2 2
3S-6132 0 3S-6152022243S-617203S-620203S-62420223S-6253S-6262 0
222 43S-7012 0
222 43S-701A2 0
2 2
3S-70420222426283032343 638 3S-718 wp0620223S-602 wp042022242628303S-703 (P12) wp032 02 2
2 4
26
3S-705 (I12) wp08203S-714 wp072022243S-719 (P02) wp053S-721 (I03) wp0420223S-723 wp042022242628303234
3 63840423S-722 wp06
3S-722 wp06Spider Plot13:26, May 08 202439.10 To 18864.71Northing (70 usft/in)Easting (70 usft/in)810121416183S-036810123S-066810126810123S-086810123S-08A6810123S-08B6810123S-08C6810123S-08CL16810123S-08CL1PB1243S-14243S-15246810121416182022
384042443S-16243S-172424683S-1824683S-19246810123S-21246
8
10123S-2224683S-2324683S-23A2 4683S-242 4683S-24A2 4683S-24B24681012141 6182022242628
3 0
3 2
3 43S-2624681012141 618202224262830
3 2
PALM 1243S-61224681 0
1 2
1 4
1 6
1 8
3S-613246810121 4
1 6
3S-615246
83S-617246
81012143S-620246
83S-62424681012143S-62524683S-6261 4
1 6
1 8
2 0
3S-7011 4
1 6
1 8
2 0
3S-701A810121 41 6
1 8
3S-7042468101214163S-718 wp06101214161820
2 2
3S-705 (I12) wp08243S-714 wp0724681012143S-719 (P02) wp05246810123S-721 (I03) wp042463S-723 wp042468101214163S-722 wp06
3S-722 wp063S-063S-06A3S-073S-083S-08A3S-08B3S-093S-103S-143S-263S-718 wp063S-703 (P12) wp033-D View3S-722 wp0614:21, May 08 2024
3S-722 wp063S-063S-06A3S-073S-093S-103S-143S-263S-6063S-6113S-6123S-6243S-718 wp063S-602 wp043S-703 (P12) wp033S-705 (I12) wp083-D View3S-722 wp0614:22, May 08 2024
-2500025005000750010000South(-)/North(+) (2500 usft/in)-5000 -2500 0 2500 5000 7500 1000012500 15000West(-)/East(+) (2500 usft/in)4190424042903S-6264190424042903S-626 wp07.14190424042903S-034190424042903S-064190424042903S-06A4190424042903S-074190424042903S-084 1 9 042404290
3S-08A
4 1 9 042404290
3S-08B4190424042903S -08C
4190424042903S-08CL14190424042903S-08CL1PB14190424042903S-094190424042903S-104190424042903S-144190424042903S-154190424042903S-164190424042903S-174190424042903S -17A4190424042903S-184190424042903S-193S-214 1 9 042404290
3 S -2 2 4 1 9 042404290
3 S -2 3
4 1 9 042404290
3S-23A3S-243S-24A3S-24B4 1 9 042404290
3 S -2 6
419042404290PALM 14190424042903S-6064190424042903S-6104190424042903S-6113S-611PB13S-6124190424042903S-6133S-6154190424042903S-6174190424042903S-6204190424042903S-6243S-6254190424042903S-6264190424042903S-7013S-701A3S-7044190424042903S-718 wp064190424042903S-602 wp0441903S-703 (P12) wp033S-705 (I12) wp0841903S-714 wp073S-719 (P02) wp053S-721 (I03) wp0441903S-723 wp044190424042903S-722 wp063S-722 wp06Quarter Mile View13:47, May 08 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3S-722 T01 031424 4284.00 Circle (Radius: 100.00)3S-722 T02 031424 4194.00 Circle (Radius: 100.00)3S-722 T01 QM 4284.00 Circle (Radius: 1350.00)3S-722 T02 QM 4194.00 Circle (Radius: 1350.00)
-1750-1500-1250-1000-750-500South(-)/North(+) (250 usft/in)750 1000 1250 1500 1750 2000 2250 2500 2750West(-)/East(+) (250 usft/in)258026003S-08258026003S-08A25802600
3S-08B258026002580260025802600258026003S-718 wp0610-3/4" Surface Casing258026003S-722 wp063S-722 wp06Surface Casing 500ft r14:18, May 08 2024WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3S-722 T01 031424 4284.00 Circle (Radius: 100.00)3S-722 T02 031424 4194.00 Circle (Radius: 100.00)3S-722 Srf Csg 2590.00 Circle (Radius: 500.00)3S-722 T01 QM 4284.00 Circle (Radius: 1350.00)3S-722 T02 QM 4194.00 Circle (Radius: 1350.00)
3S-722wp06 Surface Location
3S-722wp06 Surface Location
# Schlumberger-Confidential
3S-722wp06 Surface Casing
3S-722wp06 Surface Casing
# Schlumberger-Confidential
3S-722wp06 Top Coyote
3S-722wp06 Top Coyote
# Schlumberger-Confidential
3S-722wp06 Intermediate Csg
3S-722wp06 Intermediate Csg
# Schlumberger-Confidential
3S-722wp06 TD
3S-722wp06 TD
# Schlumberger-Confidential
Certificate Of Completion
Envelope Id: 9BF3AE758DCC491499EC6E459B608226 Status: Completed
Subject: Complete with DocuSign: 1. 3S-722 Permit Combined.pdf
Source Envelope:
Document Pages: 59 Signatures: 1 Envelope Originator:
