Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout225-0631. 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:
Kuparuk River Field Torok Oil Pool
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
24020 1724 None
Casing Collapse
Structural
Conductor
Surface 2,470
Intermediate 4,790
Intermediate 7,850
Liner 9,210
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:Allen Eschete
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
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
11,590
Tubing Grade: Tubing MD (ft):
TNT Packer: 11216' MD / 4916' TVD
ZXP: 11354' MD / 4952' TVD
Perforation Depth TVD (ft):
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL025528 / ADL393883 / ADL 393884
225-063
P.O. Box 100360, Anchorage, Alaska 99510-0360 50-103-20921-00-00
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
L-80
TVD Burst
11357
10,860
MD
6,890
5,210
119
2481
4738
119
2739
10540
4-1/2"
4995
20"
10-3/4"
80
7-5/8"10502
2700
907-265-6558
Senior Completions Engineer
KRU 3T-619
4995 24005 4995 None
997
4-1/2"
Allen.Eschete@ConocoPhillips.com
10/1/2025
24005
Halliburton TNT Prod Packer
Baker ZXP, No SSSV
11537
Perforation Depth MD (ft):
50007-5/8"
12652
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 2:18 pm, Sep 16, 2025
Digitally signed by Allen Eschete
DN: OU=ConocoPhillips Alaska, O=Completions Engineering
, CN=Allen Eschete, E=Allen.Eschete@ConocoPhillips.com
Reason: I am the author of this document
Location:
Date: 2025.09.16 14:05:30-08'00'
Foxit PDF Editor Version: 13.1.6
Allen Eschete
325-566
10/1/2025
10-404
SFD 9/23/2025
CDW 09/24/2025
DSR-9/24/25
Fracture Stimulate
VTL 9/25/25JLC 9/25/2025
Gregory C Wilson Digitally signed by Gregory C
Wilson
Date: 2025.09.25 14:23:58 -08'00'09/25/25
RBDMS JSB 092625
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)
Business
Unit ID
Business
Area ID Field Name API * Well Name Status Symbology
Well in Frac Port
1/2 mi Buffer
Open Interval in
Frac Port 1/2 mi
Buffer
NAK NAK NORTH ALASKA EXPLORATION 501032064500 NUNA 1 SUSP Suspended Yes - Suspended Yes - Suspended
NAK NAK NORTH ALASKA EXPLORATION 501032064570 NUNA 1PB1 PA Plugged and Abandoned
NAK OU OOOGURUK UNIT 501032066000 NDST-02 SUSP Suspended
NAK OU OOOGURUK UNIT 501032066070 NDST-02PB1 PA Plugged and Abandoned
KUP TOROK TOROK 501032077400 3S-611 ACTIVE Oil
KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas
KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil
KUP TOROK TOROK 501032087800 3S-626 ACTIVE Injector Miscible Water Alternating Gas
KUP TOROK TOROK 501032087870 3S-626PB1 PA Plugged and Abandoned
KUP TOROK TOROK 501032088200 3T-621 ACTIVE Injector Produced Water
KUP TOROK TOROK 501032088700 3T-603 ACTIVE Oil
KUP TOROK TOROK 501032089000 3T-608 ACTIVE Injector Produced Water
KUP TOROK TOROK 501032089600 3T-612 ACTIVE Injector Produced Water Yes Yes
KUP TOROK TOROK 501032089900 3T-616 ACTIVE Oil Yes Yes
KUP TOROK TOROK 501032089970 3T-616PB1 PROP Proposed Yes Yes
KUP TOROK TOROK 501032089971 3T-616PB2 PROP Proposed
KUP COYOTE COYOTE 501032090500 3T-731 ACTIVE Oil
KUP COYOTE COYOTE 501032090700 3T-730 ACTIVE Injector Produced Water
KUP TOROK TOROK 501032091400 3T-613 ACTIVE Oil Yes Yes
KUP TOROK TOROK 501032091700 3T-605 ACTIVE Oil
KUP TOROK TOROK 501032091800 3T-617 ACTIVE Oil
KUP TOROK TOROK 501032084200 3S-625 ACTIVE Injector Produced Water
KUP TOROK TOROK 501032084400 3S-615 ACTIVE Oil
3T-619 Frac Sundry Well - Wells within 1/2 Mile Buffer of Well Track
SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3)
There are no known underground sources of drinking water within a one-half mile radius of the current or
proposed wellbore trajectory.
See Conclusion number 3 of the Area Injection Order AIO 39 – Kuparuk River – Torok Oil Pool, which states
“The injection interval does not contain freshwater and is not a potential underground source of drinking water.”
Not Applicable: AIO 39 Conclusion 3 applies only to the authorized injection strata within the Kuparuk River, Torok Oil Pool.
However, there are no freshwater sands beneath the surface casing shoes of wells drilled in the 3T Pad area based on examination
of well logs and a quick-look Pickett Plot analysis by AOGCC of a prominent, water-wet sand beneath permafrost and above the
surface casing shoe in nearby well Colville Delta 3 (PTD 185-211--which has open-hole resistivity and porosity well logs) between
1,942' and 1,966' MD (-1,905' to -1,929' TVDSS), yielded TDS values greater than 11,000 mg/l. This sand correlates to the interval in
3T-619 from 2,116' to 2,153' MD (-1,962' to -1,992' TVDSS), which lies about 9,500' to the southeast of Colville Delta 3.
Additional supporting evidence that there are no potential underground sources of drinking water from other resources:
Well 3T-619 lies within acreage that was located inside the former Oooguruk Unit before it was purchased by CPAI and included
within the 12th Expansion of the KRU. According to page 17 of EPA's UIC Class 1 Permit Number AK11009-B for Oooguruk Unit
disposal wells DW-1 and DW-2: “The requirement to monitor the strata overlying the confining zone for fluid movement is waived
since the aquifers at the Oooguruk Unit are too naturally saline to qualify as USDWs (meet “No USDW” criteria).”
Further support is found in Conclusion 14 of AIO 33 for the nearby Oooguruk-Kuparuk Oil Pool also states:
“Formation water salinity calculations by the Commission using log data from four exploratory wells and methods compatible with
the Rwa method endorsed by the EPA confirm that there are no aquifers within the Affected Area that could serve as underground
sources of drinking water.” SFD
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.
Upper Completion
1. 3ea SLB (VanOil) 4.5” x 1" Gas Lift Mandrel
2. HES Opsis Single Downhole Gauge
3. HES 7-5/8" x 4-1/2" TNT Production Packer
4. SLB 3.75" DB Nipple
5. Arsenal Glass Disk (to be shared during frac)
6. HES Self-Aligning Muleshoe with Baker Shear Locator
Lower Completion
1. Baker ZXP Packer and Hanger
2. 21ea Interra Frac Sleeves
3. 2ea Baker Alpha Sleeves
4. Citadel MOAS Shoe
Base Perm
1593' MD /
1560' TVD
Top Coyote
8089' MD / 4088' TVD
Top Torok Oil Pool
(Moraine)
11496' MD / 4990' TVD
Production TOL
ZXP LTP/HGR
6.5” Production Hole
24020' MD / 4995' TVD
Production Liner
4.5" 12.6# P110S H563
Cemented to TOL
3T-619 Moraine Injector Well Plan: As Drilled
W. Dai / A. Eschete
Last Update: 9/3/2025
20" 94# H40 Insulated Conductor
119’ MD/TVD Cemented to Surface
Surface Casing
10.75"45.5# L-80 Hyd563
2738’ MD / 2481' TVD
Cemented to Surface
Lead: 10.7ppg, Tail: 15.8ppg
Int 1 TOC
Fair Cement: 5050' MD / 3304' TVD
Good Cement: 7652’ MD / 3974’ TVD
Intermediate I Casing
7.625"29.7# L80 Hyd563 + 800'
33.7# P110S Hyd563 heavy heel
11537' MD / 5000' TVD
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 report on 08/07/2025 was pumped with 414.8 barrels of 11.0 ppg lead cement and
61 barrels 15.8 ppg tail cement. This was displaced with 234 bbl 9.8 ppg spud mud. The plug bumped and the
floats held.
The 7-5/8” casing cement report on 08/17/2025 shows that the job was pumped as designed, indicating
competent cementing operations. The cement job was pumped with 191 barrels of 14.0 ppg lead cement,
followed with 61 barrels of 15.3 ppg tail cement. This was displaced with 520 barrels of 10.0 ppg NAF. The plug
bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent
cement with a cement top @ 7,652’ MD (3,974’ TVD). The intermediate column of good cement of 437’ MD in
combination with the weaker column of cement in excess of 2600’ MD above meets regulation (AOGCC’s
approval on 09/03/2025).
The 4-1/2” liner cement report on 08/31/2025 shows the job was pumped as designed, indicating competent
cementing operations. No losses were observed. The cement job was pumped with 326 barrels of 13.5 ppg
cement. The cement was displaced with 9.5 ppg CI NaCl brine and the plugs bumped 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.
SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-
TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7)
On 08/09/2025 the 10-3/4” casing was pressure tested to 3,000 psi for 30 minutes
On 08/17/2025 the 7-5/8” casing was pressure tested to 4,000 psi for 30 minutes.
On 09/03/2025 the 4-1/2” tubing was pressure tested to 4,200 psi for 30 minutes.
On 09/03/2025 The 7-5/8” casing by 4-1/2” tubing annulus was pressure tested to 3,850 psi for 30 minutes.
AOGCC Required Pressures [all in psi]
Frac Stage 1 to 22
Maximum Predicted Treating Pressure (MPTP) 7,050
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 4,200
Electronic PRV 8,050
Highest pump trip 7,550
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 2474
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 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 Torok Oil Pool, has an average thickness of approximately 230 ft TVD over the course
of the lateral section of well 3T-619, from where it intersects the top formation at 11,513’ MD (-4,997’ TVDSS) to
the TD of the well. The Torok Oil Pool is comprised of thinly interbedded sandstone, siltstone, and silty shale
layers. The sandstone and siltstone components are litharenites, moderately to well sorted, and very fine
grained. The silty shales are composed of clay-rich, moderately to poorly sorted silt and clay. The estimated
fracture pressure for the Moraine interval is approximately 12.5-13.5 ppg.
The overlying confining interval of the Torok Formation consists of mudstones and siltstones with a thickness of
approximately 900’ TVD along the 3T-619 trajectory. The top of the Torok confining interval in the well starts at
8,344 MD (-4,104 TVDSS). The estimated fracture gradient of the overlying Torok formation is approximately
0.82 psi/ft.
The underlying confining zone below the Base Moraine consists of lower Torok, HRZ, and Kalubik shales totaling
approximately 500’ TVD. The estimated fracture gradient for this section ranges from 15-18 ppg, with the gradient
increasing down section. The Base Moraine is estimated from seismic to be at -5,150’ TVDSS along the length
of the well.
The estimated formation pressure within the Torok Oil Pool is 2,285psi at a depth of 5,200’ TVDSS.
SECTION 10 – LOCATION, ORIENTATION AND A REPORT ON MECHANICAL
CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC
25.283(a)(10)
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:
3T-612: The intermediate casing cement job was pumped with 98 bbls of 14.0ppg lead cement and 58 bbls of
15.3ppg tail cement. Plugs bumped and floats held.
Source: Laserfiche WebLink 224-128
3T-616: The intermediate casing cement job was pumped with 117 bbls of 14.0ppg with BMII lead cement and
58bbls of 15.3ppg tail cement. Plugs bumped and floats held.
Source: Laserfiche WebLink 224-138
3T-616 PB1: The abandonment plug consisted of 42bbls of 16.3ppg cement laid in at the heel of the wellbore
into the 7-5/8” intermediate casing shoe. The cement top was then tagged at 9,065’ MD/5,104’ TVD/5,053’
TVDSS with 12klbs.
Source: Laserfiche WebLink 224-138
Nuna-1: The 7-5/8” casing was cemented in place on 2/16/2012. The cement report indicates that the job was
pumped with 40 bbls 15.8ppg Class G cement. The plugs bumped and partial returns were observed during the
job (pg. 187 at link).
Suspension operations began on 1/18/2023 where a cement retainer was set at 9,062’ CTMD and 65bbls of
Class G cement was pumped through the retainer. Another retainer was placed at 7,965’ MD and 48bbls of
15.8ppg cement was pumped with another 12 bbls laid on top of the retainer. The TOC was tagged at 7,003’ MD
and a MIT-T performed to 1700 psi, witnessed by AOGCC on 3/1/2023. A tubing cut was completed at 6,960’
MD and the 4.5” tubing was then pulled. A CIBP was set at 6,910’ MD and tested to 1,200 psi. Cement was laid
on top of the retainer and tagged at 6,621’ MD two times with 12klbs.
Source: Laserfiche WebLink 211-155
3T-613: The intermediate casing cement job was pumped with 211 bbls of 14.0ppg lead cement and 59 bbls of
15.3ppg tail cement. Plugs bumped and floats held.
Source: Laserfiche WebLink 225-036
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
three faults transect the Torok Oil Pool reservoir within one half mile radius of the 3T-619 wellbore trajectory.
