Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout2025-09-16_325-5661. 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
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.”
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.
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.
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4
S
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-
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S
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-
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Interval 1
Moraine
@ 23832 - 23836.34 ft 136.7 °F"Alpha Sleeve
Interval 2
Moraine
@ 23287 - 23291.34 ft 137 °F"Frac Sleeve 1
Interval 3
Moraine
@ 22787 - 22791.34 ft 137.3
°F"Frac Sleeve 2
Interval 4
Moraine
@ 22287 - 22291.34 ft 137.5 °F"Frac Sleeve 3
Li
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@ 19787 - 19791.34 ft 137.9 °F"Frac Sleeve 8
Interval 5
Moraine
@ 21786 - 21790.34 ft 137.6 °F"Frac Sleeve 4
Interval 6
Moraine
@ 21287 - 21291.34 ft 137.8 °F"Frac
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Interval 7
Moraine
@ 20787 - 20791.34 ft 138 °F"Frac
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Interval 8
Moraine
@ 20287 - 20291.34 ft 137.9 °F"Frac
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Interval 11
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@ 18786 - 18790.34 ft 137.5 °F"Frac
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Interval 12
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@ 18286 - 18290.34 ft 137.5 °F"Frac
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Interval 13
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@ 17786 - 17790.34 ft 138.1 °F"Frac
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Interval 14
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@ 17285 - 17289.34 ft 138.5 °F"Frac Sleeve
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Interval 15
Moraine
@ 16785 - 16789.34 ft 138.7 °F"Frac Sleeve 14
Interval 16
Moraine
@ 16285 - 16289.34 ft 138.8 °F"Frac
Sleeve 15
Interval 17
Moraine
@ 15786 - 15790.34 ft 138.7 °F"Frac
Sleeve 16
Interval 18
Moraine
@ 15287 - 15291.34 ft 138.8
°F"Frac Sleeve 17
Interval 19
Moraine
@ 14787 - 14791.34 ft 138.9 °F"Frac Sleeve
18
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Interval 20
Moraine
@ 14289 - 14293.34 ft 138.8 °F"Frac Sleeve 18
Interval 21
Moraine
@ 13788 - 13792.34 ft 138.8 °F"Frac
Sleeve 20
Interval 22
Moraine
@ 13288 - 13292.34 ft 138.8 °F"Frac Sleeve 21
Pr
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9
Pl
a
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D
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g
n
5
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:
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API Number:
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