Certificate Pages: 4 Initials: 0 Matt Smith
AutoNav: Enabled
EnvelopeId Stamping: Disabled
Time Zone: (UTC-06:00) Central Time (US & Canada)
925 N Eldridge Pkwy
Houston, TX 77079
Matt.Smith2@conocophillips.com
IP Address: 138.32.8.5
Record Tracking
Status: Original
5/15/2024 11:56:31 AM
Holder: Matt Smith
Matt.Smith2@conocophillips.com
Location: DocuSign
Signer Events Signature Timestamp
Chris Brillon
chris.l.brillon@cop.com
Security Level: Email, Account Authentication
(None)
Signature Adoption: Pre-selected Style
Using IP Address: 24.237.159.155
Signed using mobile
Sent: 5/15/2024 11:58:36 AM
Viewed: 5/18/2024 10:14:47 AM
Signed: 5/18/2024 10:15:09 AM
Electronic Record and Signature Disclosure:
Accepted: 5/18/2024 10:14:47 AM
ID: 2cb957e5-9557-40e6-b649-a68bbd738236
In Person Signer Events Signature Timestamp
Editor Delivery Events Status Timestamp
Agent Delivery Events Status Timestamp
Intermediary Delivery Events Status Timestamp
Certified Delivery Events Status Timestamp
Carbon Copy Events Status Timestamp
Witness Events Signature Timestamp
Notary Events Signature Timestamp
Envelope Summary Events Status Timestamps
Envelope Sent Hashed/Encrypted 5/15/2024 11:58:36 AM
Certified Delivered Security Checked 5/18/2024 10:14:47 AM
Signing Complete Security Checked 5/18/2024 10:15:09 AM
Completed Security Checked 5/18/2024 10:15:09 AM
Payment Events Status Timestamps
Electronic Record and Signature Disclosure
ELECTRONIC RECORD AND SIGNATURE DISCLOSURE
From time to time, ConocoPhillips (we, us or Company) may be required by law to provide to
you certain written notices or disclosures. Described below are the terms and conditions for
providing to you such notices and disclosures electronically through the DocuSign system.
Please read the information below carefully and thoroughly, and if you can access this
information electronically to your satisfaction and agree to this Electronic Record and Signature
Disclosure (ERSD), please confirm your agreement by selecting the check-box next to ‘I agree to
use electronic records and signatures’ before clicking ‘CONTINUE’ within the DocuSign
system.
Getting paper copies
At any time, you may request from us a paper copy of any record provided or made available
electronically to you by us. You will have the ability to download and print documents we send
to you through the DocuSign system during and immediately after the signing session and, if you
elect to create a DocuSign account, you may access the documents for a limited period of time
(usually 30 days) after such documents are first sent to you. After such time, if you wish for us to
send you paper copies of any such documents from our office to you, you will be charged a
$0.00 per-page fee. You may request delivery of such paper copies from us by following the
procedure described below.
Withdrawing your consent
If you decide to receive notices and disclosures from us electronically, you may at any time
change your mind and tell us that thereafter you want to receive required notices and disclosures
only in paper format. How you must inform us of your decision to receive future notices and
disclosure in paper format and withdraw your consent to receive notices and disclosures
electronically is described below.
Consequences of changing your mind
If you elect to receive required notices and disclosures only in paper format, it will slow the
speed at which we can complete certain steps in transactions with you and delivering services to
you because we will need first to send the required notices or disclosures to you in paper format,
and then wait until we receive back from you your acknowledgment of your receipt of such
paper notices or disclosures. Further, you will no longer be able to use the DocuSign system to
receive required notices and consents electronically from us or to sign electronically documents
from us.