These faults all strike NE-SW and are shown in Plat 1.
Two faults intersect the 3T-619 well trajectory at 12,143’ MD (Fault 1) and 16,996’ MD (Fault 2), respectively,
while the third fault is past the toe of the well and is not intersected. Both intersected faults are upthrown on the
northern side, ~20ft. All faults encountered by the well are difficult to trace on the seismic data, due to a) lack of
fine-scale resolution at the Torok Oil Pool level and b) lack of reflectivity in the overlying Torok shales, the result
of the monotonous shaly lithology. Faults 1 & 2 have the potential to penetrate through the overburden into the
overlying hydrocarbon bearing Coyote Oil Pool; however, Fault 2 is a projection of a fault that appears to be
dying out in the Moraine interval and is not explicitly mapped on seismic. However, due to the shaly overburden
and horizontal stress acting on the fault (interpreted to be 15.8 ppg at the fault’s mapped orientation) the
presence of the faults will not interfere with containment.
If there is any indication that a fracture has intersected any mapped fault (or any other faults unmapped to date)
during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately.
For additional information regarding Fault 3, see attached email dated 9/23/2025. SFD
SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC
25.283(a)(12)
3T-619 was completed in September 2025 as a horizontal injector in the Torok formation. The well is completed
with a 4.5” tubing upper completion and a cemented 4.5” liner with a dart activated sliding sleeve lower
completion. The first stage frac will be pumped through a toe initiator valve in the toe of the lateral. After the 1st
stage, a plug will be dropped to shift open the 2nd stage sleeve and isolate the first stage. A frac will then be
pumped through the 2nd stage. Plugs will continue to be dropped to provide isolation from the previous stage and
open each subsequent stage.
Proposed Procedure:
Halliburton Pumping Services:
1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre-
existing conditions.
2. Ensure the frac tree was tested to ~10,000 psi at 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 2,276’ MD / 2,141’ TVD.
4. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC.
5. MIRU 25 clean insulated Frac tanks (450 bbls usable volume per tank), with a berm surrounding the tanks
that can hold a single tank volume plus 10%. Load tanks with either seawater or treated produced water.
6. MIRU HES Frac Equipment.
7. PT Surface lines to ~9,500 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. Perform DFIT after opening the Alpha Sleeve according to the attached pump schedule. Ensure sufficient
volume is pumped to load the well with Frac fluid, prior to shut down. Resume pumping to pump Frac Stage
1.
11. Pump Frac Stages 2 through 9 by following attached pump schedule at ~37 bpm with a maximum expected
treating pressure of ~7,050 psi.
12. RDMO Halliburton Equipment. Freeze Protect the tubing and wellhead if not able to complete following the
flush.
13. The well is ready for post frac well prep/production tree installation, coiled tubing and flowback for 21 days.
14. Swap the 5k production tree with the frac tree and test the frac tree to 10,000 psi.
15. Take the same steps to pump Frac Stages 10 through 22 as per the pump schedule.
16. The well is ready for post frac well prep/production tree installation, coiled tubing cleanout and flowback.
SECTION 13 – POST-FRACTURE WELLBORE CLEANUP AND FLUID
RECOVERY PLAN 20 AAC 25.283(a)(13)
3T-619 will be frac’d in two stages, so the flowback will also be completed in two phases. The first flowback will
occur after the toe hydraulic fracture and initial coil tubing cleanout. This flowback will last approximately 21
days. After the remaining portion of the well is frac’d, and a cleanout occurs, the second flowback will take
place. This cleanout will last approximately 14 days. The purpose of the toe test is to evaluate liquid
productivity and water cut in the shallower portion of the reservoir intersected by the 3T-619 well. This toe test
will also record toe-stage liquid-productivity-index data and characterize the water-saturation transition zone to
broaden understanding of reservoir behavior in these intervals. The flowback will be completed through a
portable test separator until the fluids clean up to facility spec and all required production data is obtained. The
total flowback length will be ~35 days.
Frac Design Attachments
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-619SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control Gel Breaker BreakerBiocideInterval 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-In1:30:19 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:30:19 1-3 Shut-In Shut-In1:25:33 1-4 30# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 1:25:33 1.00 0.50 1.00 30.00 2.00 2.000.151-5 30# Linear Step Rate Test 20 8,400 200 200 0:10:00 1:19:33 1.00 0.50 1.00 30.00 2.00 2.000.151-6 30# Linear DFIT 20 1,680 40 40 0:02:00 1:09:33 1.00 0.50 1.00 30.00 2.00 2.000.151-7 Shut-In Shut-In1:07:33 1-8 Shut-In Shut-In1:07:33 1-9 30# Hybor G-i Establish Stable Fluid 15 8,400 200 200 0:13:20 1:07:33 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-10 30# Hybor G-i Pad 37 12,720 303 303 0:08:11 0:54:13 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-11 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:46:02 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-12 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 9,000 214 224 9,000 0:06:03 0:38:13 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-13 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 12,000 286 311 24,000 0:08:26 0:32:10 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-14 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 12,000 286 324 36,000 0:08:47 0:23:45 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-15 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,500 179 210 30,000 0:05:42 0:14:58 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-16 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.50 37 6,000 143 172 27,000 0:04:39 0:09:15 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-17 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 4,800 114 140 24,000 0:03:48 0:04:36 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.151-18 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.152-1 30# Linear Pre-Pad 37 12,360 294 294 0:07:57 1:41:36 1.00 0.50 1.00 30.00 2.00 2.000.152-2 30# Hybor G-i Establish Stable Fluid 37 14,885 354 354 0:09:35 1:33:38 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-3 30# Hybor G-i Minifrac - Treatment 37 12,360 294 294 0:07:57 1:24:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-4 30# Linear Minifrac - Flush 37 14,885 354 354 0:09:35 1:16:06 1.00 0.50 1.00 30.00 2.00 2.000.152-5 Shut-In Shut-In1:06:32 2-6 30# Hybor G-i Establish Stable Fluid 15 8,400 200 200 0:13:20 1:06:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-7 30# Hybor G-i Pad 37 12,240 291 291 0:07:53 0:53:12 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-8 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:45:19 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 9,000 214 224 9,000 0:06:03 0:37:31 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 11,250 268 292 22,500 0:07:54 0:31:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 12,450 296 336 37,350 0:09:06 0:23:33 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-12 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 5,625 134 158 22,500 0:04:17 0:14:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-13 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.50 37 4,650 111 133 20,925 0:03:36 0:10:10 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.152-14 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 3,915 93 114 19,575 0:03:06 0:06:34 1.25 0.50 1.00 0.50 30.00 2.00 2.000.152-15 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.50 37 3,300 79 98 18,150 0:02:39 0:03:28 1.25 0.50 1.00 0.50 30.00 2.00 2.000.152-16 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.000.153-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:58:38 1.00 0.50 1.00 30.00 2.00 2.000.153-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:57:17 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-3 30# Hybor G-i Pad 37 11,630 277 277 0:07:29 0:51:53 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:44:24 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 9,000 214 224 9,000 0:06:03 0:36:35 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 11,250 268 292 22,500 0:07:54 0:30:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 10,500 250 283 31,500 0:07:41 0:22:38 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,500 179 210 30,000 0:05:42 0:14:57 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 6,000 143 175 30,000 0:04:44 0:09:14 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 4,500 107 136 27,000 0:03:41 0:04:30 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.153-11 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.000.154-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 1:02:54 1.00 0.50 1.00 30.00 2.00 2.000.154-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 1:01:33 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-3 30# Hybor G-i Pad 37 8,090 193 193 0:05:12 0:56:09 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:50:56 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 6,375 152 159 6,375 0:04:17 0:43:08 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 6,375 152 165 12,750 0:04:29 0:38:50 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 6,000 143 162 18,000 0:04:23 0:34:22 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 6,750 161 189 27,000 0:05:08 0:29:59 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 6,000 143 175 30,000 0:04:44 0:24:50 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 5,250 125 158 31,500 0:04:18 0:20:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.50 37 3,750 89 115 24,375 0:03:08 0:15:48 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.154-12 30# Linear Flush 37 14,246 339 339 0:09:10 0:12:40 1.00 0.50 1.00 30.00 2.00 2.000.154-13 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 4-14 Shut-In Shut-InInterval 1Moraine@ 23832 - 23836.34 ft 136.7 °F"Alpha SleeveInterval 2Moraine@ 23287 - 23291.34 ft 137 °F"Frac Sleeve 1Interval 3Moraine@ 22787 - 22791.34 ft 137.3 °F"Frac Sleeve 2Interval 4Moraine@ 22287 - 22291.34 ft 137.5 °F"Frac Sleeve 3Liquid AdditivesDry AdditivesConoco Phillips - 3T-619Planned Design1
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-619SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control Gel Breaker BreakerBiocideInterval 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 Additives5-1 Shut-In Shut-In0:56:03 5-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 0:56:03 5-3 Shut-In Shut-In0:51:17 5-4 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 0:51:17 1.00 0.50 1.00 30.00 2.00 2.000.155-5 30# Hybor G-i Establish Stable Fluid 15 8,400 200 200 0:13:20 0:49:17 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-6 30# Hybor G-i Pad 37 4,200 100 100 0:02:42 0:35:57 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-7 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:33:15 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,500 36 37 1,500 0:01:01 0:25:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 1,875 45 49 3,750 0:01:19 0:24:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,000 71 81 9,000 0:02:12 0:23:07 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 6,000 143 168 24,000 0:04:34 0:20:55 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-12 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,050 168 205 35,250 0:05:34 0:16:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-13 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 7,500 179 226 45,000 0:06:09 0:10:47 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-14 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 4,500 107 141 31,500 0:03:49 0:04:38 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.155-15 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.156-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:42:42 1.00 0.50 1.00 30.00 2.00 2.000.156-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:41:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-3 30# Hybor G-i Pad 37 4,200 100 100 0:02:42 0:35:57 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:33:15 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,500 36 37 1,500 0:01:01 0:25:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 1,875 45 49 3,750 0:01:19 0:24:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,000 71 81 9,000 0:02:12 0:23:07 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 6,000 143 168 24,000 0:04:34 0:20:55 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,050 168 205 35,250 0:05:34 0:16:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 7,500 179 226 45,000 0:06:09 0:10:47 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 4,500 107 141 31,500 0:03:49 0:04:38 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.156-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.157-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:42:42 1.00 0.50 1.00 30.00 2.00 2.000.157-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:41:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-3 30# Hybor G-i Pad 37 4,200 100 100 0:02:42 0:35:57 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:33:15 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.0000 37 1,500 36 37 1,500 0:01:01 0:25:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 1,875 45 49 3,750 0:01:19 0:24:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,000 71 81 9,000 0:02:12 0:23:07 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 6,000 143 168 24,000 0:04:34 0:20:55 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,050 168 205 35,250 0:05:34 0:16:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 7,500 179 226 45,000 0:06:09 0:10:47 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 4,500 107 141 31,500 0:03:49 0:04:38 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.157-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.158-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:42:42 1.00 0.50 1.00 30.00 2.00 2.000.158-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:41:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-3 30# Hybor G-i Pad 37 4,200 100 100 0:02:42 0:35:57 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:33:15 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,500 36 37 1,500 0:01:01 0:25:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 1,875 45 49 3,750 0:01:19 0:24:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.0000 37 3,000 71 81 9,000 0:02:12 0:23:07 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 6,000 143 168 24,000 0:04:34 0:20:55 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,050 168 205 35,250 0:05:34 0:16:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 7,500 179 226 45,000 0:06:09 0:10:47 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 4,500 107 141 31,500 0:03:49 0:04:38 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.158-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.159-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 1:02:54 1.00 0.50 1.00 30.00 2.00 2.000.159-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 1:01:33 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-3 30# Hybor G-i Pad 37 8,560 204 204 0:05:31 0:56:09 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:50:38 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,900 45 47 1,900 0:01:17 0:42:50 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,375 57 62 4,750 0:01:40 0:41:33 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,800 90 103 11,400 0:02:47 0:39:53 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,600 181 213 30,400 0:05:47 0:37:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 8,930 213 260 44,650 0:07:03 0:31:19 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 9,500 226 287 57,000 0:07:47 0:24:16 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.0000 37 5,700 136 178 39,900 0:04:50 0:16:29 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.159-12 30# Linear Flush 37 12,648 301 301 0:08:08 0:11:38 1.00 0.50 1.00 30.00 2.00 2.000.159-13 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 9-14 Shut-In Shut-InInterval 9Moraine@ 19787 - 19791.34 ft 137.9 °F"Frac Sleeve 8Interval 5Moraine@ 21786 - 21790.34 ft 137.6 °F"Frac Sleeve 4Interval 6Moraine@ 21287 - 21291.34 ft 137.8 °F"Frac Sleeve 5Interval 7Moraine@ 20787 - 20791.34 ft 138 °F"Frac Sleeve 6Interval 8Moraine@ 20287 - 20291.34 ft 137.9 °F"Frac Sleeve 7Conoco Phillips - 3T-619Planned Design2