All notices and disclosures will be sent to you electronically
Unless you tell us otherwise in accordance with the procedures described herein, we will provide
electronically to you through the DocuSign system all required notices, disclosures,
authorizations, acknowledgements, and other documents that are required to be provided or made
available to you during the course of our relationship with you. To reduce the chance of you
inadvertently not receiving any notice or disclosure, we prefer to provide all of the required
notices and disclosures to you by the same method and to the same address that you have given
us. Thus, you can receive all the disclosures and notices electronically or in paper format through
the paper mail delivery system. If you do not agree with this process, please let us know as
described below. Please also see the paragraph immediately above that describes the
consequences of your electing not to receive delivery of the notices and disclosures
electronically from us.
How to contact ConocoPhillips:
You may contact us to let us know of your changes as to how we may contact you electronically,
to request paper copies of certain information from us, and to withdraw your prior consent to
receive notices and disclosures electronically as follows:
To contact us by email send messages to: DocuSign.Admin@conocophillips.com
To advise ConocoPhillips of your new email address
To let us know of a change in your email address where we should send notices and disclosures
electronically to you, you must send an email message to us
at DocuSign.Admin@conocophillips.com and in the body of such request you must state: your
previous email address, your new email address. We do not require any other information from
you to change your email address.
If you created a DocuSign account, you may update it with your new email address through your
account preferences.
To request paper copies from ConocoPhillips
To request delivery from us of paper copies of the notices and disclosures previously provided
by us to you electronically, you must send us an email
to DocuSign.Admin@conocophillips.com and in the body of such request you must state your
email address, full name, mailing address, and telephone number. We will bill you for any fees at
that time, if any.
To withdraw your consent with ConocoPhillips
To inform us that you no longer wish to receive future notices and disclosures in electronic
format you may:
i. decline to sign a document from within your signing session, and on the subsequent page,
select the check-box indicating you wish to withdraw your consent, or you may;
ii. send us an email to DocuSign.Admin@conocophillips.com and in the body of such request
you must state your email, full name, mailing address, and telephone number. We do not need
any other information from you to withdraw consent.. The consequences of your withdrawing
consent for online documents will be that transactions may take a longer time to process..
Required hardware and software
The minimum system requirements for using the DocuSign system may change over time. The
current system requirements are found here: https://support.docusign.com/guides/signer-guide-
signing-system-requirements.
Acknowledging your access and consent to receive and sign documents electronically
To confirm to us that you can access this information electronically, which will be similar to
other electronic notices and disclosures that we will provide to you, please confirm that you have
read this ERSD, and (i) that you are able to print on paper or electronically save this ERSD for
your future reference and access; or (ii) that you are able to email this ERSD to an email address
where you will be able to print on paper or save it for your future reference and access. Further,
if you consent to receiving notices and disclosures exclusively in electronic format as described
herein, then select the check-box next to ‘I agree to use electronic records and signatures’ before
clicking ‘CONTINUE’ within the DocuSign system.
By selecting the check-box next to ‘I agree to use electronic records and signatures’, you confirm
that:
x You can access and read this Electronic Record and Signature Disclosure; and
x You can print on paper this Electronic Record and Signature Disclosure, or save or send
this Electronic Record and Disclosure to a location where you can print it, for future
reference and access; and
x Until or unless you notify ConocoPhillips as described above, you consent to receive
exclusively through electronic means all notices, disclosures, authorizations,
acknowledgements, and other documents that are required to be provided or made
available to you by ConocoPhillips during the course of your relationship with
ConocoPhillips.
From:Smith, Matt
To:Davies, Stephen F (OGC)
Cc:Dewhurst, Andrew D (OGC); Perfetta, Patrick J
Subject:RE: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
Date:Wednesday, May 22, 2024 2:37:21 PM
Attachments:image001.png
image002.png
image003.png
image004.png
image (3).png
Hey Steve, see below, I got a bit more clarification on 3S-08. Thanks,
Matt Smith
Drilling Engineer – Kuparuk
700 G ST ANCHORAGE ALASKA, ATO-1566
OFFICE: +1.907.263.4324
CELL: +1.432.269.6432
MATT.SMITH2@COP.COM
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Wednesday, May 22, 2024 12:44 PM
To: Smith, Matt <Matt.Smith2@conocophillips.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
Matt,
Will KRU 3S-722 be pre-produced or will it be flowed back for a short period of time to clean up
the wellbore? Flowed back correct, not pre-produced
Could CPAI please re-check and confirm that the Coyote intercept in 3S-08 does not lie within
¼ mile of the Coyote intercept in 3S-722. On my map the two intercepts appear to be about
1,130’ apart. I’ll also recheck my picks and map. If these intercepts do in fact lie within ¼ mile
of one another, please provide a report on the mechanical condition of 3S-08. The 3S-08 is
P&A’d, and the Coyote penetration is ~1300’ away in that well. Reading through the daily
reports (condensed daily report image attached) it appears they originally drilled this open
hole section in 2003 (red box, which is the intersection in question), then abandoned and
plugged back and drilled the 2 wells in green (3S-08A and 3S-08B) at the same time. Then in
2007, it looks like we abandoned those wells, and drilled 3S-08C, in blue box, and have since
done a coil tubing sidetrack as well in 2019. The active wellbore is 3S-08C, which intersection
points are ~1800’ away in the Coyote. I was able to find this schematic on the AOGCC website
also
Have drilling operations begun on 3S-718? If not, when will those operations begin? Planned
start date is likely ~30-35 days from now, depending on operations on 3S-626 which we’ve
have operational issues on. If 3S-718 will be drilled before 3S-722, AOGCC must be provided
with a report on the mechanical condition of 3S-718 in advance of beginning injection
operations in 3S-722. Yes sir we’ll supply final completions reports etc for 3S-718 once
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.
complete.
Please note that an injection order must be issued by AOGCC before injection operations scan
begin for 3S-722. Yes sir we have submitted a draft application for an AIO and look forward to
progressing that.
Thanks and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil
and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov
From: Smith, Matt <Matt.Smith2@conocophillips.com>
Sent: Wednesday, May 22, 2024 10:46 AM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
Steve, thanks for the note. Please see below. If you have any other questions please let me
know.
Thanks!
Matt Smith
Drilling Engineer – Kuparuk
700 G ST ANCHORAGE ALASKA, ATO-1566
OFFICE: +1.907.263.4324
CELL: +1.432.269.6432
MATT.SMITH2@COP.COM
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Wednesday, May 22, 2024 9:33 AM
To: Smith, Matt <Matt.Smith2@conocophillips.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
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.
Matt,
I’m reviewing CPAI’s Permit to Drill application for KRU 3S-722. I have a question and a
request.
1. What is the well logging program for the surface hole interval? GR/Res
2. I didn’t see an Area of Review analysis for this planned injection well. Per 20 AAC
25.402(c)(15), please provide a report on the mechanical condition of each well that has
penetrated the injection zone within a one-quarter mile radius of KRU 3S-722. If there
are none, please state "none." None – Looking at the ¼ mile view in the directional pack,
it looks as though 3S-08, 3S-26, 3S-09 would fall within this, however at the Coyote
formation, they are not within the ¼ mile. The TVD tick marks on the individual wells
indicate this in the original directional pack, but showed another 3D view below to
illustrate. For 3S-26 and 3S-09 they pass under the wellbore at deeper depths than the
Coyote, and 3S-08 passes above the planned 3S-722 and doesn’t enter the Coyote, until
again outside the ¼ mile.
Top/Base Target Zone (Coyote) in the offsets is outside the ¼ mile radius shown below.
To 3S-09
To 3S-08
Thanks and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil
and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Davies, Stephen F (OGC)
To:Smith, Matt
Cc:Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
Date:Wednesday, May 22, 2024 12:43:00 PM
Attachments:image001.png
image002.png
Matt,
Will KRU 3S-722 be pre-produced or will it be flowed back for a short period of time to clean up
the wellbore?
Could CPAI please re-check and confirm that the Coyote intercept in 3S-08 does not lie within
¼ mile of the Coyote intercept in 3S-722. On my map the two intercepts appear to be about
1,130’ apart. I’ll also recheck my picks and map. If these intercepts do in fact lie within ¼ mile
of one another, please provide a report on the mechanical condition of 3S-08.
Have drilling operations begun on 3S-718? If not, when will those operations begin? If 3S-718
will be drilled before 3S-722, AOGCC must be provided with a report on the mechanical
condition of 3S-718 in advance of beginning injection operations in 3S-722.
Please note that an injection order must be issued by AOGCC before injection operations scan
begin for 3S-722.
Thanks and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil
and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov
From: Smith, Matt <Matt.Smith2@conocophillips.com>
Sent: Wednesday, May 22, 2024 10:46 AM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
Steve, thanks for the note. Please see below. If you have any other questions please let me
know.
Thanks!
Matt Smith
Drilling Engineer – Kuparuk
700 G ST ANCHORAGE ALASKA, ATO-1566
OFFICE: +1.907.263.4324
CELL: +1.432.269.6432
MATT.SMITH2@COP.COM
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Wednesday, May 22, 2024 9:33 AM
To: Smith, Matt <Matt.Smith2@conocophillips.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
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.