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-619SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control Gel Breaker BreakerBiocideInterval 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 Additives10-1 Shut-In Shut-In1:19:03 10-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:19:03 10-3 Shut-In Shut-In1:14:18 10-4 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:14:18 1.00 0.50 1.00 30.00 2.00 2.000.1510-5 30# Linear Displace Dart to Seat 15 12,328 294 294 0:19:34 1:12:18 1.00 0.50 1.00 30.00 2.00 2.000.1510-6 30# Linear DFIT 10 840 20 20 0:02:00 0:52:43 1.00 0.50 1.00 30.00 2.00 2.000.1510-7 Shut-In Shut-In0:50:43 10-8 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:50:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-9 30# Hybor G-i Pad 37 8,560 204 204 0:05:31 0:45:19 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-10 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:39:49 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,900 45 47 1,900 0:01:17 0:32:00 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-12 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,375 57 62 4,750 0:01:40 0:30:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-13 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,800 90 103 11,400 0:02:47 0:29:03 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-14 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,600 181 213 30,400 0:05:47 0:26:16 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-15 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 8,930 213 260 44,650 0:07:03 0:20:30 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-16 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 9,500 226 287 57,000 0:07:47 0:13:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-17 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 5,700 136 178 39,900 0:04:50 0:05:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1510-18 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1511-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:52:05 1.00 0.50 1.00 30.00 2.00 2.000.1511-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:50:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-3 30# Hybor G-i Pad 37 8,560 204 204 0:05:31 0:45:19 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:39:49 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,900 45 47 1,900 0:01:17 0:32:00 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,375 57 62 4,750 0:01:40 0:30:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,800 90 103 11,400 0:02:47 0:29:03 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,600 181 213 30,400 0:05:47 0:26:16 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 8,930 213 260 44,650 0:07:03 0:20:30 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 9,500 226 287 57,000 0:07:47 0:13:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 5,700 136 178 39,900 0:04:50 0:05:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1511-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1512-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:52:05 1.00 0.50 1.00 30.00 2.00 2.000.1512-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:50:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-3 30# Hybor G-i Pad 37 8,560 204 204 0:05:31 0:45:19 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:39:49 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,900 45 47 1,900 0:01:17 0:32:00 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,375 57 62 4,750 0:01:40 0:30:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,800 90 103 11,400 0:02:47 0:29:03 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,600 181 213 30,400 0:05:47 0:26:16 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 8,930 213 260 44,650 0:07:03 0:20:30 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 9,500 226 287 57,000 0:07:47 0:13:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 5,700 136 178 39,900 0:04:50 0:05:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1512-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1513-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:52:05 1.00 0.50 1.00 30.00 2.00 2.000.1513-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:50:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-3 30# Hybor G-i Pad 37 8,560 204 204 0:05:31 0:45:19 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:39:49 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,900 45 47 1,900 0:01:17 0:32:00 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,375 57 62 4,750 0:01:40 0:30:43 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 3,800 90 103 11,400 0:02:47 0:29:03 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,600 181 213 30,400 0:05:47 0:26:16 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 8,930 213 260 44,650 0:07:03 0:20:30 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 9,500 226 287 57,000 0:07:47 0:13:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 5,700 136 178 39,900 0:04:50 0:05:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1513-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1514-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 1:01:52 1.00 0.50 1.00 30.00 2.00 2.000.1514-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 1:00:31 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-3 30# Hybor G-i Pad 37 8,560 204 204 0:05:31 0:55:07 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:49:37 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 1,900 45 47 1,900 0:01:17 0:41:48 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,375 57 62 4,750 0:01:40 0:40:31 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.0000 37 3,800 90 103 11,400 0:02:47 0:38:51 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,600 181 213 30,400 0:05:47 0:36:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 8,930 213 260 44,650 0:07:03 0:30:17 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 9,500 226 287 57,000 0:07:47 0:23:14 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 5,700 136 178 39,900 0:04:50 0:15:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1514-12 30# Linear Flush 37 11,049 263 263 0:07:07 0:10:37 1.00 0.50 1.00 30.00 2.00 2.000.1514-13 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 14-14 Shut-In Shut-InInterval 10Moraine@ 19287 - 19291.34 ft 137.6 °F"Frac Sleeve 9Interval 11Moraine@ 18786 - 18790.34 ft 137.5 °F"Frac Sleeve 10Interval 12Moraine@ 18286 - 18290.34 ft 137.5 °F"Frac Sleeve 11Interval 13Moraine@ 17786 - 17790.34 ft 138.1 °F"Frac Sleeve 12Interval 14Moraine@ 17285 - 17289.34 ft 138.5 °F"Frac Sleeve 13Conoco Phillips - 3T-619Planned Design3
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-619SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control Gel Breaker BreakerBiocideInterval 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 Additives15-1 Shut-In Shut-In1:01:11 15-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:01:11 15-3 Shut-In Shut-In0:56:25 15-4 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 0:56:25 1.00 0.50 1.00 30.00 2.00 2.000.1515-5 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:54:25 1.00 0.50 1.00 30.00 2.00 2.000.1515-6 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:53:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-7 30# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:47:40 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-8 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-12 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-13 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-14 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-15 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1515-16 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1516-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:54:25 1.00 0.50 1.00 30.00 2.00 2.000.1516-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:53:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-3 30# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:47:40 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1516-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1517-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:54:25 1.00 0.50 1.00 30.00 2.00 2.000.1517-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:53:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-3 30# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:47:40 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1517-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1518-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:54:25 1.00 0.50 1.00 30.00 2.00 2.000.1518-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:53:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-3 30# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:47:40 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1518-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1519-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 1:03:11 1.00 0.50 1.00 30.00 2.00 2.000.1519-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 1:01:50 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-3 30# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:56:26 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:50:13 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:42:25 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:41:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:39:19 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:36:23 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:30:18 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:22:52 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:14:41 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1519-12 30# Linear Flush 37 9,452 225 225 0:06:05 0:09:35 1.00 0.50 1.00 30.00 2.00 2.000.1519-13 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 19-14 Shut-In Shut-InInterval 15Moraine@ 16785 - 16789.34 ft 138.7 °F"Frac Sleeve 14Interval 16Moraine@ 16285 - 16289.34 ft 138.8 °F"Frac Sleeve 15Interval 17Moraine@ 15786 - 15790.34 ft 138.7 °F"Frac Sleeve 16Interval 18Moraine@ 15287 - 15291.34 ft 138.8 °F"Frac Sleeve 17Interval 19Moraine@ 14787 - 14791.34 ft 138.9 °F"Frac Sleeve 18Conoco Phillips - 3T-619Planned Design4
CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.48LAT LEASE3T-619SALES ORDERBHST (°F)139LONGFORMATIONMoraineDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-IIBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Crosslinker Surfactant Buffer Clay Control Gel Breaker BreakerBiocideInterval 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 Additives20-1 Shut-In Shut-In1:16:20 20-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:16:20 20-3 Shut-In Shut-In1:11:34 20-4 30# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:11:34 1.00 0.50 1.00 30.00 2.00 2.000.1520-5 30# Linear Displace Dart to Seat 15 9,134 217 217 0:14:30 1:09:34 1.00 0.50 1.00 30.00 2.00 2.000.1520-6 30# Linear DFIT 10 840 20 20 0:02:00 0:55:04 1.00 0.50 1.00 30.00 2.00 2.000.1520-7 Shut-In Shut-In0:53:04 20-8 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:53:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-9 30# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:47:40 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-10 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-12 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-13 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-14 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-15 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-16 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-17 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1520-18 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1521-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 0:54:25 1.00 0.50 1.00 30.00 2.00 2.000.1521-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:53:04 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-3 30# Hybor G-i Pad 37 9,650 230 230 0:06:13 0:47:40 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:41:27 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:33:39 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:32:18 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:30:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 8,000 190 224 32,000 0:06:05 0:27:37 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 9,400 224 274 47,000 0:07:26 0:21:32 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 10,000 238 302 60,000 0:08:12 0:14:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:05:54 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1521-12 30# Linear Spacer and Dart Drop 37 1,260 30 30 0:00:49 0:00:49 1.00 0.50 1.00 30.00 2.00 2.00 0.1522-1 30# Linear Pre-Pad 37 2,100 50 50 0:01:21 1:00:30 1.00 0.50 1.00 30.00 2.00 2.000.1522-2 30# Hybor G-i Establish Stable Fluid 37 8,400 200 200 0:05:24 0:59:09 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-3 30# Hybor G-i Pad 37 8,680 207 207 0:05:35 0:53:45 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-4 30# Hybor G-i Conditioning Pad 100M 0.25 37 12,000 286 289 3,000 0:07:49 0:48:10 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-5 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 1.00 37 2,000 48 50 2,000 0:01:21 0:40:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-6 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 2.00 37 2,500 60 65 5,000 0:01:45 0:39:01 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-7 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 3.00 37 4,000 95 108 12,000 0:02:56 0:37:15 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-8 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 4.00 37 7,000 167 196 28,000 0:05:20 0:34:20 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-9 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 5.00 37 7,160 170 208 35,800 0:05:39 0:29:00 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-10 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 6.00 37 6,400 152 193 38,400 0:05:15 0:23:21 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-11 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 7.00 37 6,000 143 187 42,000 0:05:06 0:18:06 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-12 30# Hybor G-i Proppant Laden Fluid 16/20 Ceramic 8.00 37 4,600 110 149 36,800 0:04:02 0:13:00 1.25 0.50 1.00 0.50 1.00 30.00 2.00 2.000.1522-13 30# Linear Flush 37 8,494 202 202 0:05:28 0:08:58 1.00 0.50 30.00 2.00 2.000.1522-14 Freeze Protect Freeze Protect 10 1,470 35 35 0:03:30 0:03:30 0.50 30.0022-15 Shut-In Shut-In1,745,470 41,559 45,814 4,006,000Design Total (gal)Design Total (lbs)CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-63,940,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)179,77566,000Initial Design Material Volume 1,941.7 776.7 1,733.1 867.3 1,717.4 52,037.7 3,466.2 3,466.2 260.0-2232.63430412,350-Whole Units to be ordered 71,553,345-CL-28M BC-140X2 Losurf-300D MO-67 LD-6450 WG-36 OPTIFLO-III OPTIFLO-II BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm ppm-Max Additive Rate 1.9 0.8 1.6 0.8 1.6 46.6 3.1 3.1 0.2-Min Additive Rate22:16:32 Interval 20Moraine@ 14289 - 14293.34 ft 138.8 °F"Frac Sleeve 18Interval 21Moraine@ 13788 - 13792.34 ft 138.8 °F"Frac Sleeve 20Interval 22Moraine@ 13288 - 13292.34 ft 138.8 °F"Frac Sleeve 21Proppant Type16/20 Ceramic100M---Fluid Type30# Hybor G30# LinearSeawaterFreeze Protect30# Hybor G-i---Conoco Phillips - 3T-619Planned Design5
Hydraulic Fracturing Fluid Product Component Information Disclosure
2025-09-12
Alaska
HARRISON BAY
50-103-20921-00-00
CONOCOPHILLIPS
3T 619
-150.26759666
70.42081967
NAD83
none
Oil
5200
1658296.5
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
BA-20
BUFFERING
AGENT Halliburton Buffer
BC-140 X2 Halliburton Initiator
BE-6(TM)
Bactericide Halliburton Microbiocide
CAT-3
ACTIVATOR Halliburton Activator
CL-28M
CROSSLINKER Halliburton Crosslinker
CLA-WEB(TM) Halliburton Clay Stabilizer
Legend LD-6450 MultiChem
Completion/Stimulati
on
LoSurf-300D Halliburton Non-ionic Surfactant
MO-67 Halliburton pH Control
OPTIFLO-II
DELAYED
RELEASE
BREAKER Halliburton Breaker
OPTIFLO-III
DELAYED
RELEASE
BREAKER Halliburton Breaker
Patina Energy
Flow Insurance
Brass
Patina
Energy Additive
ResMetrics Oil
Phase Tracer ResMetrics Tracer
ResMetrics
Water Phase
Tracer ResMetrics Tracer
WG-36 GELLING
AGENT Halliburton Gelling Agent
Ceramic
Proppant - Wanli Wanli Proppant
SAND,
COMMON
BROWN 100
MESH Halliburton Proppant
CarboLite 16/20
Carbo
Ceramics Proppant
Flow Insurance
Copper
Patina
Energy Tracer
Fresh Water Operator Base Fluid
Ingredients Water 7732-18-5 100.00%43.41049%14574832
Water 7732-18-5 95.00%42.07913%14127835
Ceramic Materials and Wares,
Chemicals 66402-68-4 100.00%11.73512%3940000
Sodium chloride 7647-14-5 5.00%2.21469%743571
Crystalline silica, quartz 14808-60-7 100.00%0.28119%94407
Guar gum 9000-30-0 100.00%0.15499%52037
Borate salts Proprietary 60.00%0.03673%12334
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
Calcium chloride, dihyrate 10035-04-8 60.00%0.03314%11127
Ethanol 64-17-5 60.00%0.02354%7903
Monoethanolamine borate 26038-87-9 100.00%0.02351%7895
Ammonium persulfate 7727-54-0 100.00%0.02065%6932
Heavy aromatic petroleum
naphtha 64742-94-5 30.00%0.01177%3952
Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01177%3952 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Sodium hydroxide 1310-73-2 30.00%0.00820%2755
Ethylene glycol 107-21-1 70.00%0.00747%2509
Oxylated phenolic resin Proprietary 30.00%0.00619%2080 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Oxyalkylated phenolic resin Proprietary 10.00%0.00392%1318 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Potassium chloride 7447-40-7 5.00%0.00306%1028
Inorganic mineral 1317-65-3 5.00%0.00306%1028
Copolymer of acrylamide and
sodium acrylate 25085-02-3 5.00%0.00276%928
Water 7732-18-5 100.00%0.00253%850
Poly(oxy-1,2-ethanediyl), alpha-(4-
nonylphenyl)-omega-hydroxy-,
branched 127087-87-0 5.00%0.00196%659
Naphthalene 91-20-3 5.00%0.00196%659
Flow Insurance Copper Proprietary 100.00%0.00110%368
Patina
Energy Product Stewardship
test@patinae
nergy.com 7205324886
2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00077%260
Inorganic mineral Proprietary 1.00%0.00061%206 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Polymer Proprietary 1.00%0.00061%206 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Calcium magnesium carbonate 16389-88-1 1.00%0.00061%206
Gluteraldehyde 111-30-8 1.00%0.00061%206
Glycol Ether Proprietary 80.00%0.00048%161 ResMetrics Product Stewardship
info@resmetr
ics.com 8325921900
1,2,4 Trimethylbenzene 95-63-6 1.00%0.00039%132
Sodium chloride 7647-14-5 1.00%0.00027%92
Proprietary1 Proprietary 20.00%0.00018%61 ResMetrics Product Stewardship
info@resmetr
ics.com 8325921900
Proprietary NoN-hazardous Proprietary 100.00%0.00013%44
Patina
Energy Product Stewardship
test@patinae
nergy.com 6692416025
C.I. pigment Orange 5 3468-63-1 1.00%0.00010%35
Methanesulfonic acid, 1-hydroxy-,
sodium salt 870-72-4 0.10%0.00006%21
Sodium bisulfate 7681-38-1 0.10%0.00006%21
Polymer Proprietary 0.10%0.00006%19 MultiChem Ana Djuric
Ana.Djuric@
Halliburton.co
m 281-871-5747
Ammonium acetate 631-61-8 100.00%0.00003%10
2,7-Naphthalenedisulfonic acid, 3-
hydroxy-4-[(4-sulfor-1-
naphthalenyl) azo] -, trisodium
salt 915-67-3 0.10%0.00002%8
Corundum 1302-74-5 60.00%0.00002%6
Ammonium salt Proprietary 60.00%0.00002%6 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Mullite 1302-93-8 40.00%0.00001%4
Acetic acid 64-19-7 30.00%0.00001%3
EDTA/Copper chelate Proprietary 30.00%0.00001%3 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Magnesium nitrate 10377-60-3 0.01%0.00001%3
Magensium chloride 7786-30-3 0.01%0.00001%3
5-Chloro-2-methyl-3(2H)-
Isothaiazolone 26172-55-4 0.01%0.00001%3
2-Methyl-4-isothiazolin-3-one 2682-20-4 0.01%0.00001%3
Ammonium chloride 12125-02-9 5.00%0.00000%1
Ammonia 7664-41-7 1.00%0.00000%1
Quaternary amine Proprietary 0.10%0.00000%1 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
Amine salts Proprietary 0.10%0.00000%1 Halliburton Denise Tuck
Denise.Tuck
@Halliburton.
com 281-871-6226
* 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 1.5
All component information listed was obtained from the supplier’s Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier
who provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for
how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D.
Production Type:
True Vertical Depth (TVD):
Total Water Volume (gal)*:
MSDS and Non-MSDS Ingredients are listed below the green line
Well Name and Number:
Longitude:
Latitude:
Long/Lat Projection:
Indian/Federal:
Fracture Date
State:
County:
API Number:
Operator Name:
Originated: Delivered to:TRANSMITTAL DATE18-Sep-25Alaska Oil & Gas Conservation CommissionTRANSMITTAL #18Sep25-AP01ATTN: Gavin Gluyas
!WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGEDCOLOR PRINTS e-TRANS DATE/ CD3T-619 50-103-20921-00-00 225-079 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 29-Sep-25 1Path .PDF-Qty .LAS-Qty .DLIS-Qty .PPT-Qty .TXT-Qty.CSV -QtyData from M/LWD Tools" # $ % & '(# %
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, )*" '# 1 &% ," $ $ ' '# 1 + +3+ ," $ $ ' '# $ $ 1 + +3+ ,"%&'# '
4 &&"%# ( 5 6
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225-063T40898Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.09.19 08:51:47 -08'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________KUPARUK RIV UNIT 3T-619
JBR 09/22/2025
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
Good test. Blinds failed, Doors were opened and inspected, failed again and doors were opened again and seals were changed
out, failed again. They were replaced with another set of blind rams and tested good. I did not witness the passing test on the
blinds but had them send me the chart.
Test Results
TEST DATA
Rig Rep:HaugOperator:ConocoPhillips Alaska, Inc.Operator Rep:Tucker
Rig Owner/Rig No.:Doyon 142 PTD#:2250630 DATE:8/8/2025
Type Operation:DRILL Annular:
250/3500Type Test:INIT
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopRCN250810112530
Inspector Bob Noble
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 26
MASP:
1724
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
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8"P
#1 Rams 1 7 5/8"P
#2 Rams 1 Blind / Shear F
#3 Rams 1 3 1/2" x 6"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 0 NA
System Pressure P3000
Pressure After Closure P1750
200 PSI Attained P8
Full Pressure Attained P49
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6 @ 1991
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P18
#1 Rams P7
#2 Rams P7
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
Test Charts attached
BOPE - Doyon 142
KRU 3T-619 (PTD 2250630)
AOGCC Insp# bopRCN250810112530
8/8/2025
o�-6 :;
• �
�4)i}N1 30-4�
BOPE - Doyon 142
KRU 3T-619 (PTD 2250630)
AOGCC Insp# bopRCN250810112530
8/8/2025
BOPE - Doyon 142
KRU 3T-619 (PTD 2250630)
AOGCC Insp# bopRCN250810112530
8/8/2025
DOYON RIG 142 ACCUMULATOR DRAW DOWN WORKSHEET
WELL: 3T-619 8/8/2025
ACCUMULATOR PSI 3000
MANIFOLD PSI 1300
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 1750
NITROGEN BOTTLE'S PSI
BOTTLE # 1 2000
BOTTLE # 2 2000
BOTTLE # 3 2000
BOTTLE # 4 2000
BOTTLE # 5 2000
BOTTLE # 6 1950
AVG FOR 6 BOTTLE'S =1991
TURN ON ELEC. PUMP, SEC FOR 200 PSI =8
TURN ON AIR PUMP'S
TIME FOR FULL CHARGE =49
Annular 18
UPR 7
Blind/ Shear 7
LPR 7
KILL HCR 2
Choke HCR 2
KRU 3T-619 (PTD 2250630)
AOGCC Insp# bopRCN250810112530
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, Rig floor kill line
valve, Upper IBOP, 5” FOSV #1 250/5000
3. CMV’s #’s 9, 11, Mezz Kill line valve, Lower IBOP, 5” FOSV
#2, 250/5000
4. CMV’s #’s 8, 10, HCR Kill, 5” Dart Valve 250/5000
5. CMV’s #’s 6, 7, Manual Kill, 250/5000
6. Super Choke 250/2000
7.Manual Choke 250/2000
8. CMV’s #’s 2, 5, 250/5000
9. HCR Choke 250/5000
10.Manual Choke 250/5000
Koomey Drawdown
Remove 7-5/8”Test Joint
11. CMV’s #’s 3, 4, Blind rams 250/5000
Install 5” Test joint
12. 5” TJ Annular 250/3500
13.5” TJ 3-1/2” X 6” Lower VBR’s 250/5000
IBOP=2 Manual choke=1 LPR’s=1
Dart=1 Mud Cross=6 Total Components=32
TIW=2 Annular=2
CMV’s =14 UPR’s=1
Hyd. choke=1 Blind/Shears=1 BOPE - Doyon 142
KRU 3T-619 (PTD 2250630)
AOGCC Insp# bopRCN250810112530
8/8/2025
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 Brillon
Wells Engineering Manager
Conoco Phillips Alaska, Inc.
700 G Street
Anchorage, AK, 99501
Re: Kuparuk River Field, Torok Oil Pool, KRU 3T-619
Conoco Phillips Alaska, Inc.
Permit to Drill Number: 225-063
Surface Location: 1767' FSL, 329' FWL, NWSW S1 T12N R7E
Bottomhole Location: 4055' FSL, 2152' FWL, NENW S21 T13N R7E
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,
Gregory &Wilson
Commissioner
DATED this 24
th day of July 2025.
Gregory C. Wilson
Digitally signed by Gregory C.
Wilson
Date: 2025.07.24 14:07:00 -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: 24,022 TVD: 5017
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
8/1/2025
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
1229' to ADL355037
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 51 15. Distance to Nearest Well Open
Surface: x-467539 y- 6003494 Zone- 4 12 to Same Pool: 840' to 3T-616
16. Deviated wells: Kickoff depth: 300 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 L80 Hyd563 2631 39 39 2670 2387
9.875"7.625" 29.7 L80 Hyd563 10706 39 39 10745 4876
9.875"7.625" 33.7 P110-S Hyd563 800 10745 4876 11545 4958
6.5"4.5" 12.6 P110-S Hyd563 12627 11395 5008 24022 4966
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: Weifeng Dai
Chris Brillon Contact Email:weifeng.dai@conocophillips.com
Wells Engineering Manager Contact Phone:907-265-6936
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
10 yds
P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field
Torok Oil Pool
1767' FSL, 329' FWL, NWSW S1 T12N R7E ADL025528 / ADL393883 / ADL393884
(including stage data)
2671' FSL, 263' FWL, SENE S34 T13N R7E LONS 01-013
4055' FSL, 2152' FWL, NENW S21 T13N R7E 2560 / 5760 / 5645
GL / BF Elevation above MSL (ft):
2221 1724
18. Casing Program:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
ConocoPhillips Alaska Inc.59-52-180 KRU 3T-619
930sks 11ppg, 280sks 15.8ppg
662sks 14ppg, 138sks 15.3ppg
Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks
1101sks 13.5ppg
Casing Length Size Cement Volume MD
Total Depth MD (ft):Total Depth TVD (ft):Plugs (measured):Effect. Depth MD (ft):Effect. Depth TVD (ft):
Surface
Conductor/Structural
Liner
Production
Intermediate
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.
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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 8:20 am, Jun 18, 2025
225-063
Variance of the diverter requirement under 20 AAC 25.035(h)(2) is approved.
*
* See Cementing Calculations on p. 9. SFD
DSR-6/18/25
Yess
X
Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig
Annular preventer test to 2500 psig
BOPE testing on a 21-day interval is approved with the attached conditions
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
Cement logs must be reviewed with the AOGCC as soon as available and prior to running the production liner.
50-103-20921-00-00
VTL 7/23/2025 SFD 7/24/2025GKC for JLC 7/24/25
Gregory C. Wilson Digitally signed by Gregory C. Wilson
Date: 2025.07.24 14:05:27 -08'00'07/24/25
07/24/25
RBDMS JSB 072825
ConocoPhillips Alaska, Inc.
Post Office Box 100360
Anchorage, Alaska 99510-0360
Telephone 907-276-1215
June 17, 2025
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Application for Permit to Drill 3T-619
Dear Sir or Madam:
ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Moraine Injector well from the 3T drilling pad.
The intended spud date for this well is 8/1/2025. It is intended that Doyon 142 be used to drill the well.
3T-619 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 topset the Moraine reservoir. A 7-
5/8” casing string will be set and cemented from TD to secure the shoe and cover 500’ or 250’TVD above any hydrocarbon-
bearing zones (Torok).
The production interval will be comprised of a 6-1/2” horizontal hole that will be landed and geo-steered in the Moraine
formation. The well will be completed as an cemented, fracture stimulated injector with 4-1/2” liner, and frac sleeves. The
upper completion will include a production packer with GLM’s and a downhole guage tied back to surface.
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)
It is requested that a waiver of the diverter requirement under 20 AAC 25.035 (h) (2) is granted. At 3T, 4 penetrations have
been completed and there has not been a significant indication of shallow gas or gas hydrates through the surface hole interval.
A variance is also requested for a BOPE test interval of 21 days for this project. Doyon 142 is a strong participant in the CPAI
BOPE between well maintenance program reflected by low failure rates in BOP tests since its entry in the CPAI fleet. The
variance allows effective drilling and completion of problematic intermediate shale sections and efficient management of
losses in the production sections when they are encountered.