Matt,
I’m reviewing CPAI’s Permit to Drill application for KRU 3S-722. I have a question and a
request.
1. What is the well logging program for the surface hole interval? GR/Res
2. I didn’t see an Area of Review analysis for this planned injection well. Per 20 AAC
25.402(c)(15), please provide a report on the mechanical condition of each well that has
penetrated the injection zone within a one-quarter mile radius of KRU 3S-722. If there
are none, please state "none." None – Looking at the ¼ mile view in the directional pack,
it looks as though 3S-08, 3S-26, 3S-09 would fall within this, however at the Coyote
formation, they are not within the ¼ mile. The TVD tick marks on the individual wells
indicate this in the original directional pack, but showed another 3D view below to
illustrate. For 3S-26 and 3S-09 they pass under the wellbore at deeper depths than the
Coyote, and 3S-08 passes above the planned 3S-722 and doesn’t enter the Coyote, until
again outside the ¼ mile.
Top/Base Target Zone (Coyote) in the offsets is outside the ¼ mile radius shown below.
To 3S-09
To 3S-08
Thanks and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil
and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Smith, Matt
To:Davies, Stephen F (OGC)
Cc:Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
Date:Wednesday, May 22, 2024 10:46:39 AM
Attachments:image001.png
image002.png
Steve, thanks for the note. Please see below. If you have any other questions please let me
know.
Thanks!
Matt Smith
Drilling Engineer – Kuparuk
700 G ST ANCHORAGE ALASKA, ATO-1566
OFFICE: +1.907.263.4324
CELL: +1.432.269.6432
MATT.SMITH2@COP.COM
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Wednesday, May 22, 2024 9:33 AM
To: Smith, Matt <Matt.Smith2@conocophillips.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL]KRU 3S-722 (PTD 224-066) - Question and Request
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.
Matt,
I’m reviewing CPAI’s Permit to Drill application for KRU 3S-722. I have a question and a
request.
1. What is the well logging program for the surface hole interval? GR/Res
2. I didn’t see an Area of Review analysis for this planned injection well. Per 20 AAC
25.402(c)(15), please provide a report on the mechanical condition of each well that has
penetrated the injection zone within a one-quarter mile radius of KRU 3S-722. If there
are none, please state "none." None – Looking at the ¼ mile view in the directional pack,
it looks as though 3S-08, 3S-26, 3S-09 would fall within this, however at the Coyote
formation, they are not within the ¼ mile. The TVD tick marks on the individual wells
indicate this in the original directional pack, but showed another 3D view below to
illustrate. For 3S-26 and 3S-09 they pass under the wellbore at deeper depths than the
Coyote, and 3S-08 passes above the planned 3S-722 and doesn’t enter the Coyote, until
again outside the ¼ mile.
Top/Base Target Zone (Coyote) in the offsets is outside the ¼ mile radius shown below.
To 3S-09
To 3S-08
Thanks and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil
and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.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 no greater
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.
COYOTE UNDEFINED OIL
224-066
KUPARUK RIVER
KRU 3S-722
WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3S-722Initial Class/TypeSER / PENDGeoArea890Unit11160On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2240660KUPARUK RIVER, COYOTE UNDF OIL - 490120NA1Permit fee attachedYesSurf Loc & Top Prod Int lie in ADL0380107; TD lies in ADL0380106.2Lease number appropriateYes3Unique well name and numberNACoyote Undefined Oil Pool.4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryYes6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNoAIO required before injection operations begin.14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15All wells within 1/4 mile area of review identified (For service well only)No16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes81' conductor driven18Conductor string providedYesSC set to 3686' MD19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgYesProduction interval will be cemented and completed with frac sleeves22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYesAnti collision analysis complete; no major risk failures26Adequate wellbore separation proposedYesDiverter waiver granted per 20 AAC 25.035(h)(2)27If diverter required, does it meet regulationsYesMax reservoir pressure is 1877 psig(8.6 ppg EMW); will drill w/ 9.0 to 10.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 1457 psig; will test BOPs to 5000 psig initially and subsequently to 4000 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYes33Is presence of H2S gas probableYes34Mechanical condition of wells within AOR verified (For service well only)NoMeasures required: H2S risk high; mitigation discussed; see p. 12.35Permit can be issued w/o hydrogen sulfide measuresYesNormal pressure gradient expected.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/31/2024ApprVTLDate7/15/2024ApprSFDDate5/23/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 7/19/2024