Information pertinent to the application that is presently on file at the AOGCC:
1. Diagrams of the BOP equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b).
2. A description of the drilling fluids handling system.
3. Diagram of riser set up.
If you have any questions or require further information, please contact Weifeng Dai at 907-265-6936
(Weifeng.Dai@conocophillips.com) or Greg Hobbs at 907-263-4749.
Sincerely, cc:
3T-619 Well File / Jenna Taylor ATO 1560
Will Earhart ATO 1552
Weifeng Dai Chris Brillon ATO 1548
Drilling Engineer Jiedi Wu ATO 1418
Recommend approving requested ariance of the diverter requirement under 20 AAC 25.035(h)(2). (See page 5.) SFD
requested that a waiver of the diverter requirement under 20 AAC 25.035 (h) (2)
Application for Permit to Drill, 3T-619
Saved: 16-Jun-25
3T-613 PTD
Page 1 of 9
Printed: 16-Jun-25
3T-619
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)) ............................................................. 5
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)) ........................................................... 7
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 3T-613
2. Location Summary (Requirements of 20 AAC 25.005(c)(2))
Location at Surface 1,767 FSL, 329 FWL, SENE S1 T12N R7E, UM
NAD 1927
Northings: 467539
Eastings:6003494
RKB Elevation 51.1’AMSL
Pad Elevation 12’AMSL
Top of Productive Horizon
(Heel) 2671‘ FSL, 263‘ FWL, NWSE S34 T13N R7E, UM
NAD 1927
Northings: 460635
Eastings: 6009711
Measured Depth, RKB:
11,545
Total Vertical Depth, RKB: 5,009
Total Vertical Depth, SS: 4,958
Total Depth (Toe) 4055‘ FSL, 2152‘ FWL, SENW S21 T13N R7E, UM
NAD 1927
Northings: 457282
Eastings: 6021673
Measured Depth, RKB: 24,022
Total Vertical Depth, RKB: 5,017
Total Vertical Depth, SS: 4,966
Pad Layout
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 3T-619
2. Rig up and test diverter and riser, dewater cellar as needed.
3. Drill 13 1/2” hole to the surface casing point as per the directional plan (LWD program:GR/RES/GWD).
4. Run and cement 10 3/4” surface casing to surface.
5. Install BOPE with the following equipment/configuration:13-5/8” annular preventer, 7-5/8” FBR’s, blind ram and 2-
7/8”x5” VBR’s.
a. See section 4 for ram configuration justification.
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 3,000 psi for 30 minutes.
9. Drill out shoe track and 20’ of new hole
10. Perform FIT/LOT. Max FIT to 18.0 ppg. Minimum LOT required to drill ahead is 11.0 ppg EMW.
11. Drill 9 7/8” hole to section TD, setting pipe 5 ft TVD into the top Moraine Reservoir. (LWD Program: GR/RES).
12. Run 7 5/8” casing and cement to a minimum of 250’ TVD above any hydrocarbon bearing zones (cementing
schematic attached). Pressure test casing if possible on plug bump to 4000 psi.
13. Test BOPE to 250 psi low / 4,000 psi high (24-48 Regulatory notice).
14. Pick up and run in hole with 6 1/2” drilling BHA. Log top of cement with sonic tool in recorded mode.
15. Chart casing pressure test to 4,000 psi for 30 minutes if not tested on plug bump.
16. Drill out shoe track and 20 feet of new formation.
17. Perform LOT to a maximum of 16.0 ppg. Minimum acceptable leak-off value is 11.0 ppg EMW.
18. Drill 6 1/2” hole to section TD (LWD Program: GR/RES/Den/Neu/Sonic).
19. Pull out of hole with drilling BHA. Review cement job details and sonic log TOC.
20. Run 4 1/2” liner with toe valve, frac sleeves and liner hanger and packer to TD.
21. Cement 4 1/2” liner from TD to liner top. Pressure test liner and hanger for 30 minutes.
22. Run 4 1/2” upper completion with glass plug, production packer, chemical injection mandrel with cap string,
downhole gauge, and gas lift mandrels. Space out and land tubing hanger with pre-installed and pre-tested BPV.
23. Pressure test hanger seals to 3,850 psi.
24. Pressure test against the glass plug to set production packer, test tubing to 3,850 psi, chart test.
25. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test.
26. Install HP-BPV and test to 2500 psi.
27. Nipple down BOP.
28. Install tubing head adapter assembly. N/U frac tree and test to 10,000 psi/10 minutes.
29. Freeze protect down tubing and annulus.
30. 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 3T-613.
3T-619 has a MASP of 1,741 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.
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
x Annular Preventer (iii)
x 7 5/8 Fixed Rams
x Blind/Shear Rams (ii)
x VBR’s (i)
Production:
x Annular Preventer (iii)
x VBR’s (i)
x Blind/Shear Rams (ii)
x VBR’s (i)
5. Diverter System (Requirements of 20 AAC 25.005(c)(7))
It is requested that a waiver of the diverter requirement under 20 AAC 25.035 (h) (2) is granted. At 3T, 3 penetrations
have been completed and one more penetration is planned prior to 3T-613 and there has not been a significant indication
of shallow gas or gas hydrates through the surface hole interval.
6. MASP Calculations (Requirements of 20 AAC 25.005(c)(4))
(A) maximum downhole pressure and maximum potential surface pressure;
Maximum Potential Surface Pressure (MPSP) is determined as the lesser of:
Method 1: surface pressure at breakdown of the formation casing seat with a gas gradient to the
surface
Recommend approving requested ariance of the diverter requirement under 20 AAC 25.035(h)(2).* SFD
requested that a waiver of the diverter requirement under 20 AAC 25.035 (h) (2)
* The 3T-619 surface casing shoe will lie within 500' of those in 3T-730 (400' W) and 3T-613 (225-036) 450' N. There is no mention of shallow gas at permafrost base or in surface hole in the daily drilling
records for these wells. In addition, a diverter variance was approved for 3T-617 (225-053) which lies 320' NW. Also nearby is 3T-612 (224-128, 150' N), but surface hole gas readings for this well are not
credible due to values over 300 units before spudding. CPAI suspects gas sensor was not calibrated. (For additional information, see Well History File 224-156. p. 69). Other 3T-Pad wells
with no mention of shallow gas at permafrost base or while drilling surface hole are 3T-731 (224-156), 3T-621 (224-022), 3T-730 (225-010), and 3T-608 (224-094). SFD
Method 2: formation pore pressure at the next casing point less a gas gradient to the surface
Method 2: formation pore pressure at the next casing point less a gas gradient to the surface
Method 1 Method 2
ܯܲܵܲ = [(ܨܩ × 0.052 )െ ܩܽݏ ܩݎܽ݀݅݁݊ݐ
] × ܸܶܦ ܯܲܵܲ = ܨܲܲ െ (ܩܽݏ ܩݎܽ݀݅݁݊ݐ) × ܸܶܦ
Where:
FG –Fracture gradient at the casing seat in
lb/gal
0.052 – Conversion from lb/gal to psi/ft
Gas Gradient –0.1 psi/ft
TVD –True Vertical Depth of casing seat in ft
RKB
Where:
FPP –Formation Pore Pressure at the next
casing point
Gas Gradient –0.1 psi/ft
The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP)
while drilling:
Section Hole Size
Previous CSG Section TD MPSP
psi
MPSP MPSP
Size MD TVD FG
ppg
Pore Pressure
ppg | psi MD TVD Pore Pressure
ppg | psi
Method 1
psi
Method 2
psi
SURF 13.5 20 119 119 10.9 8.6 53 2,670 2,438 8.6 1,090 67 67 846
INT1 9 7/8 10-3/4 2,670 2,438 13.5 8.6 2,249 11,545 5,008 8.6 2,239 1,138 1,138 1,738
PROD 6 1/2 7-5/8 11,545 5,008 13.0 8.6 2,284 24,022 5,017 8.6 2,243 1,741 3,029 1,741
(B) data on potential gas zones;
The planned wellbore is expected to enter the gas cap and the area is expected to be normally pressured (8.5-8.9 ppg).
(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.
The planned wellbore is expected to enter the gas cap and the area is expected to be normally pressured (8.5-8.9 ppg).
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 H40 Welded Cemented to surface with 10 yds slurry
10 3/4 13 1/2 45.50 L80 Hyd563 Cement to Surface
7 5/8 9 7/8 29.70
33.70
L80
P110-S Hyd563 250’ TVD or 500’ MD, whichever is greater, above upper
most producing zone (Coyote)
4 1/2 6 1/2 12.60 P110-S Hyd563 Cemented liner with frac sleeves
Cementing Calculations
10 3/4” Surface Casing run to 2,670’ MD / 2,438’ TVD
Cement 2,670’ MD to 2,170’ (500’ of tail) with Class G + Add's@ 15.8 PPG, and from 2,170' to surface with 10.7 ppg
Arctic Lite Crete. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1,560’
MD), zero excess in 20” conductor.
Lead 373 bbls => 717 sx of 10.7 ppg Class G + Add's @ 2.92 ft3 /sk
Tail 56 bbls => 280 sx of 15.8ppg Class G + Add's @ 1.16 ft3/sk
7 5/8” Intermediate Casing run to 11,454’ MD / 5,008 ’ TVD
Top of slurry is designed to be at 7,650’ MD, which is 500’ MD 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.
Lead 182 bbls => 659 sx of 14 ppg Class G + Add's @ 1.55 ft3 /sk
Tail 30.5 bbls => 137 sx of 15.3ppg Class G + Add's @ 1.25 ft3/sk
4-1/2” Liner run to 24,022’ MD / 5,017 ’ TVD
Cement the liner from TD to the liner top using a 13.5 ppg Class G + Add’s cement. Assume 20% excess annular
volume in the open hole.
Tail 330 bbls => 1,126 sx of 13.5 ppg Class G + Add's @ 1.645 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 8.6 – 9.8 9.0 – 9.6 10 – 11
PV cP 20-50 8-15 7-12
YP lb./100 ft2 30 - 80 20 - 30 15 - 30
Funnel Viscosity s/qt. 250 – 300 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 < 10.0 < 10.0
pH 9.5 – 10.0 9.5 – 10.0 9.5 – 10.5
Assume 20% excess annular
volume in the open hole.
p,
Assume 40% excess annular volume
,,
50% excess below the permafrost
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 9.8 ppg by use of solids control system and dilutions where
necessary.
Intermediate:
Fresh water polymer mud system. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular
velocity. Maintain mud weight at or below 9.6 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 weighted up to 9.5 ppg before pulling out of the hole.
Production Hole:
The horizontal production interval will be drilled with an NAF mud system weighted to 10 – 11 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:
3T is a multi-well pad, with only a few existing wells. 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: Unlikely to encounter any abnormal pressure, however, 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.
The overburden logs will be evaluated to ensure no hydrocarbon bearing zones are above the known Coyote. If identified, the
primary intermediate cement job will be replanned to cover the zone as per the agency regulations.
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.
16. Proposed Completion Schematic
39 500
500 800
800 1100
1100 1500
1500 2000
2000 2500
2500 3000
3000 5000
5000 9000
9000 17000
17000 24022
3T-619 wp07.2 Plan Summary
0
4
Dogleg Severity0 4000 8000 12000 16000 20000 24000
Measured Depth
10-3/4" Surface Casing
7-5/8" Intermediate Casing
4-1/2" Production Liner
30.0
30.0
60.0
60.0
0
90
180
270
30
210
60
240 120
300
150
330
Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in]
39111211
311411
511612
3T-621
23842483258326832784288429853086
3187
3288
3389
3491
3T-618 wp07
3910020030040050060170180190110011102120213021403150416041704
1805
3T-620 wp05
100200300400500601701
801
900
3T-622 wp09.1
0
3000
True Vertical Depth0 3000 6000 9000 12000 15000 18000 21000
Vertical Section at 330.31°
10-3/4" Surface Casing
7-5/8" Intermediate Casing
4-1/2" Production Liner
15
30
45
Centre to Centre Separation0 425 850 1275 1700 2125 2550 2975
Measured Depth
DDI
7.369
SURVEY PROGRAM
Date: 2019-07-03T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
39.00 500.00 3T-619 wp07.2 (3T-619) r.5 SDI_URSA1
500.00 2670.00 3T-619 wp07.2 (3T-619) MWD+IFR2+SAG+MS
2670.00 11540.00 3T-619 wp07.2 (3T-619) MWD+IFR2+SAG+MS
11540.00 24021.99 3T-619 wp07.2 (3T-619) MWD+IFR2+SAG+MS
Ground / 12.00
CASING DETAILS
TVD MD Name
2437.58 2670.00 10-3/4" Surface Casing
5008.72 11545.00 7-5/8" Intermediate Casing
5017.28 24021.99 4-1/2" Production Liner
Mag Model & Date: BGGM2025 15-Sep-25
Magnetic North is 13.56° East of True North (Magnetic Declinatio
Mag Dip & Field Strength: 80.60° 57154.25nT
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.003 500.00 2.00 315.00 499.96 2.47 -2.47 1.00 315.00 3.37 Start Build 2.004 1628.31 24.57 315.00 1591.00 184.60 -184.60 2.00 0.00 251.79 Start 109.95 hold at 1628.31 MD5 1738.26 24.57 315.00 1691.00 216.92 -216.92 0.00 0.00 295.88 Start Build 2.506 2751.22 49.89 315.00 2491.00 646.74 -646.74 2.50 0.00 882.15 Start 20.00 hold at 2751.22 MD7 2771.22 49.89 315.00 2503.89 657.56 -657.56 0.00 0.00 896.91 Start DLS 3.00 TFO -8.678 3599.03 74.51 311.23 2887.13 1152.06 -1189.72 3.00 -8.67 1590.06 Start 7843.22 hold at 3599.03 MD9 11442.25 74.51 311.23 4982.32 6133.79 -6873.78 0.00 0.00 8732.97 Start DLS 3.25 TFO 69.1210 11989.19 81.40 328.00 5097.19 6540.06 -7218.02 3.25 69.12 9256.40 Start Build 3.00
11 12239.19 88.90 328.00 5118.31 6751.16 -7349.94 3.00 0.00 9505.13 3T Grewingk T01 103124 Start 20.00 hold at 12239.19 MD
12 12259.19 88.90 328.00 5118.69 6768.12 -7360.53 0.00 0.00 9525.11 Start DLS 3.00 TFO 89.48
1312965.62 89.16 349.19 5130.78 7422.00 -7616.81 3.00 89.4810220.08 Start 67.59 hold at 12965.62 MD
1413033.21 89.16 349.19 5131.77 7488.38 -7629.48 0.00 0.00 10284.03 Start DLS 2.50 TFO -64.96
15 13112.43 90.00 347.40 5132.35 7565.95 -7645.55 2.50 -64.9610359.38 3T Grewingk T02 103124 Start DLS 2.50 TFO -60.22
16 13191.38 90.98 345.69 5131.67 7642.73 -7663.92 2.50 -60.2210435.18 Start 2503.69 hold at 13191.38 MD
17 15695.08 90.98 345.69 5088.85 10068.35 -8282.81 0.00 0.00 12848.94 Start DLS 1.00 TFO -179.02
18 15793.10 90.00 345.67 5088.01 10163.32 -8307.05 1.00 -179.0212943.45 3T Grewingk T03 103124 Start DLS 1.00 TFO 179.96
19 15991.39 88.02 345.67 5091.44 10355.40 -8356.12 1.00 179.9613134.62 Start 1064.22 hold at 15991.39 MD
2017055.60 88.02 345.67 5128.26 11385.89 -8619.33 0.00 0.0014160.22 Start DLS 1.50 TFO 0.25
21 17187.80 90.00 345.68 5130.55 11513.95 -8652.03 1.50 0.25 14287.67 3T Grewingk T04 103124 Start DLS 1.50 TFO 0.81
22 17353.93 92.49 345.72 5126.94 11674.88 -8693.06 1.50 0.81 14447.79 Start 617.20 hold at 17353.93 MD
2317971.13 92.49 345.72 5100.11 12272.43 -8845.21 0.00 0.00 15042.27 Start DLS 1.00 TFO -179.62
2418050.30 91.70 345.71 5097.21 12349.10 -8864.73 1.00 -179.6215118.55 3T Grewingk T05 103124 Start DLS 1.00 TFO 179.86
2518118.39 91.02 345.71 5095.59 12415.07 -8881.53 1.00 179.86 15184.18 Start 3846.93 hold at 18118.39 MD
26 21965.33 91.02 345.71 5027.17 16142.42 -9830.81 0.00 0.00 18892.44 Start DLS 1.00 TFO -179.91
27 22067.23 90.00 345.71 5026.26 16241.16 -9855.96 1.00 -179.9118990.69 3T Grewingk T06 103124 Start DLS 1.00 TFO -178.98
28 22136.40 89.31 345.70 5026.68 16308.19 -9873.04 1.00 -178.9819057.37 Start 704.86 hold at 22136.40 MD
29 22841.26 89.31 345.70 5035.18 16991.15 -10047.16 0.00 0.00 19736.93 Start DLS 1.00 TFO 23.61
30 22916.73 90.00 346.00 5035.64 17064.33 -10065.61 1.00 23.6119809.64 3T Grewingk T07 103124 Start DLS 1.00 TFO -16.85
31 23021.12 91.00 345.70 5034.73 17165.54 -10091.13 1.00 -16.8519910.20 Start 1000.88 hold at 23021.12 MD
32 24021.99 91.00 345.70 5017.28 18135.25 -10338.35 0.00 0.00 20875.07 3T Grewingk T08 103124 TD at 24021.99
FORMATION TOP DETAILS
TVDPath Formation
1392.87 Ugnu C
1562.43 Base Perm
1615.27 Ugnu B
1735.07 Ugnu A
2024.91 West Sak
2372.11 West Sak Base
2547.71 C-80
2616.96 C-50
2875.16 C-40
3790.84 C-35
4102.85 Coyote
4181.65 Coyote Base
5003.56 Moraine
5124.45 Lower Moraine
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 Checked by Accepted by Approved by
Plan 12+39 @ 51.00usft (D142)
-30000300060009000True Vertical Depth0 3000 6000 9000 12000 15000 18000 21000Vertical Section at 330.31°10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner100020003000400050006000700080009000100001100012000130001 4000
15000160001700018000
19000
20000
21000
22000
23000
24000
24022
0°30°60°75°90°91°88°9 2 °
91°89°9 1°3T-619 wp07.2
Ugnu CBase PermUgnu BUgnu AWest SakWest Sak BaseC-80C-50C-40C-35CoyoteCoyote BaseMoraineLower Moraine3T-619 wp07.210:33, June 17 2025Section View
035007000105001400017500South(-)/North(+)-17500 -14000 -10500 -7000 -3500 0 3500 7000West(-)/East(+)10-3/4" Surface Casing7-5/8" Intermediate Casing4-1/2" Production Liner50010001500200025003000350040004500500050173T-619 wp07.23T-619 wp07.2While drilling production section, stay within 100 feet laterally of plan, unless notified otherwise.10:35, June 17 20253ODQ9LHZ
0.000.751.502.253.003.754.505.256.006.757.50Separation Factor-1500 0 1500 3000 4500 6000 7500 900010500 12000 13500 15000 16500 18000 19500 21000 22500 24000 25500Measured Depth (3000 usft/in)Colville Delta 3Nuna 1Nuna 1PB13T-6123T-6133T-6163T-616PB13T-6213T-614 wp063T-622 wp09.13T-625 wp07.1STOP DrillingTake Immediate ActionCaution - Monitor CloselyNormal OperationsProject: Kuparuk River Unit_2Site: Kuparuk 3T PadWell: 3T-619Wellbore: 3T-619Design: 3T-619 wp07.2
0
35
Centre to Centre Separation0 500 1000 1500 2000 2500
Partial Measured Depth3T-6213T-619 wp07.2 Ladder View
0
150
300
Centre to Centre Separation0 3500 7000 10500 14000 17500 21000 24500
Measured DepthNDST-02NDST-02PB1Nuna 1Nuna 1PB13T-6133T-6123T-6133T-6163T-616PB13T-616PB23T-617 wp103T-6213T-7303T-731Equivalent Magnetic Distance
SURVEY PROGRAM
Depth From Depth To Survey/Plan Tool
39.00 500.00 3T-619 wp07.2 (3T-619) r.5 SDI_URSA1
500.00 2670.00 3T-619 wp07.2 (3T-619) MWD+IFR2+SAG+MS
2670.0011540.00 3T-619 wp07.2 (3T-619) MWD+IFR2+SAG+MS
11540.00 24021.99 3T-619 wp07.2 (3T-619) MWD+IFR2+SAG+MS
11:24, June 17 2025
CASING DETAILS
TVD MD Name
2437.58 2670.00 10-3/4" Surface Casing
5008.72 11545.00 7-5/8" Intermediate Casing
5017.28 24021.99 4-1/2" Production Liner
39 500
500 800
800 1100
1100 1500
1500 2000
2000 2500
2500 3000
3000 5000
5000 9000
9000 17000
17000 24022
3T-619 wp07.2 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]
1188
1233
1276
1318
1359
1398
1436
1471
NDST-02
1188
1233
1276
1318
1359
1398
1436
1471
3873 3916 3959 4002 4045 4089
Nuna 1
3873 3916 3959 4002 4045 4089
2417246425112557260426502697
2744
27912837
2883
2929
2975
3021
3067
3114
3160
3207
3254
3300
3348
3395
3442
3489
3535
3T-612
3950100150200250300350399448498
546
595
643
691
738
786
833
879
925
971
1016
3T-616
3950100150200250300350399448498
546
595
643
691
738
786
833
879
925
971
1016
3950100150200250300350399448498
546
595
643
691
738
786
833
879
925
971
1016
3950100150200250300350400449499549598648697747796846895945994104410931143119212421291134113901440148915391589
163816881738178718371886193619852034208421332182223222812330238024292478252725772626267527242773282128692916
2963
3010
3056
3T-617 wp10
3961111161211
261311361411461511561612662713764814
8659169671018106911191170122112711322137314231474152515751626
16761725177618271878193019813T-621
2109 2153 2196 2237 2276
2314
2350
3T-731
143914891538158816381688173817881838188819381988203820882139218922402290234123922443
3T-615 wp06
395010015020025030035040044949954959864869874779784689694599510451094114411931243129313421392144114911540159016401690173917891838188819371987203620862135218522352284233423842434248325332583263326832734278428342884293429853035308631363187323732883339338934403491
3542
3592
3642
3691374037893837388639343982
3T-618 wp07
3950100150200250300350400450500551601651701751801851901951100110511102115212021252130213531403145315041554160416541704
1754180518551906195620072058210921602211226223132364
241524672518257026222673
3T-620 wp05 501001502002503003504004505005506016517017518018509009501000104910991149119812481297134713961445
14941544
1593
1642
1691
1741
1790
3T-622 wp09.1
395010015020025030035040145150155160165270275280285290395310031053110311531203125313031353140214521502
1552
3T-623 wp05 v5
39501001502002503003504014515015516026527027528038539039531003105311031153120312531302
1352
1401
3T-624 wp05 v5
3950100150200250300350400451501551602652702753803853904954100410541104
3T-625 wp07.1
39501001502002503003514014515015526026537037538048549043T-626 wp05 v5
3950100150200250300351401451501552602
652
3T-627 wp05 v5
SURVEY PROGRAM
Date: 2019-07-03T00:00:00 Validated: Yes Version:
From To Tool
39.00 500.00 r.5 SDI_URSA1
500.00 2670.00 MWD+IFR2+SAG+MS
2670.00 11540.00 MWD+IFR2+SAG+MS
11540.00 24021.99 MWD+IFR2+SAG+MS
CASING DETAILS
TVD MD Name
2437.58 2670.00 10-3/4" Surface Casing
5008.72 11545.00 7-5/8" Intermediate Casing
5017.28 24021.99 4-1/2" Production Liner
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 39.00 0.00 0.00 39.00 0.00 0.00 0.00 0.00 0.00
2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.00
3 500.00 2.00 315.00 499.96 2.47 -2.47 1.00 315.00 3.37 Start Build 2.00
4 1628.31 24.57 315.00 1591.00 184.60 -184.60 2.00 0.00 251.79 Start 109.95 hold at 1628.31 MD
5 1738.26 24.57 315.00 1691.00 216.92 -216.92 0.00 0.00 295.88 Start Build 2.50
6 2751.22 49.89 315.00 2491.00 646.74 -646.74 2.50 0.00 882.15 Start 20.00 hold at 2751.22 MD
7 2771.22 49.89 315.00 2503.89 657.56 -657.56 0.00 0.00 896.91 Start DLS 3.00 TFO -8.67
8 3599.03 74.51 311.23 2887.13 1152.06 -1189.72 3.00 -8.67 1590.06 Start 7843.22 hold at 3599.03 MD
911442.25 74.51 311.23 4982.32 6133.79 -6873.78 0.00 0.00 8732.97 Start DLS 3.25 TFO 69.12
1011989.19 81.40 328.00 5097.19 6540.06 -7218.02 3.25 69.12 9256.40 Start Build 3.00
11 12239.19 88.90 328.00 5118.31 6751.16 -7349.94 3.00 0.00 9505.13 3T Grewingk T01 103124 Start 20.00 hold at 12239.19 MD
1212259.19 88.90 328.00 5118.69 6768.12 -7360.53 0.00 0.00 9525.11 Start DLS 3.00 TFO 89.48
1312965.62 89.16 349.19 5130.78 7422.00 -7616.81 3.00 89.4810220.08 Start 67.59 hold at 12965.62 MD
1413033.21 89.16 349.19 5131.77 7488.38 -7629.48 0.00 0.0010284.03 Start DLS 2.50 TFO -64.96
1513112.43 90.00 347.40 5132.35 7565.95 -7645.55 2.50 -64.9610359.38 3T Grewingk T02 103124 Start DLS 2.50 TFO -60.22
1613191.38 90.98 345.69 5131.67 7642.73 -7663.92 2.50 -60.2210435.18 Start 2503.69 hold at 13191.38 MD
1715695.08 90.98 345.69 5088.85 10068.35 -8282.81 0.00 0.0012848.94 Start DLS 1.00 TFO -179.02
1815793.10 90.00 345.67 5088.01 10163.32 -8307.05 1.00 -179.0212943.45 3T Grewingk T03 103124 Start DLS 1.00 TFO 179.96
1915991.39 88.02 345.67 5091.44 10355.40 -8356.12 1.00 179.9613134.62 Start 1064.22 hold at 15991.39 MD
2017055.60 88.02 345.67 5128.26 11385.89 -8619.33 0.00 0.0014160.22 Start DLS 1.50 TFO 0.25
21 17187.80 90.00 345.68 5130.55 11513.95 -8652.03 1.50 0.2514287.67 3T Grewingk T04 103124 Start DLS 1.50 TFO 0.81
2217353.93 92.49 345.72 5126.94 11674.88 -8693.06 1.50 0.8114447.79 Start 617.20 hold at 17353.93 MD
2317971.13 92.49 345.72 5100.11 12272.43 -8845.21 0.00 0.0015042.27 Start DLS 1.00 TFO -179.62
2418050.30 91.70 345.71 5097.21 12349.10 -8864.73 1.00 -179.6215118.55 3T Grewingk T05 103124 Start DLS 1.00 TFO 179.86
2518118.39 91.02 345.71 5095.59 12415.07 -8881.53 1.00 179.8615184.18 Start 3846.93 hold at 18118.39 MD
26 21965.33 91.02 345.71 5027.17 16142.42 -9830.81 0.00 0.0018892.44 Start DLS 1.00 TFO -179.91
27 22067.23 90.00 345.71 5026.26 16241.16 -9855.96 1.00 -179.9118990.69 3T Grewingk T06 103124 Start DLS 1.00 TFO -178.98
28 22136.40 89.31 345.70 5026.68 16308.19 -9873.04 1.00 -178.9819057.37 Start 704.86 hold at 22136.40 MD
29 22841.26 89.31 345.70 5035.18 16991.15 -10047.16 0.00 0.0019736.93 Start DLS 1.00 TFO 23.61
30 22916.73 90.00 346.00 5035.64 17064.33 -10065.61 1.00 23.6119809.64 3T Grewingk T07 103124 Start DLS 1.00 TFO -16.85
31 23021.12 91.00 345.70 5034.73 17165.54 -10091.13 1.00 -16.8519910.20 Start 1000.88 hold at 23021.12 MD
32 24021.99 91.00 345.70 5017.28 18135.25 -10338.35 0.00 0.00 20875.07 3T Grewingk T08 103124 TD at 24021.99
3T-619 wp07.2AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 500.00 r.5 SDI_URSA1500.00 2670.00 MWD+IFR2+SAG+MS2670.00 11540.00 MWD+IFR2+SAG+MS11540.00 24021.99 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2437.582670.0010-3/4" Surface Casing5008.7211545.007-5/8" Intermediate Casing5017.2824021.994-1/2" Production Liner1515303045456060757590900901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [30 usft/in]39611111612112613113614114615115616126627137648148659169671018106911191170122112711322137314233T-6211540159016401690174017891838188819371987203620862135218522352284233423842434248325332583263326833T-618 wp0739501001502002503003504004505005516016517017518018519019511001105111021152120212521302135314031453150415541604165417041754180518551906195620072058210921603T-620 wp05 v55010015020025030035040045050055060165170175180185090095010001049109911491198124812973T-622 wp09.139501001502002503003504014515015516016527027528028529039533T-623 wp05 v539501001502002503003504014515015516023T-624 wp05 v539 500500 800800 11001100 15001500 20002000 25002500 30003000 50005000 90009000 1700017000 24022From Colour To MD39.00 To 2700.00MD Azi TFace39.00 0.00 0.00300.00 0.00 0.00500.00 315.00 315.001628.31 315.00 0.001738.26 315.00 0.002751.22 315.00 0.002771.22 315.00 0.003599.03 311.23 -8.6711442.25311.23 0.0011989.19 328.00 69.1212239.19 328.00 0.0012259.19 328.00 0.0012965.62 349.19 89.4813033.21 349.19 0.0013112.43 347.40 -64.9613191.38 345.69 -60.2215695.08 345.69 0.0015793.10 345.67 -179.0215991.39 345.67 179.9617055.60 345.67 0.0017187.80 345.68 0.2517353.93 345.72 0.8117971.13 345.72 0.0018050.30 345.71 -179.6218118.39 345.71 179.8621965.33 345.71 0.0022067.23 345.71 -179.9122136.40 345.70 -178.9822841.26 345.70 0.0022916.73 346.00 23.6123021.12 345.70 -16.8524021.99 345.70 0.00
3T-619 wp07.2AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 500.00 r.5 SDI_URSA1500.00 2670.00 MWD+IFR2+SAG+MS2670.00 11540.00 MWD+IFR2+SAG+MS11540.00 24021.99 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2437.582670.0010-3/4" Surface Casing5008.7211545.007-5/8" Intermediate Casing5017.2824021.994-1/2" Production Liner3030606090901201201501501801800901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in]37873830387339163959400240454089413241754219Nuna 1378738303873391639594002404540894132417542192604265026972744279128372883292929753021306731143160320732543300334833953442348935353581362936783T-612262626752724277328212869291629633010305631023147319232363T-617 wp1026492700275228033T-615 wp0626332683273427842834288429342985303530863136318732373288333933893440349135423592364236913740378938373886393439824031407941273T-618 wp0726222673272527772829288329363T-620 wp0539 500500 800800 11001100 15001500 20002000 25002500 30003000 50005000 90009000 1700017000 24022From Colour To MD2600.00 To 11600.00MD Azi TFace39.00 0.00 0.00300.00 0.00 0.00500.00 315.00 315.001628.31 315.00 0.001738.26 315.00 0.002751.22 315.00 0.002771.22 315.00 0.003599.03 311.23 -8.6711442.25311.23 0.0011989.19 328.00 69.1212239.19 328.00 0.0012259.19 328.00 0.0012965.62 349.19 89.4813033.21 349.19 0.0013112.43 347.40 -64.9613191.38 345.69 -60.2215695.08 345.69 0.0015793.10 345.67 -179.0215991.39 345.67 179.9617055.60 345.67 0.0017187.80 345.68 0.2517353.93 345.72 0.8117971.13 345.72 0.0018050.30 345.71 -179.6218118.39 345.71 179.8621965.33 345.71 0.0022067.23 345.71 -179.9122136.40 345.70 -178.9822841.26 345.70 0.0022916.73 346.00 23.6123021.12 345.70 -16.8524021.99 345.70 0.00
3T-619 wp07.2AC FlipbookSURVEY PROGRAMDepth From Depth To Tool39.00 500.00 r.5 SDI_URSA1500.00 2670.00 MWD+IFR2+SAG+MS2670.00 11540.00 MWD+IFR2+SAG+MS11540.00 24021.99 MWD+IFR2+SAG+MSCASING DETAILSTVDMDName2437.582670.0010-3/4" Surface Casing5008.7211545.007-5/8" Intermediate Casing5017.2824021.994-1/2" Production Liner3030606090901201201501501801800901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [60 usft/in]39 500500 800800 11001100 15001500 20002000 25002500 30003000 50005000 90009000 1700017000 24022From Colour To MD11500.00 To 24022.00MD Azi TFace39.00 0.00 0.00300.00 0.00 0.00500.00 315.00 315.001628.31 315.00 0.001738.26 315.00 0.002751.22 315.00 0.002771.22 315.00 0.003599.03 311.23 -8.6711442.25311.23 0.0011989.19 328.00 69.1212239.19 328.00 0.0012259.19 328.00 0.0012965.62 349.19 89.4813033.21 349.19 0.0013112.43 347.40 -64.9613191.38 345.69 -60.2215695.08 345.69 0.0015793.10 345.67 -179.0215991.39 345.67 179.9617055.60 345.67 0.0017187.80 345.68 0.2517353.93 345.72 0.8117971.13 345.72 0.0018050.30 345.71 -179.6218118.39 345.71 179.8621965.33 345.71 0.0022067.23 345.71 -179.9122136.40 345.70 -178.9822841.26 345.70 0.0022916.73 346.00 23.6123021.12 345.70 -16.8524021.99 345.70 0.00
3T-619 wp07.2 Spider Plot
11:37, June 17 2025
39.00 To 24021.99
Northing (3500 usft/in)Easting (3500 usft/in)
3035404550556065Colville Delta 330
35
40
4550NDST-0230
35
40
45
50NDST-02PB13 03540
4 550Nuna 13 035404550Nuna 1PB130354045503T-61330
35
40
45
503T-60330
35
40
45
5 03T-60530
35
40
45
5 03T-608303540455 03T-61230354045503T-61330
35
4
045503T-61630
35
4
045503T-616PB130
35
4
045503T-616PB230354045503T-617 wp1030354045505
5 3T-6213035
40 3T-730303 5
4 0 3T-73130354045503T-601 wp05 v530354045503T-602 wp05 v53
0
3
5
4
0
4
5
503T-604 wp05 v530
35
40
45
503T-606 wp0830
35
40
45
5 03T-607 wp053 0
3 5
4 0
4 5
5 03T-609 wp063 0
3 5
4 0
4 5
5 03T-610 wp05303540455 03T-611 wp1030
35
40
45503T-614 wp0630354045
5 0 3T-615 wp0630354045
5 0 3T-618 wp073035404550 3T-620 wp05 v530354045503T-622 wp09.13035404550 3T-623 wp05 v530354045503T-624 wp05 v530354045503T-625 wp07.13035404550 3T-626 wp05 v530
35
40
4
5503T-627 wp05 v530354045503T-628 wp0630354045503T-629 wp05 v530354045503T-619 wp07.2
3T-619 wp07.2 Spider Plot
11:37, June 17 2025
39.00 To 24021.99
Northing (2000 usft/in)Easting (2000 usft/in)
3035404550556065Colville Delta 330
35
40
4550NDST-0230
35
40
45
50NDST-02PB13 0
3 5
4 0
4 550Nuna 13 0
3 5
4 0
4 5
5 0Nuna 1PB1303540455 03T-61330
35
40
45
503T-60330
35
40
45
5 03T-60530
35
40
45
5 03T-608303540455 03T-612303540455 03T-6133T-6163T-616PB13T-616PB230354045503T-617 wp1030354045505
5 3T-62130
35
403T-730303 5
4 03T-7313035403T-601 wp05 v530353T-602 wp05 v53
0
3
5
4
0
4
53T-604 wp05 v530
35
40
45
503T-606 wp0830
35
40
45
5 03T-607 wp053 0
3 5
4 0
4 5
5 03T-609 wp063 0
3 5
4 0
4 5
5 03T-610 wp05303540455 03T-611 wp103T-614 wp0630354045
5 0 3T-615 wp0630354045
5 0 3T-618 wp07303540453T-620 wp05 v530354045503T-622 wp09.13035403T-623 wp05 v530354045503T-624 wp05 v530354045503T-625 wp07.13035403T-626 wp05 v53T-627 wp05 v5303540453T-628 wp06303540453T-629 wp05 v530354045503T-619 wp07.2
3T-619 wp07.2Spider Plot11:39, June 17 202539.00 To 24021.99Northing (500 usft/in)Easting (500 usft/in)1416182022242628NDST-021416182022242628NDST-02PB11416182022242628303234363840Nuna 11416182022242628303234363840Nuna 1PB1141618202224262830323T-613141618202224263T-60314161820222426283T-6051416182022242628303234363T-608141618202224262830323436384042443T-612141618202224262830323T-6131416183T-6161416183T-616PB11416183T-616PB214161820222426283032343638404244463T-617 wp1014161820222426283032343T-6211416182022242 6 2830323436383T-7301416182022242 6283032 3436383T-73114161 83T-601 wp05 v51 4
1 6
1 83T-602 wp05 v51416182022243T-604 wp05 v51416182022243T-606 wp0814161820222426283032343T-607 wp051416182022242628303234363T-609 wp0614161820222426283032343T-610 wp051416182022242628303234363840423T-611 wp101416183T-614 wp0614161820222426283T-615 wp06141618202224262830323T-618 wp07141618202224262830323T-620 wp05 v5141618202224262830323436383T-622 wp09.1141618202224262830323T-623 wp05 v514161820222426283032343T-624 wp05 v514161820222426283032343T-625 wp07.11416182022242628303T-626 wp05 v514163T-627 wp05 v5141618202224262 8
3 0
3 23T-628 wp06141618202224262830323T-629 wp05 v514161820222426283032343T-619 wp07.2
3T-619 wp07.2Spider Plot11:40, June 17 202539.00 To 24021.99Northing (95 usft/in)Easting (95 usft/in)8101214NDST-028101214NDST-02PB1121416Nuna 1121416Nuna 1PB110121416183T-6131214161820223T-61210121416183T-61324681012143T-61624681012143T-616PB124681012143T-616PB2246810121416183T-617 wp1024
681012141618203T-621246810121416182022243T-7300246810121416182022242 628 30323436383T-7311416183T-611 wp10101214163T-614 wp06246810121416183T-615 wp0624681012141618203T-618 wp0724681012141618203T-620 wp05 v502468101214161820223T-622 wp09.12468101214161820223T-623 wp05 v52468101214161820223T-624 wp05 v524681012141618203T-625 wp07.124681012141618203T-626 wp05 v52468103T-627 wp05 v524681012141618203T-628 wp0624681012141618203T-629 wp05 v524681012141618203T-619 wp07.2
3T-619 wp07.2Colville Delta 3NDST-02Nuna 1Nuna 1PB13T-6133T-6123T-6133T-6163T-616PB13T-616PB23T-617 wp103T-6213T-609 wp063T-611 wp103T-614 wp063T-622 wp09.13T-624 wp05 v53T-625 wp07.13T-627 wp05 v53T-628 wp063T-629 wp05 v53-D View3T-619 wp07.211:53, June 17 2025
3T-619 wp07.2Colville Delta 3NDST-02NDST-02PB1Nuna 1Nuna 1PB13T-6133T-6053T-6123T-6133T-6163T-616PB13T-616PB23T-617 wp103T-6213T-611 wp103T-614 wp063T-622 wp09.13T-624 wp05 v53T-625 wp07.13T-628 wp063T-629 wp05 v53-D View3T-619 wp07.211:54, June 17 2025
6000900012000150001800021000South(-)/North(+) (3000 usft/in)-18000 -15000 -12000 -9000 -6000 -3000 0 3000 6000West(-)/East(+) (3000 usft/in)500050505100Colville Delta 3500050505100NDST-02500050505100NDST-02PB15100Nuna 15000505051003T-6135000505051003T-60350003T-6055000505051003T-6083T-6125000505051003T-6133T-6163T-616PB13T-617 wp103T-601 wp05 v53T-602 wp05 v55000505051003T-604 wp05 v55000505051003T-606 wp085000505051003T-607 wp055000505051003T-609 wp065000505051003T-610 wp053T-611 wp103T-614 wp063T-622 wp09.13T-624 wp05 v53T-625 wp07.13T-628 wp063T-629 wp05 v55000505051003T-619 wp07.23T-619 wp07.2Quarter Mile View12:00, June 17 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Grewingk T01 103124 5118.31 Circle (Radius: 100.00)3T Grewingk T02 103124 5132.35 Circle (Radius: 100.00)3T Grewingk T03 103124 5088.01 Circle (Radius: 100.00)3T Grewingk T04 103124 5130.55 Circle (Radius: 100.00)3T Grewingk T05 1031245097.21 Circle (Radius: 100.00)3T Grewingk T06 103124 5026.26 Circle (Radius: 100.00)3T Grewingk T07 103124 5035.64 Circle (Radius: 100.00)3T Grewingk T08 103124 5017.28 Circle (Radius: 100.00)3T-619 T1 QM 5118.31 Circle (Radius: 1320.00)3T-619 T5 QM 5097.21 Circle (Radius: 1320.00)3T-619 T8 QM 5017.28 Circle (Radius: 1320.00)
6000900012000150001800021000South(-)/North(+) (3000 usft/in)-18000 -15000 -12000 -9000 -6000 -3000 0 3000 6000West(-)/East(+) (3000 usft/in)500050505100Colville Delta 35100Nuna 15000505051003T-6133T-6163T-616PB15000505051003T-619 wp07.23T-619 wp07.2Quarter Mile View12:02, June 17 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Grewingk T01 103124 5118.31 Circle (Radius: 100.00)3T Grewingk T02 103124 5132.35 Circle (Radius: 100.00)3T Grewingk T03 103124 5088.01 Circle (Radius: 100.00)3T Grewingk T04 103124 5130.55 Circle (Radius: 100.00)3T Grewingk T05 1031245097.21 Circle (Radius: 100.00)3T Grewingk T06 103124 5026.26 Circle (Radius: 100.00)3T Grewingk T07 103124 5035.64 Circle (Radius: 100.00)3T Grewingk T08 103124 5017.28 Circle (Radius: 100.00)3T-619 T1 QM 5118.31 Circle (Radius: 1320.00)3T-619 T5 QM 5097.21 Circle (Radius: 1320.00)3T-619 T8 QM 5017.28 Circle (Radius: 1320.00)
02004006008001000South(-)/North(+) (200 usft/in)-1400 -1200 -1000 -800 -600 -400 -200 0 200West(-)/East(+) (200 usft/in)NDST-022438Nuna 1243824383T-61324383T-60824383T-61224383T-6133T-61624383T-617 wp1024383 T -6 2 1
2438
3T-7302 4 3 8 3T-73124383T-609 wp0624383T-610 wp0524383T-611 wp103T-614 wp0624383T-615 wp0624383T-618 wp0724383T-620 wp05 v524383T-622 wp09.124383T-623 wp05 v524383T-624 wp05 v524383T-625 wp07.124383T-626 wp05 v524383T-628 wp0624383T-619 wp07.23T-619 wp07.26XUIDFH&DVLQJ3RLQW
U12:22, June 17 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Grewingk T01 103124 5118.31 Circle (Radius: 100.00)3T Grewingk T02 103124 5132.35 Circle (Radius: 100.00)3T Grewingk T03 103124 5088.01 Circle (Radius: 100.00)3T Grewingk T04 103124 5130.55 Circle (Radius: 100.00)3T Grewingk T05 1031245097.21 Circle (Radius: 100.00)3T Grewingk T06 103124 5026.26 Circle (Radius: 100.00)3T Grewingk T07 103124 5035.64 Circle (Radius: 100.00)3T Grewingk T08 103124 5017.28 Circle (Radius: 100.00)3T-619 Srf Csg 2437.58 Circle (Radius: 500.00)3T-619 T1 QM 5118.31 Circle (Radius: 1320.00)3T-619 T5 QM 5097.21 Circle (Radius: 1320.00)3T-619 T8 QM 5017.28 Circle (Radius: 1320.00)
02004006008001000South(-)/North(+) (200 usft/in)-1400 -1200 -1000 -800 -600 -400 -200 0 200West(-)/East(+) (200 usft/in)24383T-61324383T-61224383T-6133T-61624383T-617 wp102438
3T-7302 4 3 8 3T-73124383T-619 wp07.23T-619 wp07.26XUIDFH&DVLQJ3RLQW
U12:21, June 17 2025WELLBORE TARGET DETAILS (MAP CO-ORDINATES)Name TVD Shape3T Grewingk T01 103124 5118.31 Circle (Radius: 100.00)3T Grewingk T02 103124 5132.35 Circle (Radius: 100.00)3T Grewingk T03 103124 5088.01 Circle (Radius: 100.00)3T Grewingk T04 103124 5130.55 Circle (Radius: 100.00)3T Grewingk T05 1031245097.21 Circle (Radius: 100.00)3T Grewingk T06 103124 5026.26 Circle (Radius: 100.00)3T Grewingk T07 103124 5035.64 Circle (Radius: 100.00)3T Grewingk T08 103124 5017.28 Circle (Radius: 100.00)3T-619 Srf Csg 2437.58 Circle (Radius: 500.00)3T-619 T1 QM 5118.31 Circle (Radius: 1320.00)3T-619 T5 QM 5097.21 Circle (Radius: 1320.00)3T-619 T8 QM 5017.28 Circle (Radius: 1320.00)
3T-619 wp07.2 Surface Location
3T-619 wp07.2 Surface Location
# Schlumberger-Confidential
3T-619 wp07.2 Surface Casing
3T-619 wp07.2 Surface Casing
# Schlumberger-Confidential
3T-619 wp07.2 Top Moraine
3T-619 wp07.2 Top Moraine
# Schlumberger-Confidential
3T-619 wp07.2 Intermediate Csg
3T-619 wp07.2 Intermediate Csg
# Schlumberger-Confidential
3T-619 wp07.2 TD
3T-619 wp07.2 TD
# Schlumberger-Confidential
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From:Dai, Weifeng
To:Davies, Stephen F (OGC); AOGCC Permitting (CED sponsored); Loepp, Victoria T (OGC); Dewhurst, Andrew D
(OGC); Guhl, Meredith D (OGC)
Cc:Hobbs, Greg S
Subject:Re: [EXTERNAL]RE: 3T-619 APD Application
Date:Thursday, July 24, 2025 6:57:18 AM
Hi Steve,
The well will have extended flowback. It is possible it extends few days beyond 30 day mark.
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From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Wednesday, July 23, 2025 6:14:44 PM
To: Dai, Weifeng <Weifeng.Dai@conocophillips.com>; AOGCC Permitting (CED sponsored)
<aogcc.permitting@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst,
Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>
Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>
Subject: RE: [EXTERNAL]RE: 3T-619 APD Application
Hello Weifeng,
Yes, this Permit to Drill application is under review. Does CPAI plan to pre-produce this well
for an extended period (30 days or longer), or will it be flowed back briefly to clean up the
wellbore?
Thanks Again and Be Well,
Steve Davies
Senior Petroleum Geologist
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: Dai, Weifeng <Weifeng.Dai@conocophillips.com>
Sent: Wednesday, July 23, 2025 3:47 PM
To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Loepp, Victoria T (OGC)
<victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Davies, Stephen F (OGC)
<steve.davies@alaska.gov>
Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>
Subject: RE: [EXTERNAL]RE: 3T-619 APD Application
Good afternoon,
I am just checking to see if any updates on the permit, we are looking to spud the well in about
1 week if everything goes well.
Weifeng Dai
ConocoPhillips Alaska
Staff Drilling Engineer
Cell: 907-346-0324
From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Sent: Wednesday, June 18, 2025 9:49 AM
To: Dai, Weifeng <Weifeng.Dai@conocophillips.com>; Loepp, Victoria T (OGC)
<victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Davies, Stephen F (OGC)
<steve.davies@alaska.gov>
Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>
Subject: [EXTERNAL]RE: 3T-619 APD Application
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.
Hello,
This application has been received for processing.
Thank you,
Grace Christianson
Executive Assistant,
Alaska Oil & Gas Conservation Commission
(907) 793-1230
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 Grace Christianson at (907-793-1230) or
(grace.christianson@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: Dai, Weifeng <Weifeng.Dai@conocophillips.com>
Sent: Wednesday, June 18, 2025 7:26 AM
To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>; Loepp, Victoria T (OGC)
<victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Davies, Stephen F (OGC)
<steve.davies@alaska.gov>
Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>
Subject: 3T-619 APD Application
Dear All,
Please find attached 3T-619 APD application, please reach out if you have any questions.
Weifeng Dai
ConocoPhillips Alaska
Staff Drilling Engineer
Cell: 907-346-0324
.58'67
CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following
conditions:
- CPAI must continue to implement the Between Wells Maintenance Program as approved
by AOGCC.
- The initial test after rigging up BOPE to drill a well must be to the rated working pressure
as provided in API Standard 53.
- CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit.
- CPAI must adhere to original equipment manufacturer recommendations and replacement
parts for BOPE.
- Requests for extensions beyond 21 days must include justification with supporting
information demonstrating the additional time is necessary for well control purposes or to
mitigate a stuck drill string.
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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.
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.
KRU 3T-619
KUPARUK RIVER, TOROK OILKUPARUK RIVER
225-063
WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3T-619Initial Class/TypeSER / PENDGeoArea890Unit11160On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2250630Field & Pool:KUPARUK RIVER, TOROK OIL - 490169NA1 Permit fee attachedYes Surface Location lies within ADL0025528; Top Productive Interval lies in ADL0392959;2 Lease number appropriateYes TD lies within ADL0393884.3 Unique well name and numberYes KUPARUK RIVER, TOROK OIL - 490169 - governed by CO 725A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes AIO 39A14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes Yes: See attached email labeled "Attachment 3T-619 Area of Review (AOR). SFD15 All wells within 1/4 mile area of review identified (For service well only)Yes May be pre-produced for more than 30 days.16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 81' conductor18 Conductor string providedYes SC set at 2670' MD19 Surface casing protects all known USDWsYes 149% excess planned20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes Max reservoir pressure is 2243 psig(8.6 ppg EMW); will drill w/ 8.6-11.0 ppg EMW28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP is 1741 psig; will test BOPs to 5000 psig initially and subsequently to 4000 psig30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes33 Is presence of H2S gas probableYes 3T-613 in AOR34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures are required. H2S is present in significant quantities on 3S-Pad to the south.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.446 to 0.462 psi/ft (8.6 to 8.9 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/24/2025ApprVTLDate7/10/2025ApprSFDDate7/23/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:
