Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout224-084DA
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PBU S-126B
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage,
AK 99503
224-084
50-029-23363-02-00
ADL 0028257, 0028258
14826 6805
80
4780
11482
3532
14395
20"
10-3/4"
7"
3-1/2" x 3-1/4" x 2-7/8"
6827
29 - 109
28 - 4808
25 - 11507
11294 - 14826
5400
29 - 109
28 - 3193
25 - 6727
6545 - 6805
None14395
1490
6450
7240
10160
14290- 14695 4-1/2" 12.6# L-80 23 - 113606828 - 6812
4-1/2" Baker S-3 Perm Packer
No SSSV Installed
11294, 6545
Torin Roschinger
Operations Manager
Hunter Gates
hunter.gates@hilcorp.com
(907) 777-8326
PRUDHOE BAY
6/23/2025
AURORA OIL AURORA OIL
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662)
Date: 2025.07.03 05:55:57 -
08'00'
Torin Roschinger
(4662)
By Grace Christianson at 8:09 am, Jul 03, 2025
325-400
JJL 7/3/25
Include a PRV on OA or hold an open bleed on OA during fracture treatment.
6/23/2025
10-404
CDW 07/03/2025
SFD 7/3/2025 DSR-7/3/25'tϬϳͬϬϯͬϮϬϮϱ
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.07.03 12:13:01 -08'00'07/03/25
RBDMS JSB 070925
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Well Name:S-126B Permit to Drill:224-084
Current Status:Operable, Producer API Number:50-029-23363-02
Estimated Start Date:6/23/2025 Estimated Duration:5days
Regulatory Contact:Abbie Barker Sundry Number:325-270, 325-340,TBD
First Call Engineer:Hunter Gates (907) 777-8326 (O) (215) 498-7274 (M)
Second Call Engineer:Tyson Shriver (907) 564-4542 (O) (406) 690-6385 (M)
Current Bottom Hole Pressure:3,374 psi @6,600’ TVDss
Max Anticipated Treating Pressure:5,400 psi
Last SI WHP: Tbg dead, came on w/ ~1700 psi w/ GL but died off
Min ID:2.313” @ 11,283’ MD X-Nipple
Max Angle:100 deg @ 12,434’ MD
Brief Well Summary:
S-126B is a Kuparuk producer that is Operable but currently shut-in due to its inability to flow. This was a
CTD sidetrack completed in early February 2025. We shot 30’ of perforations with service coil and
attempted to flow the well back with gas lift. We were able to unload a few wellbore volumes and then
we started seeing some oil from the formation until the well starting gassing around on us. We saw 18%
oil cut of 28.8 API oil. After several hours of non-sustained flow, the well was freeze protected and left
shut-in.
Objective:
Set dummy GLV’s. Pressure Test. Install tree-saver. Perform hydraulic fracture stimulation to stimulate
the Kuparuk C formation. Flow well back through portable test separator.
Updated Objective (6/4/2025): Attempted 6/4-6/6
The initial interval pressured up prematurely and we consistently struggled with injection rates. The plan
is to perform a tractor plug and perf by setting a CIBP above the current perforated interval at 14,630’
MD and then perforating a smaller interval from 14,290’-14,300’ MD. From here we plan to perform the
same frac design on the new interval and proceed with the original plan from there.
Updated Objective (7/4/2025):
The second interval pressured up prematurely as well. Although we were beginning to make headway
on initiating a dominant fracture, we struggled with injection rates when we pumped scour. The plan is
to perform a tractor plug and perf by setting a CIBP above the current perforated interval between
14,200’-14,250’ MD and then perforating a 10’ interval from 14,150’-14,160’ MD. We will be using both
different phasing and different charges altogether on this new interval. From here we plan to perform
the same frac design on the new interval and proceed with the original plan from there.
Current Status:
Operable Producer, Shut-In
Recent Integrity:
05-21-2025 – MIT-T passed to 3,190 psi and MIT-IA passed to 4,003 psi
2/11/2025 – PT LTP to 1500 psi
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Procedure:
Slickline/Fullbore Completed 5/21
1. MIRU SL.
2. Make a drift run to deviation (~11,678’ MD).
3. Run in with gauges for SBHPS stops at 11,678’, 11,555’, 11,437’ and 11,320’ MD (equivalent to
100’ ssTVD stops).
4. Set plug in X-nipple at 11,283’.
5. Set catcher on top of plug.
6. Pull LGLVs. Install DGLV in St #2 and flowsleeve in St #1
7. Circulate wellbore to 1% KCl or Seawater and crude freeze protect. U-tube crude freeze protect.
a. Total TBG and IA Volume down to St #1: 342 bbls
b. Freeze protect volume to 2500’ in TBG and IA: 38 bbls + 47 bbls = 85 bbls
8. Pull flowsleeve from St #1 and install DGLV.
9. Perform MIT-T to target 3100 psi (max applied 3300 psi).
10. Perform MIT-IA to target 3800 psi (max applied 4100 psi). Hold 2000 psi on tubing during MIT-IA.
11. Pull catcher and plug.
12. Fullbore to perform an injectivity test on formation once MIT’s are completed to max target
pressure of 3000 psi.
Frac Attempted 6/2-6/3
1. MIRU frac spread and associated equipment/tanks.
a. Heat water to 110 deg F, minimum pumping temp – 90 deg F
2. Pull water from each tank and have SLB lab test our water quality:
a. pH - ~7
i. Higher pH delays the hydration of the gel and delays break
b. Calcium/magnesium <500 mg/l
i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which
tend to be insoluble
c. Bicarbonate - <400 mg/l
i. High bicarbonate levels will cause slow hydration times and elevated delay times
with X-linking fluids. If we have elevated bicarbonate levels and have introduced
delay agents, it could have an exponential effect in delay times.
d. Chlorides-<10,000 mg/l
i. This fluid system should be able to cope with elevated Chloride levels
e. Iron (Fe+3) - <5 mg/l
i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have
an accelerated effect. Can cause viscosity degradation in linear gels (especially if
batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking
sites.
f. TDS – minimal/<5000
i. Effects depend on the solids that are dissolved in the fluid.
3. Install tree saver.
4. Perform pressure tests prior to performing hydraulic fracture stimulation.
a. Pressure test surface lines and tree saver to at least 7,125 psi.
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
b. Pressure test pump kick outs to 5,515 psi and global kick outs to 5,820 psi.
c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at
3,610 psi.
d. Bring IA pressure up and hold at 3,310 psi.
5. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum
allowable treating pressure is 6,125 psi.
6. RDMO frac equipment and pull tree saver. Freeze protect well.
E-line Completed 6/4
1. MIRU EL and MU tractor.
2. Function test tractor and MU GR/CCL with 10’ perf gun and a CIBP below it.
3. RIH to deviation at ~11,800’ MD and begin tractoring to target depth.
Stage # Fluid Stage
Prop Con
(ppa)
Rate
(bpm)
Volume
(bbls)
CUM Volume
(bbls)Proppant Name Proppant
(#)
CUM Proppant
(#)
1 FW w/ adds Injection Test 0 25 200 200 0 0
2 Shutdown 200 0
3 28# X-Link Pad 0.5 25 150 350 0 0
4 28# X-Link Scour 0 25 100 450 100 Mesh 2055 2055
5 28# X-Link Pad 0 25 150 600 0 2055
6 28# X-Link Flat 1 25 100 700 16-20 CarboBOND 4022 6077
7 28# X-Link Flat 2 25 50 750 16-20 CarboBOND 3859 9936
8 28# X-Link Flat 3 25 50 800 16-20 CarboBOND 5562 15498
9 28# X-Link Flat 4 25 50 850 16-20 CarboBOND 7137 22635
10 28# X-Link Flat 5 25 50 900 16-20 CarboBOND 8598 31233
11 28# X-Link Flat 6 25 50 950 16-20 CarboBOND 9957 41190
12 28# X-Link Flat 7 25 50 1000 16-20 CarboBOND 11224 52414
13 28# X-Link Flat 8 25 100 1100 16-20 CarboBOND 24816 77230
14 28# X-Link Flat 9 25 100 1200 16-20 CarboBOND 27035 104265
15 28# X-Link Flat 10 25 100 1300 16-20 CarboBOND 29117 133382
16 28# X-Link Flat 11 25 100 1400 16-20 CarboBOND 31076 164458
17 28# X-Link Flat 12 25 100 1500 16-20 CarboBOND 32921 197379
18 FW w/ adds Flush 0 25 150 1650 197379
19 Diesel Freeze Protect 0 25 40 1690 197379
Max of 3500 psi limited by MITIA 110% rule. CDW
07/03/2025
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
4. RIH to above current perforated interval at 14,665’-14,695’. Make correction and set CIBP at
14,630’ MD.
5. Prior to perforating the new interval, utilize a triplex to pump on the well and pressure up against
the plug with max applied pressure of 2,000 psi to ensure the plug is holding.
6. PUH and perforate 10’ from 14,290’-14,300’ MD.
7. POOH and RDMO EL.
8. Shut-in and secure well.
Frac Attempted 6/5
1. MIRU frac spread and associated equipment/tanks.
a. Heat water to 110 deg F, minimum pumping temp – 90 deg F
2. Install tree saver.
3. Perform pressure tests prior to performing hydraulic fracture stimulation.
a. Pressure test surface lines and tree saver to at least 7,125 psi.
b. Pressure test pump kick outs to 5,515 psi and global kick outs to 5,820 psi.
c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at
3,610 psi.
d. Bring IA pressure up and hold at 3,310 psi.
4. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum
allowable treating pressure is 6,125 psi.
Stage # Fluid Stage
Prop Con
(ppa)
Rate
(bpm)
Volume
(bbls)
CUM Volume
(bbls)Proppant Name Proppant
(#)
CUM Proppant
(#)
1 FW w/ adds Injection Test 0 25 200 200 0 0
2 Shutdown 200 0
3 28# X-Link Pad 0.5 25 150 350 0 0
4 28# X-Link Scour 0 25 100 450 100 Mesh 2055 2055
5 28# X-Link Pad 0 25 150 600 0 2055
6 28# X-Link Flat 1 25 100 700 16-20 CarboBOND 4022 6077
7 28# X-Link Flat 2 25 50 750 16-20 CarboBOND 3859 9936
8 28# X-Link Flat 3 25 50 800 16-20 CarboBOND 5562 15498
9 28# X-Link Flat 4 25 50 850 16-20 CarboBOND 7137 22635
10 28# X-Link Flat 5 25 50 900 16-20 CarboBOND 8598 31233
11 28# X-Link Flat 6 25 50 950 16-20 CarboBOND 9957 41190
12 28# X-Link Flat 7 25 50 1000 16-20 CarboBOND 11224 52414
13 28# X-Link Flat 8 25 100 1100 16-20 CarboBOND 24816 77230
14 28# X-Link Flat 9 25 100 1200 16-20 CarboBOND 27035 104265
15 28# X-Link Flat 10 25 100 1300 16-20 CarboBOND 29117 133382
16 28# X-Link Flat 11 25 100 1400 16-20 CarboBOND 31076 164458
17 28# X-Link Flat 12 25 100 1500 16-20 CarboBOND 32921 197379
18 FW w/ adds Flush 0 25 150 1650 197379
19 Diesel Freeze Protect 0 25 40 1690 197379
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
5. RDMO frac equipment and pull tree saver. Freeze protect well.
Fullbore
1. MIRU pump truck.
2. Attempt to pump a full tubing volume of crude (~200 bbls) down tubing. If injectivity rate is low
<1 BPM, call OE to discuss. Max injection pressure of 3000 psi. Keep a differential on the tubing
to <2000 psi.
3. Ensure well is freeze protected. RDMO.
E-line
1. MIRU EL and MU tractor.
2. Function test tractor and MU GR/CCL with 10’ perf gun and a CIBP below it.
3. RIH to deviation at ~11,800’ MD and begin tractoring to target depth.
4. RIH to above current perforated interval at 14,290’-14,300’. Make correction and set CIBP at
between 14,200’-14,250’ MD.
5. Prior to perforating the new interval, utilize a triplex to pump on the well and pressure up against
the plug with max applied pressure of 2,000 psi to ensure the plug is holding.
6. PUH and perforate 10’ from 14,150’-14,160’ MD.
7. POOH and RDMO EL.
8. Shut-in and secure well.
Frac
1. MIRU frac spread and associated equipment/tanks.
a. Heat water to 110 deg F, minimum pumping temp – 90 deg F
2. Install tree saver.
3. Perform pressure tests prior to performing hydraulic fracture stimulation.
a. Pressure test surface lines and tree saver to at least 7,125 psi.
b. Pressure test pump kick outs to 5,515 psi and global kick outs to 5,820 psi.
c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set
at 3,610 psi.
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
d. Bring IA pressure up and hold at 3,310 psi.
4. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum
allowable treating pressure is 6,125 psi.
5. RDMO frac equipment and pull tree saver. Freeze protect well.
Coil Tubing (Pending) – FCO if early screenout occurs during frac or perfs are covered w/ proppant
1. MU BDJSN.
a. Recommended to run without checks so reverse circulating can be performed.
2. RIH dry and tag top of proppant.
3. PU and establish circulation.
a. Recommended to perform reverse FCO until returns are less than ~70%
4. FCO down to ~14,200’ MD.
Stage # Fluid Stage
Prop Con
(ppa)
Rate
(bpm)
Volume
(bbls)
CUM Volume
(bbls)Proppant Name Proppant
(#)
CUM Proppant
(#)
1 FW w/ adds Injection Test 0 25 200 200 0 0
2 Shutdown 200 0
3 28# X-Link Pad 0.5 25 150 350 0 0
4 28# X-Link Scour 0 25 100 450 100 Mesh 2055 2055
5 28# X-Link Pad 0 25 150 600 0 2055
6 28# X-Link Flat 1 25 100 700 16-20 CarboBOND 4022 6077
7 28# X-Link Flat 2 25 50 750 16-20 CarboBOND 3859 9936
8 28# X-Link Flat 3 25 50 800 16-20 CarboBOND 5562 15498
9 28# X-Link Flat 4 25 50 850 16-20 CarboBOND 7137 22635
10 28# X-Link Flat 5 25 50 900 16-20 CarboBOND 8598 31233
11 28# X-Link Flat 6 25 50 950 16-20 CarboBOND 9957 41190
12 28# X-Link Flat 7 25 50 1000 16-20 CarboBOND 11224 52414
13 28# X-Link Flat 8 25 100 1100 16-20 CarboBOND 24816 77230
14 28# X-Link Flat 9 25 100 1200 16-20 CarboBOND 27035 104265
15 28# X-Link Flat 10 25 100 1300 16-20 CarboBOND 29117 133382
16 28# X-Link Flat 11 25 100 1400 16-20 CarboBOND 31076 164458
17 28# X-Link Flat 12 25 100 1500 16-20 CarboBOND 32921 197379
18 FW w/ adds Flush 0 25 150 1650 197379
19 Diesel Freeze Protect 0 25 40 1690 197379
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
a. Once returns fall below ~70% pickup and circulate coiled tubing clean. Swap circulation to
the long way and continue FCO with gel sweeps.
b. If losses become unmanageable while forward circulating and perfs are still covered can
attempt FCO with diesel. If losses are still unmanageable with diesel, coil will need to rig
down for SL to install gas lift valves.
Slickline
1. MIRU SL. Set LGLV design.
Portable Testers
1. MIRU, pressure test
2. POP the well to LRS with 1-1.5 MMSCFD Lift gas at minimum choke, adjust GL rate as necessary
to eliminate slugging. Flow the initial returns to the flowline as long as the shake-outs meet the
returned fluid/solids management guidelines.
a. If at any point, solids are >0.5%, divert returns to flowback tanks.
3. Limit flow to ~500 bpd
4. If solids are < 1%, after 1.5 wellbore volumes (291 bbls) increase the production rate to 750
BLPD.
5. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to
1000 BFPD.
6. Flow bottoms up (~194 bbls) and sample for solids production. If solids are still below 1%
continue to increase the flow rate in 250 BPD increments. The objective is to achieve maximum
drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well to clean
up before choke is opened further.
7. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr piggyback well test.
Attachments:
Old Wellbore Schematic
Old Proposed Wellbore Schematic
New Proposed Wellbore Schematic (to be stimulated)
Sundry Revision Change Form
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Old Wellbore Schematic:
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Old Proposed Wellbore Schematic
New Perforation Summary
Interval: 14,290’-14,300’
Shot Density: 6 SPF
CIBP @ 14,630’
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
New Proposed Wellbore Schematic
New Perforation Summary
Interval: 14,150’-14,160’
Shot Density: 4 SPF
Old Perforation Summary
Abandoned Interval: 14,290’-14,300’
Shot Density: 6 SPF
CIBP @ 14,395’
CIBP @ 14,200’
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Sundry Revision Change Form:
Changes to Approved Sundry Procedure
Date: June 4, 2025
Subject: S-126B Frac
Sundry #: 325-270, 325-340
Any modifications to an approved sundry will be documented and approved below. Changes to an approved
sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is
required before implementing the change.
Step Page Date Procedure Change
HNS
Prepared
By (Initials)
HNS
Approved
By
(Initials)
AOGCC Written
Approval
Received
(Person and
Date)
Frac
Step
4
36/4/25
Added Setting CIBP, shooting additional
perforations and Frac HRG TR Jack Lau, 6/4/25
Approval:
Operations Manager Date
Prepared:
Operations Engineer Date
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 May 27, 2025 (a) Application forSundry Approval(a)(1) Affidavit Provided with application. A.Dewhurst15MAY25(a)(2) Plat Provided with application. A.Dewhurst14MAY25(a)(2)(A) Well location Provided with application. Well lies in Section 35 of T12N, R12E, UM. A.Dewhurst15MAY25(a)(2)(B) Each water well within ½ mile None: There are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of PBU S-126B. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of PBU S-126B. A.Dewhurst15MAY25(a)(2)(C) Identify all well types within ½ mile Provided with application. Hilcorp has identified 212 wells within ½ mile. A.Dewhurst15MAY25(a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. This well lies within the Western Operating Area the of Prudhoe Bay Unit which is exempted under AEO 1. A.Dewhurst15MAY25(a)(4) Baseline water sampling plan None required. A.Dewhurst15MAY25(a)(5) Casing and cementing information Provided with application. Schematic attached. Multiple sidetracks and plug backs. CDW 05/13/2025 (a)(6) Casing and cementing operation assessment 10-3/4” surface casing cemented to surface.TOC in 7” casing at 4900 ft (CBL). CBL on file at AOGCC.Several sidetracks and plug backs.S-126B liner cemented from 13000 ft to TD of 14826 ft.4.5” tubing 3.5x3.25x2.675” liner will be anchored with apacker set at approx. 11294 ft with Kuparuk C top of 11473 ft.CBL conservatively shows good cement at area of interest sono cement concerns.No issues with cement for the upcoming stimulation.CDW 05/13/2025 ŚĞĐŬůŝƐƚĂůƐŽĂƉƉůŝĞƐƚŽ^ƵŶĚƌLJϯϮϱͲϰϬϬtϬϳͬϬϯͬϮϬϮϱ
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 May 27, 2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 Only exempt freshwater aquifers present. (See Section (a)(3), above.) A.Dewhurst 15MAY25 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates the Kuparuk hydrocarbon zone. For the parent wellbore S-126, the Kuparuk is isolated by the 7” production liner with TOC at 4,900’ MD (measured by CBL). For the S-126B well, the Kuparuk is isolated by the 3-1/2” x 3-1/4” x 2-7/8” liner cement. There is no CBL, but Hilcorp estimates 36 bbls of cement behind the liner and reported zero losses. A.Dewhurst 15MAY25/ CDW 05/13/2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3800 psi MITIA planned, 3100 psi MITT plan. CDW 05/13/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. max. frac. Pressure 6125 psi. Pump knock out 5515 and GORV 5820 psi., 10K tree saver, lines test 7125 psi. CDW 05/13/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: 188’ of shales of the HRZ and Kalubik with fracture gradient of 0.7 psi/ft to 0.72 psi/ft. Fracturing Zone: 307’ of Kuparuk sandstones and siltstones with a fracture gradient of 0.62 psi/ft to 0.66 psi/ft. Lower confining zone: 569’ of Miluveach shales with a fracture gradient of 0.72 psi/ft. MD and TVD depths provided in application. A.Dewhurst 15MAY25 (a)(10) Location, orientation, report on mechanical condition of each well that Provided with application. AOGCC evaluated all wells that may transect the confining zones within the PBU S-126B Area A.Dewhurst 15MAY25/
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 May 27, 2025 may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory of Review and found it highly unlikely that any of these wells will interfere with fracturing fluids due to cement-isolation and/or separation distance or direction. CDW 05/13/2025 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Hilcorp has identified 5 faults within the ½ mile of the proposed frac. Detailed descriptions for each are provided in the application. The closest fault is 550’ away. The anticipated fracture half-length is 200’. So, it is unlikely that any faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. A.Dewhurst 15MAY25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/13/2025 (a)(12)(A) Estimated volume Provided with application. 1690 bbl total dirty vol. 197K lb total proppant CDW 05/13/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/13/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided. CDW 05/13/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 05/13/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 5310 psi. Max. 6125 psi allowable treating pressure. Max pressure is 5515 psi to 5820 psi to Pump shutdown. Global ePRV 6125 psi. With 3310 psi back pressure IA (IA popoff set 3610 psi), max tubing differential should be 2815 psi. CDW 05/13/2025
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 May 27, 2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-length of the induced fractures is 200’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 110’ (top of about -6,725’ TVDSS and base of about -6,835’ TVDSS). A.Dewhurst 15MAY25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified but Hilcorp has options. CDW 05/13/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3310 psi back pressure, plan to test to 3800 psi, popoff set as 3610 psi CDW 05/13/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing 3.5x3.25x2.675” liner will be anchored with a packer set at approx. 11294 ft with Kuparuk C top of 11473 ft. 10-3/4” surface casing cemented to surface. TOC in 7” casing at 4900 ft (USIT). Several sidetracks and plug backs. S-126B liner cemented from 13000 ft to TD of 14826 ft. USIT/CBL conservatively shows good cement at area of interest so no cement concerns. CDW 05/13/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3100 psi. Max pressure differential is estimated as 2815 psi (6125 psi with 3310 psi backpressure) so test of 3100 psi satisfies 110% CDW 05/13/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 7125 psi line pressure test, pump knock out 5515-5820 psi with max. global kickout 5820 and 6125 psi. IA PRV set as 3610 psi. CDW 05/13/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/13/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3610 psi. Surface annulus open. Frac pressures continuously monitored. CDW 05/13/2025 (g) Annulus pressure 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time CDW 05/13/2025
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 May 27, 2025 monitoring & notification during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). A.Dewhurst 15MAY25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 15MAY25 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation.
7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in thes pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd?Yes No
Subsequent Form Required:
Approved By:Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU S-126B
Update to Sundry 325-
270
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage,
AK 99503
224-084
50-029-23363-02-00
ADL 0028257, 0028258
14826
Conductor
Surface
Intermediate
Production
Liner
6805
80
4780
11482
3532
14809
20"
10-3/4"
7"
3-1/2" x 3-1/4" x 2-7/8"
6806
29 - 109
28 - 4808
25 - 11507
11294 - 14826
5400
29 - 109
28 - 3193
25 - 6727
6545 - 6805
None
470
4020
5410
10530
None
1490
6450
7240
10160
14665 - 14695 4-1/2" 12.6# L-80 23 - 113606815 - 6812
Structural
4-1/2" Baker S-3 Perm Packer
No SSSV Installed
11294, 6545
6/4/2025
Jack Lau
Date:
Torin Roschinger
Operations Manager
Hunter Gates
hunter.gates@hilcorp.com
(907) 777-8326
PRUDHOE BAY
6/4/2025
Current Pools:
AURORA OIL
Proposed Pools:
AURORA OIL
Suspension Expiration Date:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 1:20 pm, Jun 04, 2025
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662)
Date: 2025.06.04 11:13:09 -
08'00'
Torin Roschinger
(4662)
325-340
6/4/2025
CDW 06/04/2025
6/4/2025
JJL 6/4/25
Include a PRV on OA or hold an open bleed on OA during fracture treatment.
10-404
A.Dewhurst 04JUN25
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.06.20 13:13:34
-08'00'
RBDMS JSB 062425
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Well Name:S-126B Permit to Drill:224-084
Current Status:Operable, Producer API Number:50-029-23363-02
Estimated Start Date:6/4/2025 Estimated Duration:5days
Regulatory Contact:Abbie Barker Sundry Number:325-270,TBD
First Call Engineer:Hunter Gates (907) 777-8326 (O)(215) 498-7274 (M)
Second Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M)
Current Bottom Hole Pressure:3,374 psi @ 6,600’ TVDss
Max Anticipated Treating Pressure:5,400 psi
Last SI WHP: Tbg dead, came on w/ ~1700 psi w/ GL but died off
Min ID:2.313” @ 11,283’ MD X-Nipple
Max Angle:100 deg @ 12,434’ MD
Brief Well Summary:
S-126B is a Kuparuk producer that is Operable but currently shut-in due to its inability to flow. This was a
CTD sidetrack completed in early February 2025. We shot 30’ of perforations with service coil and
attempted to flow the well back with gas lift. We were able to unload a few wellbore volumes and then
we started seeing some oil from the formation until the well starting gassing around on us. We saw 18%
oil cut of 28.8 API oil. After several hours of non-sustained flow, the well was freeze protected and left
shut-in.
Objective:
Set dummy GLV’s. Pressure Test. Install tree-saver. Perform hydraulic fracture stimulation to stimulate
the Kuparuk C formation. Flow well back through portable test separator.
Updated Objective (6/4/2025):
The initial interval pressured up prematurely and we consistently struggled with injection rates. The plan
is to perform a tractor plug and perf by setting a CIBP above the current perforated interval at 14,630’
MD and then perforating a smaller interval from 14,290’-14,300’ MD. From here we plan to perform the
same frac design on the new interval and proceed with the original plan from there.
Current Status:
Operable Producer, Shut-In
Recent Integrity:
x 09/23/2024 – MIT-T passed to 3,239 psi and CMIT-TxIA passed to 4,020 psi
x 2/11/2025 – PT LTP to 1500 psi
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Procedure:
Slickline/Fullbore Completed 5/21
1. MIRU SL.
2. Make a drift run to deviation (~11,678’ MD).
3. Run in with gauges for SBHPS stops at 11,678’, 11,555’, 11,437’ and 11,320’ MD (equivalent to
100’ ssTVD stops).
4. Set plug in X-nipple at 11,283’.
5. Set catcher on top of plug.
6. Pull LGLVs. Install DGLV in St #2 and flowsleeve in St #1
7. Circulate wellbore to 1% KCl or Seawater and crude freeze protect. U-tube crude freeze protect.
a. Total TBG and IA Volume down to St #1: 342 bbls
b. Freeze protect volume to 2500’ in TBG and IA: 38 bbls + 47 bbls = 85 bbls
8. Pull flowsleeve from St #1 and install DGLV.
9. Perform MIT-T to target 3100 psi (max applied 3300 psi).
10. Perform MIT-IA to target 3800 psi (max applied 4100 psi). Hold 2000 psi on tubing during MIT-IA.
11. Pull catcher and plug.
12. Fullbore to perform an injectivity test on formation once MIT’s are completed to max target
pressure of 3000 psi.
Frac Attempted 6/2-6/3
1. MIRU frac spread and associated equipment/tanks.
a. Heat water to 110 deg F, minimum pumping temp – 90 deg F
2. Pull water from each tank and have SLB lab test our water quality:
a. pH - ~7
i. Higher pH delays the hydration of the gel and delays break
b. Calcium/magnesium <500 mg/l
i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which
tend to be insoluble
c. Bicarbonate - <400 mg/l
i. High bicarbonate levels will cause slow hydration times and elevated delay times
with X-linking fluids. If we have elevated bicarbonate levels and have introduced
delay agents, it could have an exponential effect in delay times.
d. Chlorides-<10,000 mg/l
i. This fluid system should be able to cope with elevated Chloride levels
e.Iron (Fe+3) - <5 mg/l
i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have
an accelerated effect. Can cause viscosity degradation in linear gels (especially if
batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking
sites.
f. TDS – minimal/<5000
i. Effects depend on the solids that are dissolved in the fluid.
3. Install tree saver.
4. Perform pressure tests prior to performing hydraulic fracture stimulation.
a. Pressure test surface lines and tree saver to at least 7,125 psi.
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
b. Pressure test pump kick outs to 5,515 psi and global kick outs to 5,820 psi.
c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at
3,610 psi.
d. Bring IA pressure up and hold at 3,310 psi.
5. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum
allowable treating pressure is 6,125 psi.
6. RDMO frac equipment and pull tree saver. Freeze protect well.
E-line
1. MIRU EL and MU tractor.
2. Function test tractor and MU GR/CCL with 10’ perf gun and a CIBP below it.
3. RIH to deviation at ~11,800’ MD and begin tractoring to target depth.
Stage #Fluid Stage
Prop Con
(ppa)
Rate
(bpm)
Volume
(bbls)
CUM Volume
(bbls)Proppant Name Proppant
(#)
CUM Proppant
(#)
1 FW w/ adds Injection Test 0 25 200 200 0 0
2 Shutdown 200 0
3 28# X-Link Pad 0.5 25 150 350 0 0
4 28# X-Link Scour 0 25 100 450 100 Mesh 2055 2055
5 28# X-Link Pad 0 25 150 600 0 2055
6 28# X-Link Flat 1 25 100 700 16-20 CarboBOND 4022 6077
7 28# X-Link Flat 2 25 50 750 16-20 CarboBOND 3859 9936
8 28# X-Link Flat 3 25 50 800 16-20 CarboBOND 5562 15498
9 28# X-Link Flat 4 25 50 850 16-20 CarboBOND 7137 22635
10 28# X-Link Flat 5 25 50 900 16-20 CarboBOND 8598 31233
11 28# X-Link Flat 6 25 50 950 16-20 CarboBOND 9957 41190
12 28# X-Link Flat 7 25 50 1000 16-20 CarboBOND 11224 52414
13 28# X-Link Flat 8 25 100 1100 16-20 CarboBOND 24816 77230
14 28# X-Link Flat 9 25 100 1200 16-20 CarboBOND 27035 104265
15 28# X-Link Flat 10 25 100 1300 16-20 CarboBOND 29117 133382
16 28# X-Link Flat 11 25 100 1400 16-20 CarboBOND 31076 164458
17 28# X-Link Flat 12 25 100 1500 16-20 CarboBOND 32921 197379
18 FW w/ adds Flush 0 25 150 1650 197379
19 Diesel Freeze Protect 0 25 40 1690 197379
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
4. RIH to above current perforated interval at 14,665’-14,695’. Make correction and set CIBP at
14,630’ MD.
5. Prior to perforating the new interval, utilize a triplex to pump on the well and pressure up against
the plug with max applied pressure of 2,000 psi to ensure the plug is holding.
6. PUH and perforate 10’ from 14,290’-14,300’ MD.
7. POOH and RDMO EL.
8. Shut-in and secure well.
Frac
1. MIRU frac spread and associated equipment/tanks.
a. Heat water to 110 deg F, minimum pumping temp – 90 deg F
2. Install tree saver.
3. Perform pressure tests prior to performing hydraulic fracture stimulation.
a. Pressure test surface lines and tree saver to at least 7,125 psi.
b. Pressure test pump kick outs to 5,515 psi and global kick outs to 5,820 psi.
c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at
3,610 psi.
d. Bring IA pressure up and hold at 3,310 psi.
4. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum
allowable treating pressure is 6,125 psi.
Stage #Fluid Stage
Prop Con
(ppa)
Rate
(bpm)
Volume
(bbls)
CUM Volume
(bbls)Proppant Name Proppant
(#)
CUM Proppant
(#)
1 FW w/ adds Injection Test 0 25 200 200 0 0
2 Shutdown 200 0
3 28# X-Link Pad 0.5 25 150 350 0 0
4 28# X-Link Scour 0 25 100 450 100 Mesh 2055 2055
5 28# X-Link Pad 0 25 150 600 0 2055
6 28# X-Link Flat 1 25 100 700 16-20 CarboBOND 4022 6077
7 28# X-Link Flat 2 25 50 750 16-20 CarboBOND 3859 9936
8 28# X-Link Flat 3 25 50 800 16-20 CarboBOND 5562 15498
9 28# X-Link Flat 4 25 50 850 16-20 CarboBOND 7137 22635
10 28# X-Link Flat 5 25 50 900 16-20 CarboBOND 8598 31233
11 28# X-Link Flat 6 25 50 950 16-20 CarboBOND 9957 41190
12 28# X-Link Flat 7 25 50 1000 16-20 CarboBOND 11224 52414
13 28# X-Link Flat 8 25 100 1100 16-20 CarboBOND 24816 77230
14 28# X-Link Flat 9 25 100 1200 16-20 CarboBOND 27035 104265
15 28# X-Link Flat 10 25 100 1300 16-20 CarboBOND 29117 133382
16 28# X-Link Flat 11 25 100 1400 16-20 CarboBOND 31076 164458
17 28# X-Link Flat 12 25 100 1500 16-20 CarboBOND 32921 197379
18 FW w/ adds Flush 0 25 150 1650 197379
19 Diesel Freeze Protect 0 25 40 1690 197379
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
5. RDMO frac equipment and pull tree saver. Freeze protect well.
Coil Tubing (Pending) – FCO if early screenout occurs during frac or perfs are covered w/ proppant
1. MU BDJSN.
a. Recommended to run without checks so reverse circulating can be performed.
2. RIH dry and tag top of proppant.
3. PU and establish circulation.
a. Recommended to perform reverse FCO until returns are less than ~70%
4. FCO down to ~14,800’ MD.
a. Once returns fall below ~70% pickup and circulate coiled tubing clean. Swap circulation to
the long way and continue FCO with gel sweeps.
b. If losses become unmanageable while forward circulating and perfs are still covered can
attempt FCO with diesel. If losses are still unmanageable with diesel, coil will need to rig
down for SL to install gas lift valves.
Slickline
1. MIRU SL. Set LGLV design.
Portable Testers
1. MIRU, pressure test
2. POP the well to LRS with 1-1.5 MMSCFD Lift gas at minimum choke, adjust GL rate as necessary
to eliminate slugging. Flow the initial returns to the flowline as long as the shake-outs meet the
returned fluid/solids management guidelines.
a. If at any point, solids are >0.5%, divert returns to flowback tanks.
3. Limit flow to ~500 bpd
4. If solids are < 1%, after 1.5 wellbore volumes (291 bbls) increase the production rate to 750
BLPD.
5. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to
1000 BFPD.
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
6. Flow bottoms up (~194 bbls) and sample for solids production. If solids are still below 1%
continue to increase the flow rate in 250 BPD increments. The objective is to achieve maximum
drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well to clean
up before choke is opened further.
7. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr piggyback well test.
Attachments:
Old Wellbore Schematic
Proposed Wellbore Schematic (to be stimulated)
Sundry Revision Change Form
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Old Wellbore Schematic:
Kuparuk Frac
Well: S-126B
PTD: 224-084
API: 50-029-23363-02
Proposed Wellbore Schematic
New Perforation Summary
Interval: 14,290’-14,300’
Shot Density: 6 SPF
CIBP @ 14,630’
Kuparuk FracWell: S-126BPTD: 224-084API: 50-029-23363-02Sundry Revision Change Form:Changes to Approved Sundry ProcedureDate: June 4, 2025Subject: S-126B FracSundry #: 325-270Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDateProcedure ChangeHNSPreparedBy(Initials)HNSApprovedBy(Initials)AOGCC WrittenApprovalReceived (Personand Date)FracStep436/4/25Added Setting CIBP, shooting additionalperforationsand Frac HRG TRJack Lau, 6/4/25Approval:Operations Manager DatePrepared:Operations Engineer Date
From:Lau, Jack J (OGC)
To:Hunter Gates
Cc:Torin Roschinger; Abbie Barker; Tyson Shriver; Daniel Scarpella; Joseph Syzdek; Madan Manohar
Subject:RE: Notification Regarding Sundry 325-270 - S-126B (224-084) Hydraulic Fracturing
Date:Wednesday, June 4, 2025 10:27:50 AM
You are approved to move forward with the plug and perfs as described below.
Jack
From: Hunter Gates <Hunter.Gates@hilcorp.com>
Sent: Wednesday, June 4, 2025 10:19 AM
To: Lau, Jack J (OGC) <jack.lau@alaska.gov>
Cc: Torin Roschinger <Torin.Roschinger@hilcorp.com>; Abbie Barker <Abbie.Barker@hilcorp.com>;
Tyson Shriver <Tyson.Shriver@hilcorp.com>; Daniel Scarpella <Daniel.Scarpella@hilcorp.com>;
Joseph Syzdek <Joseph.Syzdek@hilcorp.com>; Madan Manohar <Mohan.Manohar@hilcorp.com>
Subject: RE: [EXTERNAL] RE: Notification Regarding Sundry 325-270 - S-126B Hydraulic Fracturing
Morning Jack,
Unfortunately, the acid did not improve our situation regarding injectivity. Our final
injectivity test show 0.7 BPM at 4,600 psi. We have made the decision to ask for approval
in attempting to perforate a few hundred feet higher while staying in pool and frac that
interval as we discussed on the phone yesterday.
Attached is my revised Frac Procedure to be included on the new sundry. The changes to
the previous procedure are in red. I have included a rough sketch of the proposed
wellbore schematic after the new perforations have been added as well. The old
perforations to be abandoned are from 14,695’-14,665’ MD. Our plan is to set the CIBP
at about 14,630’ MD, we’ll pressure up against it to ensure it is holding, and then we will
pull up hole to perforate 14,290’-14,300’ MD. This interval is confirmed to be in the same
pool and will not be adding any additional wells to the AOR.
Please let me know if there are any questions or concerns.
Hunter Gates
Operations Engineer I M & S Pads I Prudhoe Bay West
Hilcorp Alaska, LLC
Email: hunter.gates@hilcorp.com
Cell: (215) 498-7274
Office: (907) 777-8326
From: Lau, Jack J (OGC) <jack.lau@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.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Sent: Tuesday, June 3, 2025 7:59 AM
To: Hunter Gates <Hunter.Gates@hilcorp.com>
Cc: Torin Roschinger <Torin.Roschinger@hilcorp.com>; Abbie Barker <Abbie.Barker@hilcorp.com>;
Tyson Shriver <Tyson.Shriver@hilcorp.com>; Daniel Scarpella <Daniel.Scarpella@hilcorp.com>
Subject: [EXTERNAL] RE: Notification Regarding Sundry 325-270 - S-126B Hydraulic Fracturing
Thanks for the update Hunter. Good luck.
Jack
From: Hunter Gates <Hunter.Gates@hilcorp.com>
Sent: Monday, June 2, 2025 6:26 PM
To: Lau, Jack J (OGC) <jack.lau@alaska.gov>
Cc: Torin Roschinger <Torin.Roschinger@hilcorp.com>; Abbie Barker <Abbie.Barker@hilcorp.com>;
Tyson Shriver <Tyson.Shriver@hilcorp.com>; Daniel Scarpella <Daniel.Scarpella@hilcorp.com>
Subject: Notification Regarding Sundry 325-270 - S-126B Hydraulic Fracturing
Evening Jack,
I was just wanted to let you know about some recent developments and our plan forward
regarding S-126B’s frac.
After obtaining our initial injectivity test, we went to pump our 100 mesh scour. We
began to see pressure climbing prematurely and began losing the ability to inject into our
perforated interval.
Moving forward, our plan for tomorrow is to pump acid in order to re-establish injection
and clean up our perforations near wellbore so that we can begin our normal pump
schedule again and give this another shot before rigging down.
Please let me know if you have any questions or concerns.
Hunter Gates
Operations Engineer I M & S Pads I Prudhoe Bay West
Hilcorp Alaska, LLC
Email: hunter.gates@hilcorp.com
Cell: (215) 498-7274
Office: (907) 777-8326
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in this pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd?Yes No
Subsequent Form Required:
Approved By:Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU S-126B
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK
99503
224-084
50-029-23363-02-00
ADL 0028257, 0028258
14826
Conductor
Surface
Intermediate
Production
Liner
6805
80
4780
11482
3532
14809
20"
10-3/4"
7"
3-1/2" x 3-1/4" x 2-7/8"
6806
29 - 109
28 - 4808
25 - 11507
11294 - 14826
5400
29 - 109
28 - 3193
25 - 6727
6545 - 6805
None
470
4020
5410
10530
None
1490
6450
7240
10160
14665 - 14695 4-1/2" 12.6# L-80 23 - 113606815 - 6812
Structural
4-1/2" Baker S-3 Perm Packer
No SSSV Installed
11294, 6545
Date:
Torin Roschinger
Operations Manager
Hunter Gates
hunter.gates@hilcorp.com
(907) 777-8326
PRUDHOE BAY
5/26/2025
Current Pools:
AURORA OIL
Proposed Pools:
AURORA OIL
Suspension Expiration Date:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 10:55 am, Apr 30, 2025
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662)
Date: 2025.04.30 10:47:28 -
08'00'
Torin Roschinger
(4662)
325-270
5/26/2025
JJL 5/14/25
10-404
DSR-5/1/25
CDW 05/13/2025
A.Dewhurst 15MAY25
Include a PRV on OA or hold an open bleed on OA during fracture treatment.
*&:
5/28/2025
Jessie L.
Chmielowski
Digitally signed by Jessie L. Chmielowski
Date: 2025.05.28 14:38:41 -08'00'
RBDMS JSB 052925
Kuparuk Frac
Well: S-126B
PTD: 224-084
Well Name:S-126B Permit to Drill:224-084
Current Status:Operable, Producer API Number:50-029-23363-02
Estimated Start Date:May 26, 2025 Estimated Duration:5days
Regulatory Contact:Abbie Barker Sundry Number:
First Call Engineer:Hunter Gates (907) 777-8326 (O)(215) 498-7274 (M)
Second Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M)
Current Bottom Hole Pressure:3,374 psi @ 6,600’ TVDss
Max Anticipated Treating Pressure:5,400 psi
Last SI WHP: Tbg dead, came on w/ ~1700 psi w/ GL but died off
Min ID:2.313” @ 11,283’ MD X-Nipple
Max Angle:100 deg @ 12,434’ MD
Brief Well Summary:
S-126B is a Kuparuk producer that is Operable but currently shut-in due to its inability to flow. This was a
CTD sidetrack completed in early February 2025. We shot 30’ of perforations with service coil and
attempted to flow the well back with gas lift. We were able to unload a few wellbore volumes and then
we started seeing some oil from the formation until the well starting gassing around on us. We saw 18%
oil cut of 28.8 API oil. After several hours of non-sustained flow, the well was freeze protected and left
shut-in.
Objective:
Set dummy GLV’s. Pressure Test. Install tree-saver. Perform hydraulic fracture stimulation to stimulate
the Kuparuk C formation. Flow well back through portable test separator.
Current Status:
Operable Producer, Shut-In
Recent Integrity:
x 09/23/2024 – MIT-T passed to 3,239 psi and CMIT-TxIA passed to 4,020 psi
x 2/11/2025 – PT LTP to 1500 psi
Procedure:
Slickline/Fullbore
1. MIRU SL.
2. Make a drift run to deviation (~11,678’ MD).
3. Set plug in X-nipple at 11,283’.
4. Set catcher on top of plug.
5. Pull LGLVs. Install DGLV in St #2 and flowsleeve in St #1
6. Circulate wellbore to 1% KCl or Seawater and crude freeze protect. U-tube crude freeze protect.
a. Total TBG and IA Volume down to St #1: 342 bbls
b. Freeze protect volume to 2500’ in TBG and IA: 38 bbls + 47 bbls = 85 bbls
7. Pull flowsleeve from St #1 and install DGLV.
8. Perform MIT-T to target 3100 psi (max applied 3300 psi).
Kuparuk Frac
Well: S-126B
PTD: 224-084
9. Perform MIT-IA to target 3800 psi (max applied 4100 psi). Hold 2000 psi on tubing during MIT-IA.
10. Pull catcher and plug.
11. Fullbore to perform an injectivity test on formation once MIT’s are completed to max target
pressure of 3000 psi.
Frac
1. MIRU frac spread and associated equipment/tanks.
a. Heat water to 110 deg F, minimum pumping temp – 90 deg F
2. Pull water from each tank and have SLB lab test our water quality:
a. pH - ~7
i. Higher pH delays the hydration of the gel and delays break
b. Calcium/magnesium <500 mg/l
i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which
tend to be insoluble
c. Bicarbonate - <400 mg/l
i. High bicarbonate levels will cause slow hydration times and elevated delay times
with X-linking fluids. If we have elevated bicarbonate levels and have introduced
delay agents, it could have an exponential effect in delay times.
d. Chlorides-<10,000 mg/l
i. This fluid system should be able to cope with elevated Chloride levels
e. Iron (Fe+3) - <5 mg/l
i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have
an accelerated effect. Can cause viscosity degradation in linear gels (especially if
batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking
sites.
f. TDS – minimal/<5000
i. Effects depend on the solids that are dissolved in the fluid.
3. Install tree saver.
4. Perform pressure tests prior to performing hydraulic fracture stimulation.
a. Pressure test surface lines and tree saver to at least 7,125 psi.
b. Pressure test pump kick outs to 5,515 psi and global kick outs to 5,820 psi.
c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at
3,610 psi.
d. Bring IA pressure up and hold at 3,310 psi.
5. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum
allowable treating pressure is 6,125 psi.
Kuparuk Frac
Well: S-126B
PTD: 224-084
6. RDMO frac equipment and pull tree saver. Freeze protect well.
Coil Tubing (Pending) – FCO if early screenout occurs during frac or perfs are covered w/ proppant
1. MU BDJSN.
a. Recommended to run without checks so reverse circulating can be performed.
2. RIH dry and tag top of proppant.
3. PU and establish circulation.
a. Recommended to perform reverse FCO until returns are less than ~70%
4. FCO down to ~14,800’ MD.
a. Once returns fall below ~70% pickup and circulate coiled tubing clean. Swap circulation to
the long way and continue FCO with gel sweeps.
Stage #Fluid Stage
Prop Con
(ppa)
Rate
(bpm)
Volume
(bbls)
CUM Volume
(bbls)Proppant Name Proppant
(#)
CUM Proppant
(#)
1 FW w/ adds Injection Test 0 25 200 200 0 0
2 Shutdown 200 0
3 28# X-Link Pad 0.5 25 150 350 0 0
4 28# X-Link Scour 0 25 100 450 100 Mesh 2055 2055
5 28# X-Link Pad 0 25 150 600 0 2055
6 28# X-Link Flat 1 25 100 700 16-20 CarboBOND 4022 6077
7 28# X-Link Flat 2 25 50 750 16-20 CarboBOND 3859 9936
8 28# X-Link Flat 3 25 50 800 16-20 CarboBOND 5562 15498
9 28# X-Link Flat 4 25 50 850 16-20 CarboBOND 7137 22635
10 28# X-Link Flat 5 25 50 900 16-20 CarboBOND 8598 31233
11 28# X-Link Flat 6 25 50 950 16-20 CarboBOND 9957 41190
12 28# X-Link Flat 7 25 50 1000 16-20 CarboBOND 11224 52414
13 28# X-Link Flat 8 25 100 1100 16-20 CarboBOND 24816 77230
14 28# X-Link Flat 9 25 100 1200 16-20 CarboBOND 27035 104265
15 28# X-Link Flat 10 25 100 1300 16-20 CarboBOND 29117 133382
16 28# X-Link Flat 11 25 100 1400 16-20 CarboBOND 31076 164458
17 28# X-Link Flat 12 25 100 1500 16-20 CarboBOND 32921 197379
18 FW w/ adds Flush 0 25 150 1650 197379
19 Diesel Freeze Protect 0 25 40 1690 197379
Kuparuk Frac
Well: S-126B
PTD: 224-084
b. If losses become unmanageable while forward circulating and perfs are still covered can
attempt FCO with diesel. If losses are still unmanageable with diesel, coil will need to rig
down for SL to install gas lift valves.
Slickline
1. MIRU SL. Set LGLV design.
Portable Testers
1. MIRU, pressure test
2. POP the well to LRS with 1-1.5 MMSCFD Lift gas at minimum choke, adjust GL rate as necessary
to eliminate slugging. Flow the initial returns to the flowline as long as the shake-outs meet the
returned fluid/solids management guidelines.
a. If at any point, solids are >0.5%, divert returns to flowback tanks.
3. Limit flow to ~500 bpd
4. If solids are < 1%, after 1.5 wellbore volumes (291 bbls) increase the production rate to 750
BLPD.
5. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to
1000 BFPD.
6. Flow bottoms up (~194 bbls) and sample for solids production. If solids are still below 1%
continue to increase the flow rate in 250 BPD increments. The objective is to achieve maximum
drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well to clean
up before choke is opened further.
7. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr piggyback well test.
Attachments:
x Current Wellbore Schematic
x Sundry Revision Change Form
Kuparuk Frac
Well: S-126B
PTD: 224-084
Current Wellbore Schematic:
Kuparuk FracWell: S-126BPTD: 224-084Sundry Revision Change Form:Changes to Approved Sundry ProcedureDate:Subject:Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDateProcedure ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC Written ApprovalReceived (Person and Date)Approval:Operations Manager DatePrepared:Operations Engineer Date
S-126B Fracture Stimulation
PTD: 224-084
Page 1
Date: April 24, 2025
Subject: S-126B Fracture Stimulation
From: Hunter Gates
O: (907) 777-8326
C: (215) 498-7274
To: AOGCC
Estimated Start Date: 5/26/2025
Attached is Hilcorp’s proposal and supporting documents to perform a fracture stimulation on well S-
126B (PTD #224-084) in the Kuparuk reservoir of the Prudhoe Bay Unit.
The objective of this program is to perform a single stage fracture stimulation of the newly drilled coiled
tubing sidetrack Kuparuk well to improve overall performance.
Well S-126B is a coiled tubing drilling sidetrack that was completed in February 2025. The well is an
undulating lateral through the Kuparuk C sands that is expected to be fracture stimulated at the toe. The
well was POP’d post sidetrack to confirm water cut and productivity. S-126B produced a few wellbore
volumes but was unable to sustain flow. During the short flow period, water cut was confirmed at 18%
and an API gravity of 28.8 degrees was captured. Well in line with expectations.
Hilcorp requests a variance to sections 20 AAC 25.283, a, 3- 4 which require identification of freshwater
aquifers and a plan for base-water sampling.
Please direct questions or comments to Hunter Gates.
Hilcorp requests a variance to sections 20 AAC 25.283, a, 3- 4 which require identification of freshwater
aquifers and a plan for base-water sampling.
S-126B Fracture Stimulation
PTD: 224-084
Page 2
SECTION 1 - AFFIDAVIT (20 AAC 25.283, a, 1):
Below is an affidavit stating that the owners, landowners, surface owners and operators identified on a
plat 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.
S-126B Fracture Stimulation
PTD: 224-084
Page 3
SIGNED AFFIDAVIT:
S-126B Fracture Stimulation
PTD: 224-084
Page 4
COPY OF NOTIFICATION SENT VIA EMAIL:
S-126B Fracture Stimulation
PTD: 224-084
Page 5
SECTION 2 - PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25.283, a, 2):
Plat of wells within one-half mile of S-126B trajectory.
S-126B Fracture Stimulation
PTD: 224-084
Page 6
LIST OF WELLS IN PLAT WITHIN ½ MILES ON SURFACE (20 AAC 25.283, a, 2, C):
Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc
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ϱ͏͗ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͕͐͑ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώēŪťώIIJ ϱ͓͑͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī
ϱ͏͘ ôŘŽĖèô æÍIJîĺIJôî ϱ͕͐͑ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ͓͑ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώēŪťώĖIJ
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ϱ͏͑͘ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑͗ ôŘŽĖèô aĖŜèĖæīôώIIJĤ ôèťĺŘώiŕôŘÍťĖIJČ ϱ͔͑͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī
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ϱ͐͏ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ͐͑͗͑ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͖͑ "ôŽôīĺŕıôIJť æÍIJîĺIJôî
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ϱ͐͏͏ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͑͘ "ôŽôīĺŕıôIJť iĖīώŘĺî ŪèôŘώ@ÍŜώ[Ėċť ϱ͖͑͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī
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ϱ͐͏͑[͐ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ͐͒ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ͑͗͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī
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ϱ͐͏͑ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͔͐͒͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͑͘[͐ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώēŪťϱIIJ
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S-106A "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͔͐ ôŘŽĖèô aĖŜèĖæīôώIIJĤôèťĺŘώēŪťϱIIJ ϱ͒͒ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώēŪťώĖIJ
S-106L1PB1 "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͔͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͒ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώIIJĤôèťĖIJČ
ϱ͐͏͕[͐ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ͕͐ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώēŪťϱIIJ ϱ͔͒ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť
ϱ͐͏͕͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͐͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͒ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώēŪťϱIIJ
ϱ͐͏͖ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώĖIJĤôèťĖIJČ ϱ͖͐ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ͖͒ "ôŽôīĺŕıôIJť æÍIJîĺIJôî
ϱ͐͏͗ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώēŪťϱIIJ ϱ͖͐ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ ͖͒ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώēŪťϱIIJ
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ϱ͐͏͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͖͐͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͏ "ôŽôīĺŕıôIJť æÍIJîĺIJôî
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ϱ͐͐ ôŘŽĖèô æÍIJîĺIJôî ϱ͖͐ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώēŪťϱIIJ ϱ͓͏͏ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώēŪťϱIIJ
ϱ͐͐͏ ôŘŽĖèô æÍIJîĺIJôî ϱ͖͐ ͐ "ôŽôīĺŕıôIJť īŪČČôîώÍèħώ>ĺŘώôîŘĖī ī ϱ͓͏͐ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώēŪťϱIIJ
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ϱ͐͐͐ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώIIJĤôèťĖIJČ ϱ͐͗ "ôŽôīĺŕıôIJť æÍIJîĺIJôî ϱ ͓͐ "ôŽôīĺŕıôIJť æÍIJîĺIJôî
ϱ͐͐͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͗ "ôŽôīĺŕıôIJť iĖīώŘĺîŪèôŘώēŪťϱIIJ ϱ͓͐ ôŘŽĖèô ®ÍťôŘώIIJĤôèťĺŘώIIJĤôèťĖIJČ
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S-126B Fracture Stimulation
PTD: 224-084
Page 7
SECTION 3 - EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25.283, a, 3):
Well S-126B is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated
July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas
Conservation Commission to issue an order exempting those portions of all aquifers lying directly below
the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities.
Findings 1- 4 state:
1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas
of the Prudhoe Bay Unit do not currently serve as a source of drinking water.
2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas
of the Prudhoe Bay Unit are situated at a depth and location that makes recovery of water for
drinking water purposes economically impracticable.
3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas
of the Prudhoe Bay Unit are reported to have total dissolved solids content of 7000 mg/ I or
more.
4. By letter of July 1, 1986, EPA- Region 10 advises that the aquifers occurring beneath the
Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is
considered to be a minor exemption and a non-substantial program revision not requiring notice
in the Federal Registrar.
Per the above findings, " Those portions of freshwater aquifers lying directly below the Western
Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC
25. 440" thus allowing Hilcorp exemption from 20 AAC 25. 283, a, 3- 4 which require identification of
freshwater aquifers and establishing a plan for base-water sampling.
S-126B Fracture Stimulation
PTD: 224-084
Page 8
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.
S-126B Fracture Stimulation
PTD: 224-084
Page 9
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, g when completed.
See wellbore schematic for casing details:
S-126B Fracture Stimulation
PTD: 224-084
Page 10
SECTION 6 - ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE
PERFORMED TO CONSTRUCT OR REPAIR THE WELL (20 AAC 25.283, a, 6):
Summary:
S-126 was spudded 10/20/2007 with a 13-1/2” hole to 4,815’ where 10-3/4” surface casing was set and
cemented at 4,808’ with 1,101 sx (755 bbls) of 10.7 ppg DeepCrete lead cement followed by 434 sx (88
bbls) of 15.8 ppg Class ‘G’ cement, last 24 bbls was 16.3 ppg Class ‘G’. Returned 423 bbls of cement to
surface. The 10-3/4” surface casing was pressure test to 3,500 psi before drilling out the shoe track and
20’ of new formation to 4,835’. A leak off test to 13.28 ppge was performed.
The 9-7/8” production hole was directionally drilled to 11,910’. 7” production casing was then run to
11,898’ and cemented in place with 720 cuft (318 bbls) of 12.0 ppg LiteCrete followed by a tail of 298
cuft (62 bbls) 15.8 ppg Class ‘G’ cement. The casing was reciprocated throughout the cement job and no
losses were reported. A subsequent 4,000 psi pressure test against the 7” casing passed. A USIT log
pulled prior to running upper completion showed TOC at 4,900’ MD. 4-1/2” production tubing was then
run and tested to 4,000 psi.
S-126APB1 was sidetracked out of the 7” production casing at ~11,510’ MD which does not affect
cement isolation above the Kuparuk of the original S-126 production casing.
S-126A lateral was sidetracked off of an open hole billet that was set at 12,510’ MD inside of the 4-1/4”
hole of PB1. The “A” lateral was drilled to a TD of 14,820’ MD but left unlined or cemented.
S-126B was sidetracked off another open hole billet set in the S-126A lateral at ~13,000’ MD. The “B”
lateral was drilled to a TD of 14,826’ MD. 3-1/2” x 3-1/4” x 2-7/8” liner was run to 14,826’ and cemented
in place with 50 bbls 14.8 ppg cement.
All casing is cemented in accordance with 210 AAC 25.030 and each hydrocarbon zone penetrated by
the well is isolated.
Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that
this well can be successfully fractured within well design limits.
TOC at 4,900’ MD
S-126B Fracture Stimulation
PTD: 224-084
Page 11
SECTION 7 - PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND
TUBING INSTALLED IN THE WELL (20 AAC 25.283, a, 7):
On 9/23/2024, the tubing was pressure tested to 3,239 psi for a passing MIT-T
On 9/23/2024, the casing was pressure tested to 4,020 psi for a passing CMIT-TxIA
Live gas lift valves were installed post CTD to flow test the well. Ahead of fracturing operations, live gas
lift valves will be pulled and replaced with dummy valves. The tubing and casing will be pressure tested
to the following:
- MIT-T = 3,100 psi
- MIT-IA = 3,800 psi
The production casing annulus pressure will be monitored during the frac, if any change of pressure is
seen outside of thermal expansion, the job will be flushed, and the pressure source diagnosed before
frac operations continue.
Anticipated Pressures:
MIT-T 3,100 psi
MIT-IA 3,800 psi
Maximum Anticipated Treating Pressure:5,310 psi @ 25 BPM
IA Pop-off Set Pressure (95% of MIT-IA):3,610 psi
IA Minimum Hold Pressure (POP-off – ~300 psi):3,310 psi
Maximum Allowable Treating Pressure (MATP =
Ann hold + MIT-T/1.1):
6,125 psi w/ 3,310 psi on IA
Stagger Pump Kickouts Between 90 – 95% of MATP:5,515 – 5,820 psi
Global Kickout (95% of MATP):5,820 psi
N2 POP-off set pressure (MATP):6,125 psi
Treating Line Test Pressure (MATP + 1000 psi):7,125 psi
OA Pressure:Monitor
Max Anticipated Proppant Loading:12 PPA
S-126B Fracture Stimulation
PTD: 224-084
Page 12
SECTION 8 - PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE
AND TREATING HEAD (20 AAC 25.283, a, 8):
Wellbore Tubular Ratings:
Size/Name Weight Grade Burst, psi Collapse, psi
10-3/4” Surface Casing 45.5#L80 5,210 2,470
7” Production Casing 26#L80 7,240 5,410
4-1/2” Production Tubing 12.6#L80 8,430 7,500
3-1/2” Production Liner 9.2#L80 10,160 10,540
2-7/8” Production Liner 6.5#L80 10,570 11,170
Wellhead:
FMC manufactured wellhead, rated to 5,000 psi
Tubing head adaptor: 11", 5,000 psi x 4-1/16", 5,000 psi
Tubing Spool: 11" 5, 000 psi w/ 2-1/16" side outlets
Casing Spool: 11" 5, 000 psi w/ 2-1/16" side outlets
Tree: CIW 4-1/16" 5,000 psi.
- A 10,000-psi rated TreeSaver will be used during the fracturing operations.
S-126B Fracture Stimulation
PTD: 224-084
Page 13
SECTION 9 - DATA FOR FRACTURING ZONE AND CONFINING ZONES (20 AAC 25.283, a, 9):
Formation*MD
Top
MD
Bottom
TVDss
Top
TVDss
Bottom
TVD
Thickness
Frac Grad
psi/ft Lith. Desc.
THRZ 11,254 11,454 -6,443 -6,614 171 0.72 Shale
TKLB 11,454 11,473 -6,614 -6,631 17 0.7 Shale
Top Kuparuk / C 11,473 11,599 -6,631 -6,739 108 0.62 SS
LCU / Kuparuk B 11,599 11,756 -6,739 -6,875 136 0.64 Silts/SS
Kuparuk A 11,756 11,828 -6,875 -6,938 63 0.66 Silts/SS
Miluveach**11,828 -6,938 -7,507 569 0.72 Shale
*Depths are taken from the S-126 parent bore
**Did not penetrate Base Miluveach. Base depth taken from S-01.
S-126B Fracture Stimulation
PTD: 224-084
Page 14
SECTION 10 – LOCATION, ORIENTATION, AND A REPORT ON MECHANICAL CONDITION OF
EACH WELL THAT MAY TRANSECT CONFINING ZONE (20 AAC 25.283, a, 10):
Plat of wells within one-half mile of S-126B wellbore reservoir trajectory and location of faults. The red line indicates the
approximate fracture length and orientation of the frac.
The plat shows the location and orientation of each well that transects the confining zone within a ½
mile radius. Hilcorp has formed the opinion, based on the 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.
S-126B Fracture StimulationPTD: 224-084Page 15Casing and Cement assessments for all wells that transect the confining zone:
S-126B Fracture Stimulation
PTD: 224-084
Page 16
SECTION 11 - LOCATION OF, ORIENTATION OF, AND GEOLOGICAL DATA FOR FAULTS AND
FRACTURES THAT MAY TRANSECT THE CONFING ZONES (20 AAC 25.283, a, 11):
Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates
that there are 5 mapped faults that transect the Kuparuk interval and enter the confining zone within
the ½ radius of the production and confining zone trajectory for the S-126B. Fracture gradients within
the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation and would
therefore confine injected fluids to the pool. The HRZ and Kalubik in this area are predominately shale
with some silts with an estimated fracture pressure of ~13.5ppg.
Faults 1-5 intersect the production interval and confining zone within the ½ mile radius of the planned
fracs. Their displacements, sense of throw, and zone in which they terminate upwards are given below.
The wellbore trajectory is a horizontal well with the planned frac at the toe of the well. Maximum stress
direction is estimated to be ~30 deg W of N. The frac stage should have sufficient offset to and should
not intersect the faults.
The frac is 1,200’ from fault #1, 550’ from fault #2, 1960’ from fault #3, 1925’ from fault #4 and 2,250’
from Fault #5. The maximum anticipated fracture half-length of 200’ is well short of these faults. Half-
length is modeled using hydraulic fracture modelling software and is corroborated by what we have
seen in other frac treatments.
If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot
be explained by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan
forward and explanation can be put forth.
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S-126B Fracture Stimulation
PTD: 224-084
Page 17
SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM (20 AAC 25.283, a, 12):
Proposed Procedure:
1. Conduct safety meeting, inspect location, and review 10-403.
2. Ensure all pre-frac well work has been completed, and the tubing & IA are freeze protected.
3. Install Tree Saver.
4. MIRU frac equipment and associated frac tanks.
5. Pressure test surface lines and Tree Saver to at least 7,125 psi.
6. Test IA Pop-off system to ensure functioning properly. IA Pop-off to be set at 3,610 psi.
7. Bring IA pressure up to a hold pressure of 3,310 psi.
8. Pump the fracture stimulation per the proposed pump schedule below. Maximum allowable
treating pressure is 6,125 psi.
9. RDMO frac equipment. Ensure tubing is freeze protected.
10. Return the well to production / flowback post slickline gas lift and contingent coiled tubing
cleanout.
Fracture Stimulation Schedule:
Note:
There are three overpressure devices that protect the surface equipment and wellbore from
overpressure. 1) Each individual frac pump has an electronic kickout that will shift the pumps into
neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are
staggered between 90% and 95% of the maximum allowable treating pressure. 2) A primary pressure
transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3)
There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. All
three of these shutdown systems will be individually tested prior to high pressure pumping operations.
Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van.
Stage #Fluid Stage
Prop Con
(ppa)
Rate
(bpm)
Volume
(bbls)
CUM Volume
(bbls)Proppant Name Proppant
(#)
CUM Proppant
(#)
1 FW w/ adds Injection Test 0 25 200 200 0 0
2 Shutdown 200 0
3 28# X-Link Pad 0.5 25 150 350 0 0
4 28# X-Link Scour 0 25 100 450 100 Mesh 2055 2055
5 28# X-Link Pad 0 25 150 600 0 2055
6 28# X-Link Flat 1 25 100 700 16-20 CarboBOND 4022 6077
7 28# X-Link Flat 2 25 50 750 16-20 CarboBOND 3859 9936
8 28# X-Link Flat 3 25 50 800 16-20 CarboBOND 5562 15498
9 28# X-Link Flat 4 25 50 850 16-20 CarboBOND 7137 22635
10 28# X-Link Flat 5 25 50 900 16-20 CarboBOND 8598 31233
11 28# X-Link Flat 6 25 50 950 16-20 CarboBOND 9957 41190
12 28# X-Link Flat 7 25 50 1000 16-20 CarboBOND 11224 52414
13 28# X-Link Flat 8 25 100 1100 16-20 CarboBOND 24816 77230
14 28# X-Link Flat 9 25 100 1200 16-20 CarboBOND 27035 104265
15 28# X-Link Flat 10 25 100 1300 16-20 CarboBOND 29117 133382
16 28# X-Link Flat 11 25 100 1400 16-20 CarboBOND 31076 164458
17 28# X-Link Flat 12 25 100 1500 16-20 CarboBOND 32921 197379
18 FW w/ adds Flush 0 25 150 1650 197379
19 Diesel Freeze Protect 0 25 40 1690 197379
S-126B Fracture Stimulation
PTD: 224-084
Page 18
Frac Dimensions:
Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft
1 14,665 -6,725 -6,835 ~200’
Frac Modelling:
Maximum Anticipated Treating Pressure: ~5,310 psi
Surface pressure is calculated based on a closure pressure of ~0.62 psi/ ft or ~4,110 psi. Closure pressure
plus anticipated net pressure to be built (500 psi) and friction pressure minus hydrostatic results in a
surface pressure of 5,310 psi at the time of flush.
4,110 psi (closure) + 500 psi (net) + 5,300 psi (friction) – 4,600 psi (hydrostatic) = 5,310 psi (max surface
press)
The difference in closure pressures of the confining shale layers determines height of the fracture.
Average confining layer stress is anticipated to be ~0.72 psi/ft. Fracture half-length is determined from
confining layer stress as well as leak-off and formation modulus. The modeled frac is anticipated to
reach a half-length of ~200 ft with a height of ~110 ft TVD.
Disclaimer Notice:
This model was generated using commercially available modelling software and is based on engineering
estimates of reservoir properties. Hilcorp is providing these model results as an informed prediction of
actual results. Because of the inherent limitations in assumptions required to generate this model, and
for other reasons, actual results may differ from the model results.
S-126B Fracture Stimulation
PTD: 224-084
Page 19
Pre-Job Anticipated Chemicals to be pumped:
S-126B Fracture Stimulation
PTD: 224-084
Page 20
SECTION 13 - POST FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN (20 AAC
25.283, a, 13):
After the fracture stimulation and potentially during the post frac coil fill cleanout, the well will be put
on production through a portable well test separator. All liquids will be captured and either sent to
production facilities or diverted to flowback tanks if solids percentage becomes too high for the
production facility to manage.
The initial flowback period is intended to produce back the fracture fluids to tanks as quickly as possible,
until the well is producing less than 0.5% solids, at which time the produced fluids meet the GC2
acceptance criteria for start-up. There will be a tank farm on pad to store the produced fluids from
flowback operations.
The flowback fluids not suitable for GC2 processing will be hauled to another facility’s slop tanks for
additional settling time and/or disposal. Hilcorp will work to separate and recover fluid that meets the
facility specification for the flowback fluids. A fluid manifest form will be completed for each load
trucked offsite.
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 May 27, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 15MAY25 (a)(2) Plat Provided with application. A.Dewhurst 14MAY25 (a)(2)(A) Well location Provided with application. Well lies in Section 35 of T12N, R12E, UM. A.Dewhurst 15MAY25 (a)(2)(B) Each water well within ½ mile None: There are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of PBU S-126B. There are no subsurface water rights or temporary subsurface water rights within 5 miles of the surface location of PBU S-126B. A.Dewhurst 15MAY25 (a)(2)(C) Identify all well types within ½ mile Provided with application. Hilcorp has identified 212 wells within ½ mile. A.Dewhurst 15MAY25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. This well lies within the Western Operating Area the of Prudhoe Bay Unit which is exempted under AEO 1. A.Dewhurst 15MAY25 (a)(4) Baseline water sampling plan None required. A.Dewhurst 15MAY25 (a)(5) Casing and cementing information Provided with application. Schematic attached. Multiple sidetracks and plug backs. CDW 05/13/2025 (a)(6) Casing and cementing operation assessment 10-3/4” surface casing cemented to surface. TOC in 7” casing at 4900 ft (CBL). CBL on file at AOGCC. Several sidetracks and plug backs. S-126B liner cemented from 13000 ft to TD of 14826 ft. 4.5” tubing 3.5x3.25x2.675” liner will be anchored with a packer set at approx. 11294 ft with Kuparuk C top of 11473 ft. CBL conservatively shows good cement at area of interest so no cement concerns. No issues with cement for the upcoming stimulation. CDW 05/13/2025
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 May 27, 2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 Only exempt freshwater aquifers present. (See Section (a)(3), above.) A.Dewhurst 15MAY25 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates the Kuparuk hydrocarbon zone. For the parent wellbore S-126, the Kuparuk is isolated by the 7” production liner with TOC at 4,900’ MD (measured by CBL). For the S-126B well, the Kuparuk is isolated by the 3-1/2” x 3-1/4” x 2-7/8” liner cement. There is no CBL, but Hilcorp estimates 36 bbls of cement behind the liner and reported zero losses. A.Dewhurst 15MAY25/ CDW 05/13/2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3800 psi MITIA planned, 3100 psi MITT plan. CDW 05/13/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. max. frac. Pressure 6125 psi. Pump knock out 5515 and GORV 5820 psi., 10K tree saver, lines test 7125 psi. CDW 05/13/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: 188’ of shales of the HRZ and Kalubik with fracture gradient of 0.7 psi/ft to 0.72 psi/ft. Fracturing Zone: 307’ of Kuparuk sandstones and siltstones with a fracture gradient of 0.62 psi/ft to 0.66 psi/ft. Lower confining zone: 569’ of Miluveach shales with a fracture gradient of 0.72 psi/ft. MD and TVD depths provided in application. A.Dewhurst 15MAY25 (a)(10) Location, orientation, report on mechanical condition of each well that Provided with application. AOGCC evaluated all wells that may transect the confining zones within the PBU S-126B Area A.Dewhurst 15MAY25/
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 May 27, 2025 may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory of Review and found it highly unlikely that any of these wells will interfere with fracturing fluids due to cement-isolation and/or separation distance or direction. CDW 05/13/2025 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Hilcorp has identified 5 faults within the ½ mile of the proposed frac. Detailed descriptions for each are provided in the application. The closest fault is 550’ away. The anticipated fracture half-length is 200’. So, it is unlikely that any faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. A.Dewhurst 15MAY25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/13/2025 (a)(12)(A) Estimated volume Provided with application. 1690 bbl total dirty vol. 197K lb total proppant CDW 05/13/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/13/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided. CDW 05/13/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 05/13/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 5310 psi. Max. 6125 psi allowable treating pressure. Max pressure is 5515 psi to 5820 psi to Pump shutdown. Global ePRV 6125 psi. With 3310 psi back pressure IA (IA popoff set 3610 psi), max tubing differential should be 2815 psi. CDW 05/13/2025
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 May 27, 2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-length of the induced fractures is 200’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 110’ (top of about -6,725’ TVDSS and base of about -6,835’ TVDSS). A.Dewhurst 15MAY25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified but Hilcorp has options. CDW 05/13/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3310 psi back pressure, plan to test to 3800 psi, popoff set as 3610 psi CDW 05/13/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing 3.5x3.25x2.675” liner will be anchored with a packer set at approx. 11294 ft with Kuparuk C top of 11473 ft. 10-3/4” surface casing cemented to surface. TOC in 7” casing at 4900 ft (USIT). Several sidetracks and plug backs. S-126B liner cemented from 13000 ft to TD of 14826 ft. USIT/CBL conservatively shows good cement at area of interest so no cement concerns. CDW 05/13/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3100 psi. Max pressure differential is estimated as 2815 psi (6125 psi with 3310 psi backpressure) so test of 3100 psi satisfies 110% CDW 05/13/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 7125 psi line pressure test, pump knock out 5515-5820 psi with max. global kickout 5820 and 6125 psi. IA PRV set as 3610 psi. CDW 05/13/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/13/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3610 psi. Surface annulus open. Frac pressures continuously monitored. CDW 05/13/2025 (g) Annulus pressure 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time CDW 05/13/2025
20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-126B (PTD No. 224-084; Sundry No. 325-270) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 May 27, 2025 monitoring & notification during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). A.Dewhurst 15MAY25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 15MAY25 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 3/2/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250302
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP
CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP
END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG
END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF
MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24
MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey
MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24
MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D
NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf
ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint
PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM
PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT
PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM
PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM
PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT
PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF
PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL
PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT
PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP
Please include current contact information if different from above.
T40161
T40161
T40162
T40163
T40164
T40165
T40166
T40167
T40168
T40169
T40170
T40171
T40172
T40173
T40174
T40175
T40176
T40177
T40178
T40179
PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.03.03 10:15:14 -09'00'
3-1/2"x3-1/4"
2079' FSL, 26' FWL, Sec. 33, T12N, R12E, UM, AK
Complete
2/7/2025
JSB
RBDMS JSB 022825
G
Received 2/25/2025
6/3/25 DSR-4/7/25JJL
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.02.25 15:09:50 -
09'00'
Sean
McLaughlin
(4311)
ACTIVITYDATE SUMMARY
2/4/2025
*** Job Continued from 2-3-25 ( CTD ) Assist CDR-2, Rig Down Secure RU End
Ticket.
2/6/2025
LRS CTU #1, 1.5" CT, 0.134" WT. Job Scope: Post Rig Drift, CBL, Add Perf
Travel from L2-10. MIRU. Spot non-mobile equipment, build scaffolding. ***Function
Test BOP***. RIH w/ 2.25" drift w/ choke closed, whp increased to 1110psi and
begins injecting at 0.2bpm, open choke take returns. Lockup at 14,595', circulate the
well to1% slick w/ safelube, complete drift to PBTD 14812' CTM. PU 20' from weight
back, paint white safety flag at 14783'. POOH continue circulating well to safelube.
***Continued on 2-7-25 WSR***
2/7/2025
LRS CTU #1, 1.5" CT, 0.134" WT. Job Scope: Drift, CBL, Ad Perf
Continue pooh w/ 2.25" drift bha, finish circ'ing well to slick 1% KCL w/ safelube. Circ
in 60/40 and diesel FP from 3000'. MU/RIH w/ HES RBT. Log from 14,783' (White
Flag) to 11,200'. Stop at 14,650' to paint correlation flag. POOH after stop at 11,200'.
BD CBL logging tool. Raise scaffolding platform. Make up 2" Perforating gun BHA
(OAL = 37.21'). RIh to white correlation flag, correct depth to top shot 14,624.69'.
Perforate interval 14,665'-14,695' w/ HES 2" MaxForce 6spf, 60deg phasing. Add
25bbls to existing diesel FP in tubing for total of 54bbls.
***Continue on 2-8-25 WSR***
2/8/2025
T/I/O=0/50/0. Post CTD. RD kill line #4 from flow cross, RU 4" chemical blind with
jewelry, Torqued Flange to spec, PT' upper tree against SSV 350/5000 (PASS),
***Job Complete*** Final WHP's 0/50/0.
2/8/2025
LRS CTU #1, 1.5" CT, 0.134" WT. Job Scope: Drift, CBL, Ad Perf
Finish Rig Down, Travel to DS01-37
***Job Complete***
2/9/2025
***WELL S/I ON ARRIVAL***
R/U POL-61
***WSR CONT ON 2-10-25***
2/9/2025
(TFS unit 1 Assist S-Line with testing) Got pulled off job to perform another. Will
return.
2/10/2025
T/I/O 500/500/0 Temp S/I (TFS unit 1 Assist S-Line with testing) Pumped 45 bbls of
Crudd down the TBG to assist S-Line with pulling valves
*******WSR Continued on 2-11-2025********
2/10/2025
***WSR CONT FROM 2-9-25***
DRIFTED 3' x 1-7/8'', 3.79'' CENT, 3.70'' LIB TO DEPLOYMENT SLV @ 11261' SLM
(impression of deploy slv)
RAN 4 1/2" X-CATCHER, TAGGED DEPLOYMENT SLEEVE @ 11,261' SLM, SET
IN X NIPPLE @ 11,254' SLM(Deployment slv 7' below X-nipple at 11273'MD)
PULLED DMY'S FROM ST #1 @ 10,107' MD & ST #2 @ 5,845' MD
SET BK-LGLV IN ST #2 @ 5,845' MD & BK-OGLV IN ST #1 @ 10,107' MD.
PULLED 4-1/2'' X- CATCHER FROM 11273' MD(empty)
BRUSHED DEPLOY SLV w/ KJ, 4-1/2'' BLB, 3' x1-7/8'', 3.70'' GRING, 3'' BLB, B.
NOSE @ 11261' SLM, T-BIRD PUMPED 30 BBLS CRUDE
***WSR CONT ON 2-11-25***
Daily Report of Well Operations
PBU S-126B
Daily Report of Well Operations
PBU S-126B
2/11/2025
***WSR CONT FROM 2-10-25***
DRIFTED UPPER 45 KB PACKER DRIFT 5' x 2-7/8'' SPACER, 3'' PTSA, S/D IN
DEPLOY SLV @ S/D IN DEPLOY SLV @ 11261' SLM (good no-go ring)
SET MONO-PAK LTP IN DEPLOYMENT SLEEVE @ 11,265' MD mid element of
packer. 2.313" x nipple @ 11283' MD.
PT LPT TO 1500PSI
ATTEMPTED TO EQ RSG
BAILED 2 CUPS OF COIL SHAVINGS FROM RSG w/ 10'x2" PUMP BAILER
PULLED RSG FROM 11,262' SLM
***WELL S/I ON DEPARTURE***
2/11/2025
*****WSR Continued from 2-10-2025******* (TFS unit 1 Assist S-Line with changing
valves) Pumped 2 BBLS of crude down TBG to pressure test packer.
SL in control of well upon departure.
DSO notified of departure.
Final WHPS=500/0/0
WELL NAME
Date :
Shoe @ :FC @ :Top Liner @ :
Type:
Type :
Type :
Type :
Type :
XYes No
Yes X No Yes X No
X Yes No X Yes No
Date :
Volume lost during displacement (bbls) : -
Remarks:
Cement In Place At : 10:49 2/3/2025 Estimated TOC : 11,294'
Method Used To Determine TOC : Calculated
3500 psi
Casing Rotated? Reciprocated? % Returns during job : 100%
Cement returns to surface? Spacer returns? Vol to Sur :
FCP (psi) : 2500 Pump used for disp : GD Plug Bumped? Bump press :
Volume : 190
Displacement :
1.5 ppb Geovis Density (ppg) : 8.4 Rate (bpm) : 4 Volume (actual / calculated) : 21.7/22.1
Post Flush (Spacer)
1.5 ppb Geovis Density (ppg) : 8.4 Rate (bpm) : 4
Yield : Sacks : Mixing / Pumping Rate (bpm) :
Tail Slurry
Volume (bbls) : Density (ppg) :
14.8
Yield : 1.332 Sacks : 194 Mixing / Pumping Rate (bpm) : 1.5
Lead Slurry
"G" Volume (bbls): 46.1 Density (ppg) :
FI
R
S
T
S
T
A
G
E
14,826' 14,812/14,823 11,293.73
Preflush (Spacer)
Fresh water Density (ppg) : 8.3 Volume pumped (bbls) : 5 bbls
PBU S-126B CEMENT REPORT
3-Feb-25 Hole Size :4.25"Casing Size :2 7/8"x3 1/4"x3 1/2"
Vert Uncert 1sd
[ft]
0.00
3.00
Start MD End MD Survey Date
[ft] [ft]
26.24 700.00 12/18/2024
700.00 11408.34 12/18/2024
11408.34 12492.34 1/18/2025
12492.34 12971.75 1/21/2025
12971.75 14826.00 1/28/2025
MD Inclination Azimuth TVD TVDSS North East Grid East Grid North Latitude Longitude DLS Toolface Build Rate Turn Rate Vert Sect Major Semi Minor Semi Vert Semi Minor Azim Comments
[ft] [°] [°] [ft] [ft] [ft] [ft] [US ft] [US ft] [°/100ft] [°] [°/100ft] [°/100ft] [ft] [ft] [ft] [ft] [°]
0.00 0.00 13.18 0.00 -67.00 0.00 0.00 618885.30 5979374.30 70°21'8.2950"N 149°02'4.8101"W 0.00 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00
26.24 0.00 13.18 26.24 -40.76 0.00 0.00 618885.30 5979374.30 70°21'8.2950"N 149°02'4.8101"W 0.00 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00
100.00 0.19 13.18 100.00 33.00 0.12 0.03 618885.33 5979374.42 70°21'8.2962"N 149°02'4.8093"W 0.26 123.982 0.26 0.00 -0.05 40.00 40.00 6.43 103.18
200.00 0.16 57.20 200.00 133.00 0.36 0.18 618885.48 5979374.66 70°21'8.2985"N 149°02'4.8047"W 0.13 -105.218 -0.03 44.02 -0.24 40.00 40.00 6.43 119.41
300.00 0.19 6.33 300.00 233.00 0.60 0.32 618885.61 5979374.90 70°21'8.3009"N 149°02'4.8008"W 0.15 -109.896 0.03 -50.87 -0.42 40.00 40.00 6.43 300.70
400.00 1.73 262.36 399.98 332.98 0.56 -1.16 618884.13 5979374.84 70°21'8.3005"N 149°02'4.8440"W 1.79 18.28 1.54 -103.97 1.04 40.00 40.00 6.44 286.79
500.00 6.76 276.05 499.68 432.68 0.98 -8.51 618876.77 5979375.15 70°21'8.3047"N 149°02'5.0589"W 5.10 -2.894 5.03 13.69 8.21 40.00 40.00 6.45 247.07
600.00 9.37 275.24 598.68 531.68 2.34 -22.47 618862.79 5979376.29 70°21'8.3181"N 149°02'5.4669"W 2.61 -35.28 2.61 -0.81 21.73 40.01 40.00 6.45 264.25
700.00 11.09 269.13 697.09 630.09 2.94 -40.20 618845.06 5979376.60 70°21'8.3240"N 149°02'5.9850"W 2.03 -22.99 1.72 -6.11 39.08 40.01 40.01 6.46 273.05
760.46 11.96 267.36 756.33 689.33 2.57 -52.27 618833.00 5979376.04 70°21'8.3203"N 149°02'6.3378"W 1.55 -30.292 1.44 -2.93 51.03 40.01 40.01 6.46 278.80
855.35 12.40 266.17 849.09 782.09 1.43 -72.26 618813.03 5979374.59 70°21'8.3091"N 149°02'6.9220"W 0.53 -90.249 0.46 -1.25 70.91 40.01 40.01 6.48 271.44
949.40 12.40 265.66 940.94 873.94 -0.01 -92.40 618792.92 5979372.83 70°21'8.2950"N 149°02'7.5108"W 0.12 -10.797 0.00 -0.54 91.00 40.02 40.02 6.49 266.06
1044.00 14.79 263.88 1032.89 965.89 -2.06 -114.54 618770.82 5979370.42 70°21'8.2747"N 149°02'8.1578"W 2.56 -4.39 2.53 -1.88 113.16 40.04 40.03 6.51 263.47
1138.42 17.54 263.18 1123.56 1056.56 -5.04 -140.65 618744.75 5979367.03 70°21'8.2455"N 149°02'8.9210"W 2.92 14.615 2.91 -0.74 139.39 40.06 40.04 6.53 261.88
1233.03 19.35 264.60 1213.31 1146.31 -8.21 -170.42 618715.05 5979363.39 70°21'8.2143"N 149°02'9.7909"W 1.97 5.913 1.91 1.50 169.25 40.09 40.05 6.54 261.00
1326.69 21.87 265.30 1300.97 1233.97 -11.10 -203.26 618682.26 5979359.98 70°21'8.1859"N 149°02'10.7507"W 2.70 8.428 2.69 0.75 202.09 40.13 40.07 6.57 260.84
1421.70 24.35 266.19 1388.35 1321.35 -13.85 -240.44 618645.13 5979356.64 70°21'8.1588"N 149°02'11.8375"W 2.64 -10.935 2.61 0.94 239.19 40.19 40.09 6.59 261.11
1515.55 26.96 265.08 1472.94 1405.94 -16.96 -280.95 618604.68 5979352.89 70°21'8.1282"N 149°02'13.0215"W 2.83 -30.949 2.78 -1.18 279.63 40.27 40.11 6.62 261.49
1610.74 28.14 263.59 1557.33 1490.33 -21.32 -324.76 618560.95 5979347.84 70°21'8.0853"N 149°02'14.3018"W 1.44 -4.9 1.24 -1.57 323.52 40.36 40.14 6.66 261.68
1704.83 31.63 263.02 1638.90 1571.90 -26.79 -371.31 618514.49 5979341.62 70°21'8.0314"N 149°02'15.6624"W 3.72 6.029 3.71 -0.61 370.32 40.48 40.176.70261.67
1796.97 35.12 263.66 1715.83 1648.83 -32.66 -421.65 618464.26 5979334.96 70°21'7.9737"N 149°02'17.1337"W 3.81 -3.734 3.79 0.69 420.91 40.63 40.206.75261.66
1891.85 37.45 263.41 1792.31 1725.31 -38.98 -477.44 618408.58 5979327.75 70°21'7.9115"N 149°02'18.7642"W 2.46 4.967 2.46 -0.26 476.95 40.82 40.236.81261.73
1985.05 39.50 263.69 1865.27 1798.27 -45.49 -535.05 618351.08 5979320.33 70°21'7.8474"N 149°02'20.4482"W 2.21 15.174 2.20 0.30 534.83 41.05 40.266.88261.82
2079.19 39.95 263.88 1937.68 1870.68 -52.01 -594.87 618291.39 5979312.87 70°21'7.7833"N 149°02'22.1963"W 0.50 -41.913 0.48 0.20 594.86 41.32 40.29 6.96 261.92
2173.59 41.45 261.87 2009.24 1942.24 -59.66 -655.94 618230.45 5979304.25 70°21'7.7080"N 149°02'23.9813"W 2.11 -21.819 1.59 -2.13 656.33 41.64 40.33 7.06 261.93
2266.36 43.27 260.81 2077.79 2010.79 -69.08 -717.73 618168.82 5979293.85 70°21'7.6153"N 149°02'25.7871"W 2.11 -20.087 1.96 -1.14 718.82 41.99 40.37 7.17 261.79
2361.11 46.73 259.08 2144.78 2077.78 -80.80 -783.68 618103.07 5979281.08 70°21'7.4999"N 149°02'27.7146"W 3.87 31.979 3.65 -1.83 785.80 42.40 40.40 7.28 261.53
2454.37 53.76 264.41 2204.41 2137.41 -90.92 -854.56 618032.36 5979269.85 70°21'7.4004"N 149°02'29.7864"W 8.72 47.099 7.54 5.72 857.37 42.91 40.447.39261.48
2548.59 55.73 266.94 2258.80 2191.80 -96.70 -931.27 617955.76 5979262.85 70°21'7.3435"N 149°02'32.0283"W 3.03 -21.546 2.09 2.69 933.91 43.51 40.48 7.53 261.83
2643.27 57.99 265.89 2310.56 2243.56 -101.66 -1010.39 617876.74 5979256.63 70°21'7.2945"N 149°02'34.3406"W 2.56 17.473 2.39 -1.11 1012.69 44.20 40.51 7.69 262.25
2739.92 60.34 266.74 2360.09 2293.09 -106.99 -1093.20 617794.03 5979249.99 70°21'7.2420"N 149°02'36.7609"W 2.55 -40.944 2.43 0.88 1095.17 44.99 40.55 7.87 262.62
2833.74 61.79 265.32 2405.49 2338.49 -112.68 -1175.10 617712.23 5979243.00 70°21'7.1859"N 149°02'39.1547"W 2.04 47.316 1.55 -1.51 1176.82 45.83 40.58 8.07 262.91
2927.61 63.20 267.02 2448.84 2381.84 -118.23 -1258.17 617629.27 5979236.13 70°21'7.1312"N 149°02'41.5825"W 2.20 -31.451 1.50 1.81 1259.59 46.75 40.61 8.27 263.17
3021.65 65.50 265.48 2489.55 2422.55 -123.79 -1342.75 617544.80 5979229.24 70°21'7.0764"N 149°02'44.0546"W 2.86 -56.222 2.45 -1.64 1343.85 47.74 40.64 8.49 263.40
3116.15 65.96 264.73 2528.39 2461.39 -131.14 -1428.58 617459.10 5979220.52 70°21'7.0040"N 149°02'46.5632"W 0.87 51.937 0.49 -0.79 1429.65 48.81 40.67 8.73 263.53
3210.04 66.24 265.12 2566.43 2499.43 -138.73 -1514.09 617373.73 5979211.58 70°21'6.9291"N 149°02'49.0621"W 0.48 -148.617 0.30 0.42 1515.18 49.93 40.70 8.97 263.62
3303.13 66.21 265.10 2603.96 2536.96 -145.99 -1598.97 617288.99 5979202.97 70°21'6.8575"N 149°02'51.5428"W 0.04 -140.803 -0.03 -0.02 1600.03 51.10 40.74 9.23 263.71
3396.44 65.83 264.76 2641.88 2574.88 -153.53 -1683.89 617204.20 5979194.09 70°21'6.7832"N 149°02'54.0248"W 0.53 -41.236 -0.41 -0.36 1684.97 52.31 40.77 9.49 263.78
3490.88 67.16 263.50 2679.55 2612.55 -162.39 -1770.03 617118.22 5979183.86 70°21'6.6959"N 149°02'56.5425"W 1.87 111.762 1.41 -1.33 1771.34 53.58 40.80 9.77 263.79
3585.81 67.05 263.80 2716.48 2649.48 -172.06 -1856.95 617031.47 5979172.81 70°21'6.6006"N 149°02'59.0826"W 0.31 175.535 -0.12 0.32 1858.62 54.91 40.83 10.05 263.78
3681.42 66.58 263.84 2754.12 2687.12 -181.52 -1944.33 616944.27 5979161.97 70°21'6.5073"N 149°03'1.6363"W 0.49 -134.526 -0.49 0.04 1946.31 56.29 40.87 10.34 263.78
3776.31 66.14 263.35 2792.17 2725.17 -191.22 -2030.71 616858.05 5979150.90 70°21'6.4117"N 149°03'4.1610"W 0.66 -100.979 -0.46 -0.52 2033.06 57.69 40.90 10.64 263.76
3870.33 66.04 262.78 2830.28 2763.28 -201.60 -2116.03 616772.91 5979139.17 70°21'6.3094"N 149°03'6.6546"W 0.56 -15.844 -0.11 -0.61 2118.89 59.10 40.94 10.94 263.72
3966.51 66.46 262.65 2869.01 2802.01 -212.76 -2203.36 616685.79 5979126.63 70°21'6.1994"N 149°03'9.2066"W 0.45 146.815 0.44 -0.14 2206.83 60.57 40.98 11.25 263.67
4058.28 66.32 262.75 2905.77 2838.77 -223.45 -2286.76 616602.57 5979114.62 70°21'6.0940"N 149°03'11.6442"W 0.18 30.446 -0.15 0.11 2290.82 62.01 41.01 11.56 263.62
4153.30 68.06 263.85 2942.60 2875.60 -233.66 -2373.75 616515.76 5979103.03 70°21'5.9933"N 149°03'14.1864"W 2.12 24.929 1.83 1.16 2378.26 63.54 41.05 11.87 263.60
BH CoilTrak (2019) (Standard) S-126B CoilTrak MWD <13000 - 14785.07> S-126B
BH CoilTrak (2019) (Standard) S-126APB1 CoilTrak MWD <11502 - 12652.37> S-126APB1
BH CoilTrak (2019) (Standard) S-126A CoilTrak MWD <12512-14781.18> S-126A
Gyrodata 2015 - CT+WIR+DPIPE 1. S-126 GYD GYRO-CT_DRILL <100-700> S-126
OWSG MWD rev2 + IFR1 + Sag + Multi-Station Correction 2. S-126 MWD+IFR+SAG+MS <760.46-11834.66> S-126
Positional Uncertainty Model Log Name / Comment Wellbore
149°02'4.8101"W
149°02'32.3435"W
148°46'1.0006"W
Horiz Uncert 1sd
[ft]
0.00
20.00
[US ft]
5979374.30
5980854.54
5974812.00
Latitude
70°21'8.2950"N
70°21'23.0025"N
70°20'17.5522"N
[ft]
942.04
Grid East
[US ft]
618885.30
617919.92
651958.00
Slot Location
Facility Reference Pt
Field Reference Pt
Local North
[ft]
-1495.38
260.00°
included
50-029-23363-02
Local East Grid North Longitude
Section Azimuth
Surface Position Uncertainty
API #
NAD27 / TM Alaska SP, Zone 4 (5004), US feet
True
0.999916
0.91 East
Slot
Rig on S-126 (RT)
Rig on S-126 (RT)
Mean Sea Level
67.00 ft
E0.00ft
N0.00ft
Magnetic North is 14.08 degrees East of True North
2.00Std Dev
WA_ANC_Defn
Projection System
North Reference
Scale
Convergence at Slot
Horizontal Reference Point
Vertical Reference Point
MD Reference Point
Field Vertical Reference
Rig on S-126 (RT) To Mean Sea Level
Section Origin X
Section Origin Y
Declination
Ellipse Confidence Limit
Database
2/3/2025 at 8:21:59 AM using WellArchitect 6.0
Hilcorp
North Slope, Alaska
Prudhoe Bay
S- Pad
S-126
S-126B
S-126B
S-126B_awp
12/20/2024
S-126Aat 12971.75 MD
Lopecarh
Minimum curvature
Wellpath
Wellbore last revised
Sidetrack from
User
Calculation method
Field
Facility
Slot
Well
Wellbore
Actual Wellpath Geographic Report - including Position Uncertainty
Report by Baker Hughes
Operator
Area
Page1of4
4247.74 68.34 263.99 2977.68 2910.68 -242.95 -2460.94 616428.73 5979092.36 70°21'5.9017"N 149°03'16.7347"W 0.33 0 0.30 0.15 2465.74 65.11 41.09 12.19 263.61
4341.41 68.55 263.99 3012.09 2945.09 -252.07 -2547.58 616342.26 5979081.87 70°21'5.8117"N 149°03'19.2668"W 0.22 -155.051 0.22 0.00 2552.65 66.69 41.13 12.52 263.62
4436.52 68.51 263.97 3046.90 2979.90 -261.35 -2635.60 616254.40 5979071.19 70°21'5.7201"N 149°03'21.8393"W 0.05 172.489 -0.04 -0.02 2640.95 68.32 41.17 12.85 263.63
4529.96 66.63 264.24 3082.55 3015.55 -270.22 -2721.51 616168.65 5979060.96 70°21'5.6326"N 149°03'24.3500"W 2.03 3.755 -2.01 0.29 2727.09 69.93 41.21 13.18 263.64
4624.71 66.77 264.25 3120.03 3053.03 -278.95 -2808.10 616082.22 5979050.86 70°21'5.5464"N 149°03'26.8805"W 0.15 125.196 0.15 0.01 2813.88 71.57 41.25 13.52 263.65
4720.88 66.66 264.42 3158.05 3091.05 -287.67 -2896.00 615994.47 5979040.75 70°21'5.4603"N 149°03'29.4495"W 0.20 -119.376 -0.11 0.18 2901.96 73.25 41.30 13.87 263.67
4755.40 66.49 264.09 3171.77 3104.77 -290.84 -2927.52 615963.01 5979037.08 70°21'5.4290"N 149°03'30.3706"W 1.01 -141.384 -0.49 -0.96 2933.55 73.86 41.31 13.99 263.67
4836.41 65.49 263.21 3204.73 3137.73 -299.02 -3001.06 615889.61 5979027.73 70°21'5.3483"N 149°03'32.5199"W 1.58 108.907 -1.23 -1.09 3007.40 75.28 41.35 14.28 263.67
4906.08 65.14 264.35 3233.83 3166.83 -305.88 -3063.99 615826.81 5979019.87 70°21'5.2806"N 149°03'34.3590"W 1.57 12.369 -0.50 1.64 3070.56 76.50 41.39 14.53 263.66
5000.15 66.86 264.76 3272.09 3205.09 -314.03 -3149.54 615741.41 5979010.37 70°21'5.2001"N 149°03'36.8591"W 1.87 59.554 1.83 0.44 3156.22 78.19 41.44 14.87 263.68
5094.99 67.23 265.44 3309.08 3242.08 -321.49 -3236.55 615654.54 5979001.53 70°21'5.1263"N 149°03'39.4020"W 0.77 -37.585 0.39 0.72 3243.21 79.92 41.49 15.22 263.72
5190.69 67.41 265.29 3345.98 3278.98 -328.63 -3324.56 615566.66 5978993.00 70°21'5.0558"N 149°03'41.9741"W 0.24 -98.086 0.19 -0.16 3331.12 81.68 41.54 15.58 263.76
5284.90 67.38 265.06 3382.19 3315.19 -335.94 -3411.23 615480.13 5978984.31 70°21'4.9834"N 149°03'44.5069"W 0.23 92.758 -0.03 -0.24 3417.74 83.44 41.58 15.93 263.79
5378.86 67.35 265.77 3418.35 3351.35 -342.87 -3497.67 615393.81 5978976.01 70°21'4.9149"N 149°03'47.0332"W 0.70 -100.925 -0.03 0.76 3504.07 85.20 41.63 16.28 263.83
5473.77 67.22 265.03 3455.00 3388.00 -349.90 -3584.94 615306.68 5978967.60 70°21'4.8454"N 149°03'49.5836"W 0.73 118.576 -0.14 -0.78 3591.23 86.98 41.69 16.64 263.87
5567.52 67.00 265.47 3491.47 3424.47 -357.05 -3671.01 615220.74 5978959.09 70°21'4.7747"N 149°03'52.0990"W 0.49 -77.346 -0.23 0.47 3677.24 88.76 41.74 16.99 263.90
5660.58 67.10 264.99 3527.76 3460.76 -364.17 -3756.40 615135.47 5978950.61 70°21'4.7042"N 149°03'54.5947"W 0.49 77.46 0.11 -0.52 3762.57 90.52 41.79 17.34 263.93
5756.66 67.22 265.57 3565.05 3498.05 -371.46 -3844.65 615047.36 5978941.92 70°21'4.6321"N 149°03'57.1736"W 0.57 -170.132 0.12 0.60 3850.74 92.36 41.85 17.71 263.95
5848.90 66.85 265.50 3601.04 3534.04 -378.07 -3929.32 614962.81 5978933.97 70°21'4.5666"N 149°03'59.6481"W 0.41 69.787 -0.40 -0.08 3935.28 94.13 41.90 18.06 263.99
5942.39 67.01 265.97 3637.67 3570.67 -384.47 -4015.09 614877.16 5978926.21 70°21'4.5033"N 149°04'2.1549"W 0.49 175.617 0.17 0.50 4020.86 95.93 41.96 18.42 264.02
6038.45 66.89 265.98 3675.28 3608.28 -390.67 -4103.27 614789.10 5978918.61 70°21'4.4418"N 149°04'4.7317"W 0.13 87.886 -0.12 0.01 4108.77 97.79 42.02 18.79 264.06
6132.25 66.91 266.54 3712.09 3645.09 -396.30 -4189.36 614703.11 5978911.62 70°21'4.3860"N 149°04'7.2478"W 0.55 -137.401 0.02 0.60 4194.53 99.62 42.08 19.15 264.11
6226.50 66.87 266.50 3749.08 3682.08 -401.56 -4275.89 614616.69 5978904.98 70°21'4.3337"N 149°04'9.7766"W 0.06 143.569 -0.04 -0.04 4280.66 101.46 42.14 19.51 264.15
6320.80 66.30 266.96 3786.55 3719.55 -406.50 -4362.28 614530.39 5978898.68 70°21'4.2847"N 149°04'12.3014"W 0.75 -64.09 -0.60 0.49 4366.60 103.30 42.20 19.88 264.20
6414.40 67.01 265.39 3823.64 3756.64 -412.23 -4448.02 614444.76 5978891.58 70°21'4.2278"N 149°04'14.8072"W 1.72 116.658 0.76 -1.68 4452.03 105.14 42.26 20.24 264.24
6507.61 66.95 265.52 3860.09 3793.09 -419.03 -4533.54 614359.37 5978883.43 70°21'4.1604"N 149°04'17.3064"W 0.14 109.167 -0.06 0.14 4537.43 106.97 42.32 20.60 264.26
6601.26 66.39 267.31 3897.19 3830.19 -424.41 -4619.36 614273.65 5978876.69 70°21'4.1070"N 149°04'19.8144"W 1.85 -70.835 -0.60 1.91 4622.88 108.82 42.39 20.97 264.30
6696.50 67.46 264.08 3934.52 3867.52 -431.00 -4706.72 614186.42 5978868.72 70°21'4.0417"N 149°04'22.3673"W 3.32 44.887 1.12 -3.39 4710.05 110.71 42.45 21.34 264.32
6788.84 67.59 264.22 3969.82 3902.82 -439.69 -4791.60 614101.69 5978858.68 70°21'3.9556"N 149°04'24.8479"W 0.20 -102.843 0.14 0.15 4795.16 112.54 42.52 21.70 264.32
6881.91 67.50 263.79 4005.37 3938.37 -448.68 -4877.14 614016.31 5978848.34 70°21'3.8667"N 149°04'27.3478"W 0.44 105.786 -0.10 -0.46 4880.96 114.39 42.58 22.07 264.31
6977.31 67.36 264.33 4041.99 3974.99 -457.79 -4964.76 613928.85 5978837.83 70°21'3.7765"N 149°04'29.9084"W 0.54 129.025 -0.15 0.57 4968.83 116.29 42.65 22.44 264.30
7069.82 67.01 264.80 4077.86 4010.86 -465.87 -5049.65 613844.11 5978828.41 70°21'3.6965"N 149°04'32.3891"W 0.60 -98.11 -0.38 0.51 5053.83 118.14 42.72 22.81 264.30
7165.81 66.98 264.57 4115.37 4048.37 -474.06 -5137.63 613756.28 5978818.83 70°21'3.6154"N 149°04'34.9601"W 0.22 -149.233 -0.03 -0.24 5141.89 120.06 42.79 23.19 264.30
7259.58 65.41 263.54 4153.22 4086.22 -482.94 -5222.95 613671.11 5978808.60 70°21'3.5275"N 149°04'37.4537"W 1.95 -142.667 -1.67 -1.10 5227.47 121.92 42.86 23.56 264.29
7355.72 65.03 263.22 4193.51 4126.51 -493.00 -5309.66 613584.59 5978797.17 70°21'3.4279"N 149°04'39.9875"W 0.50 160.117 -0.40 -0.33 5314.60 123.80 42.93 23.94 264.27
7450.44 64.73 263.34 4233.72 4166.72 -503.03 -5394.83 613499.59 5978785.78 70°21'3.3286"N 149°04'42.4765"W 0.34 -5.176 -0.32 0.13 5400.22 125.65 43.01 24.31 264.25
7543.12 64.93 263.32 4273.14 4206.14 -512.78 -5478.14 613416.45 5978774.72 70°21'3.2322"N 149°04'44.9111"W 0.22 -128.005 0.22 -0.02 5483.96 127.47 43.09 24.67 264.23
7637.57 64.62 262.88 4313.39 4246.39 -523.04 -5562.97 613331.81 5978763.11 70°21'3.1307"N 149°04'47.3899"W 0.53 67.955 -0.33 -0.47 5569.28 129.31 43.17 25.04 264.21
7731.40 64.83 263.45 4353.46 4286.46 -533.14 -5647.21 613247.74 5978751.68 70°21'3.0307"N 149°04'49.8517"W 0.59 -179.313 0.22 0.61 5654.00 131.15 43.25 25.40 264.19
7826.58 64.08 263.44 4394.50 4327.50 -542.94 -5732.53 613162.60 5978740.52 70°21'2.9337"N 149°04'52.3449"W 0.79 104.526 -0.79 -0.01 5739.72 133.02 43.33 25.78 264.17
7920.44 63.66 265.30 4435.84 4368.84 -551.21 -5816.38 613078.90 5978730.93 70°21'2.8517"N 149°04'54.7954"W 1.83 68.469 -0.45 1.98 5823.73 134.85 43.42 26.14 264.17
8016.64 64.00 266.25 4478.27 4411.27 -557.57 -5902.48 612992.91 5978723.20 70°21'2.7885"N 149°04'57.3116"W 0.95 -133.225 0.35 0.99 5909.63 136.74 43.50 26.52 264.19
8111.84 63.58 265.75 4520.31 4453.31 -563.53 -5987.69 612907.82 5978715.89 70°21'2.7293"N 149°04'59.8015"W 0.65 93.004 -0.44 -0.53 5994.58 138.62 43.59 26.89 264.22
8206.18 63.56 266.19 4562.31 4495.31 -569.47 -6071.96 612823.66 5978708.62 70°21'2.6702"N 149°05'2.2642"W 0.42 150.243 -0.02 0.47 6078.60 140.48 43.68 27.26 264.24
8299.91 63.17 266.44 4604.32 4537.32 -574.85 -6155.57 612740.16 5978701.91 70°21'2.6166"N 149°05'4.7076"W 0.48 54.484 -0.42 0.27 6161.87 142.32 43.77 27.62 264.26
8392.99 64.26 268.12 4645.55 4578.55 -578.80 -6238.92 612656.88 5978696.63 70°21'2.5770"N 149°05'7.1436"W 2.00 86.033 1.17 1.80 6244.65 144.17 43.86 27.99 264.30
8487.30 64.76 274.13 4686.16 4619.16 -577.13 -6323.98 612571.81 5978696.96 70°21'2.5928"N 149°05'9.6295"W 5.78 88.009 0.53 6.37 6328.12 146.06 43.95 28.36 264.39
8582.51 64.99 278.95 4726.61 4659.61 -567.31 -6409.59 612486.07 5978705.42 70°21'2.6887"N 149°05'12.1316"W 4.59 146.9 0.24 5.06 6410.72 147.98 44.04 28.73 264.56
8677.68 62.09 281.10 4769.01 4702.01 -552.50 -6493.48 612401.96 5978718.90 70°21'2.8336"N 149°05'14.5836"W 3.66 -123.163 -3.05 2.26 6490.77 149.84 44.14 29.10 264.77
8771.87 61.25 279.62 4813.71 4746.71 -537.59 -6575.03 612320.19 5978732.51 70°21'2.9796"N 149°05'16.9674"W 1.65 52.094 -0.89 -1.57 6568.49 151.64 44.23 29.47 264.97
8865.98 61.38 279.81 4858.88 4791.88 -523.65 -6656.40 612238.61 5978745.15 70°21'3.1159"N 149°05'19.3460"W 0.22 156.424 0.14 0.20 6646.21 153.44 44.33 29.83 265.15
8960.10 59.43 280.80 4905.37 4838.37 -509.02 -6736.92 612157.88 5978758.50 70°21'3.2591"N 149°05'21.6995"W 2.26 -171.255 -2.07 1.05 6722.96 155.22 44.44 30.18 265.34
9055.38 56.45 280.25 4955.94 4888.94 -494.27 -6816.30 612078.28 5978771.99 70°21'3.4035"N 149°05'24.0198"W 3.17 78.279 -3.13 -0.58 6798.57 156.95 44.55 30.54 265.52
9147.86 56.49 280.48 5007.02 4940.02 -480.40 -6892.13 612002.25 5978784.66 70°21'3.5392"N 149°05'26.2364"W 0.21 157.389 0.04 0.25 6870.85 158.60 44.66 30.87 265.68
9244.00 56.41 280.52 5060.15 4993.15 -465.80 -6970.92 611923.25 5978798.01 70°21'3.6821"N 149°05'28.5393"W 0.09 165.436 -0.08 0.04 6945.90 160.31 44.78 31.22 265.85
9337.95 56.25 280.57 5112.24 5045.24 -451.49 -7047.78 611846.17 5978811.09 70°21'3.8221"N 149°05'30.7862"W 0.18 88.867 -0.17 0.05 7019.11 161.98 44.89 31.56 266.01
9433.85 56.30 282.60 5165.49 5098.49 -435.47 -7125.91 611767.80 5978825.87 70°21'3.9789"N 149°05'33.0700"W 1.76 -100.483 0.05 2.12 7093.27 163.68 45.01 31.91 266.18
9527.02 56.11 281.32 5217.31 5150.31 -419.42 -7201.66 611691.82 5978840.71 70°21'4.1360"N 149°05'35.2842"W 1.16 121.091 -0.20 -1.37 7165.08 165.33 45.13 32.24 266.35
9619.20 55.67 282.21 5269.01 5202.01 -403.86 -7276.38 611616.87 5978855.08 70°21'4.2883"N 149°05'37.4683"W 0.93 165.242 -0.48 0.97 7235.96 166.95 45.25 32.58 266.50
9713.29 50.82 283.86 5325.29 5258.29 -386.90 -7349.80 611543.20 5978870.87 70°21'4.4545"N 149°05'39.6146"W 5.34 165.566 -5.15 1.75 7305.32 168.52 45.38 32.91 266.67
9805.65 46.07 285.56 5386.54 5319.54 -369.39 -7416.63 611476.10 5978887.32 70°21'4.6260"N 149°05'41.5685"W 5.32 -173.953 -5.14 1.84 7368.10 169.89 45.51 33.21 266.82
9899.20 41.79 284.88 5453.90 5386.90 -352.34 -7479.24 611413.23 5978903.37 70°21'4.7931"N 149°05'43.3987"W 4.60 -172.149 -4.58 -0.73 7426.80 171.13 45.64 33.49 266.95
9993.58 39.75 284.44 5525.38 5458.38 -336.74 -7538.86 611353.38 5978918.02 70°21'4.9459"N 149°05'45.1417"W 2.18 146.105 -2.16 -0.47 7482.81 172.27 45.79 33.75 267.07
10088.54 39.57 284.63 5598.48 5531.48 -321.53 -7597.53 611294.48 5978932.30 70°21'5.0949"N 149°05'46.8567"W 0.23 175.982 -0.19 0.20 7537.94 173.37 45.94 34.00 267.19
10181.96 39.21 284.67 5670.68 5603.68 -306.54 -7654.89 611236.90 5978946.38 70°21'5.2418"N 149°05'48.5335"W 0.39 141.342 -0.39 0.04 7591.82 174.45 46.09 34.25 267.29
10276.29 38.92 285.04 5743.92 5676.92 -291.30 -7712.35 611179.21 5978960.70 70°21'5.3911"N 149°05'50.2133"W 0.39 32.594 -0.31 0.39 7645.76 175.53 46.24 34.50 267.40
10369.36 42.28 288.19 5814.58 5747.58 -273.93 -7770.34 611120.95 5978977.15 70°21'5.5613"N 149°05'51.9089"W 4.23 -179.204 3.61 3.38 7699.86 176.64 46.39 34.75 267.53
10464.12 41.80 288.18 5884.96 5817.96 -254.13 -7830.63 611060.36 5978995.99 70°21'5.7555"N 149°05'53.6714"W 0.51 135.092 -0.51 -0.01 7755.79 177.80 46.55 35.02 267.67
10560.59 41.41 288.77 5957.09 5890.09 -233.83 -7891.38 610999.30 5979015.32 70°21'5.9545"N 149°05'55.4477"W 0.57 -132.932 -0.40 0.61 7812.10 178.98 46.71 35.29 267.81
10655.24 41.19 288.41 6028.20 5961.20 -213.92 -7950.59 610939.78 5979034.29 70°21'6.1497"N 149°05'57.1788"W 0.34 171.426 -0.23 -0.38 7866.95 180.12 46.87 35.56 267.94
10748.11 40.80 288.50 6098.30 6031.30 -194.63 -8008.38 610881.70 5979052.65 70°21'6.3388"N 149°05'58.8684"W 0.42 -164.833 -0.42 0.10 7920.51 181.23 47.03 35.82 268.07
10842.95 38.77 287.62 6171.17 6104.17 -175.81 -8066.07 610823.72 5979070.56 70°21'6.5233"N 149°06'0.5551"W 2.22 -172.478 -2.14 -0.93 7974.06 182.32 47.19 36.08 268.19
10937.03 36.01 287.00 6245.91 6178.91 -158.80 -8120.61 610768.93 5979086.69 70°21'6.6899"N 149°06'2.1494"W 2.96 -162.171 -2.93 -0.66 8024.81 183.33 47.36 36.33 268.30
11031.20 33.64 285.62 6323.21 6256.21 -143.68 -8172.21 610717.10 5979100.99 70°21'6.8381"N 149°06'3.6581"W 2.65 -174.971 -2.52 -1.47 8073.00 184.26 47.52 36.56 268.39
11125.06 32.96 285.51 6401.66 6334.66 -129.86 -8221.85 610667.25 5979114.03 70°21'6.9735"N 149°06'5.1094"W 0.73 161.278 -0.72 -0.12 8119.49 185.13 47.69 36.78 268.47
11219.30 32.16 286.02 6481.09 6414.09 -116.08 -8270.66 610618.23 5979127.03 70°21'7.1085"N 149°06'6.5364"W 0.90 -155.687 -0.85 0.54 8165.17 185.98 47.86 37.00 268.54
11313.21 31.57 285.51 6560.85 6493.85 -102.61 -8318.37 610570.32 5979139.74 70°21'7.2405"N 149°06'7.9313"W 0.69 175.432 -0.63 -0.54 8209.81 186.80 48.04 37.22 268.62
11408.34 30.99 285.60 6642.15 6575.15 -89.36 -8365.96 610522.53 5979152.23 70°21'7.3702"N 149°06'9.3224"W 0.61 -140.252 -0.61 0.09 8254.38 187.62 48.21 37.43 268.69 Tie on Point of S-126A to S-126
11502.00 30.66 285.06 6722.58 6655.58 -76.67 -8412.24 610476.06 5979164.18 70°21'7.4945"N 149°06'10.6756"W 0.46 -5.45 -0.35 -0.58 8297.75 188.14 47.90 38.60 268.72 TOWS
11515.69 32.82 284.68 6734.22 6667.22 -74.83 -8419.20 610469.07 5979165.92 70°21'7.5126"N 149°06'10.8791"W 15.85 -57.396 15.78 -2.78 8304.29 188.17 47.90 38.60 268.72 Interpolated Azimuth
11545.80 34.03 281.42 6759.35 6692.35 -71.09 -8435.35 610452.86 5979169.40 70°21'7.5492"N 149°06'11.3514"W 7.19 -2.257 4.02 -10.83 8319.55 188.25 47.92 38.62 268.73 Interpolated Azimuth
11575.76 41.64 280.97 6783.00 6716.00 -67.53 -8453.37 610434.79 5979172.67 70°21'7.5840"N 149°06'11.8780"W 25.42 -2.766 25.40 -1.50 8336.67 188.35 47.94 38.64 268.74 Interpolated Azimuth
11605.82 49.72 280.46 6803.98 6736.98 -63.54 -8474.48 610413.62 5979176.32 70°21'7.6230"N 149°06'12.4953"W 26.91 -17.263 26.88 -1.70 8356.77 188.46 47.97 38.66 268.75
11635.73 58.31 277.35 6821.54 6754.54 -59.83 -8498.37 610389.68 5979179.65 70°21'7.6592"N 149°06'13.1936"W 29.92 -14.492 28.72 -10.40 8379.65 188.59 48.01 38.68 268.75
11665.72 66.52 275.05 6835.42 6768.42 -56.99 -8524.78 610363.23 5979182.08 70°21'7.6869"N 149°06'13.9654"W 28.20 -18.285 27.38 -7.67 8405.16 188.74 48.04 38.71 268.76
11695.76 74.50 272.33 6845.44 6778.44 -55.18 -8553.01 610334.98 5979183.43 70°21'7.7043"N 149°06'14.7907"W 27.90 -22.854 26.56 -9.05 8432.65 188.90 48.07 38.74 268.77
11715.82 79.58 270.16 6849.93 6782.93 -54.76 -8572.55 610315.44 5979183.54 70°21'7.7082"N 149°06'15.3617"W 27.43 -16.149 25.32 -10.82 8451.82 189.02 48.08 38.75 268.77
11744.56 88.25 267.66 6852.98 6785.98 -55.31 -8601.09 610286.91 5979182.54 70°21'7.7025"N 149°06'16.1959"W 31.38 -36.123 30.17 -8.70 8480.03 189.20 48.10 38.77 268.78
Page2of4
11774.54 92.58 264.50 6852.76 6785.76 -57.36 -8630.99 610257.05 5979180.02 70°21'7.6820"N 149°06'17.0697"W 17.88 -78.091 14.44 -10.54 8509.82 189.39 48.11 38.80 268.78
11804.53 93.38 260.67 6851.20 6784.20 -61.22 -8660.68 610227.42 5979175.69 70°21'7.6437"N 149°06'17.9374"W 13.03 -118.255 2.67 -12.77 8539.74 189.59 48.11 38.82 268.77
11834.54 91.84 257.81 6849.83 6782.83 -66.82 -8690.13 610198.07 5979169.62 70°21'7.5883"N 149°06'18.7979"W 10.81 -85.762 -5.13 -9.53 8569.71 189.80 48.12 38.83 268.76
11871.22 92.12 253.97 6848.57 6781.57 -75.75 -8725.68 610162.67 5979160.13 70°21'7.5000"N 149°06'19.8365"W 10.49 113.959 0.76 -10.47 8606.27 190.06 48.12 38.85 268.75
11896.47 91.11 256.24 6847.85 6780.85 -82.24 -8750.07 610138.39 5979153.25 70°21'7.4360"N 149°06'20.5491"W 9.84 106.552 -4.00 8.99 8631.41 190.24 48.13 38.86 268.73
11925.48 89.97 260.07 6847.58 6780.58 -88.19 -8778.45 610110.11 5979146.85 70°21'7.3771"N 149°06'21.3785"W 13.77 91.446 -3.93 13.20 8660.40 190.46 48.14 38.87 268.72
11955.46 89.88 263.64 6847.62 6780.62 -92.44 -8808.12 610080.51 5979142.13 70°21'7.3350"N 149°06'22.2456"W 11.91 75.772 -0.30 11.91 8690.36 190.70 48.15 38.89 268.71
11985.62 91.01 268.10 6847.39 6780.39 -94.61 -8838.20 610050.48 5979139.49 70°21'7.3133"N 149°06'23.1245"W 15.25 83.835 3.75 14.79 8720.35 190.95 48.16 38.91 268.71
12015.71 91.47 272.39 6846.73 6779.73 -94.48 -8868.27 610020.41 5979139.14 70°21'7.3142"N 149°06'24.0035"W 14.34 74.873 1.53 14.26 8749.95 191.21 48.17 38.93 268.71
12045.55 93.32 279.30 6845.49 6778.49 -91.45 -8897.91 609990.72 5979141.70 70°21'7.3437"N 149°06'24.8699"W 23.95 -113.295 6.20 23.16 8778.61 191.47 48.18 38.95 268.72
12075.63 92.98 278.51 6843.83 6776.83 -86.80 -8927.58 609960.98 5979145.88 70°21'7.3890"N 149°06'25.7373"W 2.86 -78.573 -1.13 -2.63 8807.03 191.74 48.19 38.97 268.73
12105.63 93.68 275.01 6842.09 6775.09 -83.28 -8957.32 609931.20 5979148.93 70°21'7.4234"N 149°06'26.6065"W 11.88 -87.92 2.33 -11.67 8835.70 192.02 48.21 39.00 268.75
12140.86 93.78 272.12 6839.80 6772.80 -81.09 -8992.40 609896.09 5979150.56 70°21'7.4444"N 149°06'27.6320"W 8.19 -98.552 0.28 -8.20 8869.87 192.36 48.22 39.03 268.76
12165.72 93.59 270.86 6838.20 6771.20 -80.45 -9017.20 609871.28 5979150.81 70°21'7.4505"N 149°06'28.3568"W 5.12 -115.581 -0.76 -5.07 8894.18 192.61 48.23 39.05 268.76
12195.83 92.67 268.94 6836.56 6769.56 -80.50 -9047.27 609841.23 5979150.28 70°21'7.4496"N 149°06'29.2355"W 7.06 -87.839 -3.06 -6.38 8923.80 192.91 48.24 39.08 268.77
12225.83 92.82 264.77 6835.12 6768.12 -82.14 -9077.18 609811.35 5979148.16 70°21'7.4331"N 149°06'30.1097"W 13.89 -121.532 0.50 -13.90 8953.54 193.22 48.25 39.11 268.76
12254.24 90.89 261.63 6834.20 6767.20 -85.50 -9105.37 609783.21 5979144.35 70°21'7.3997"N 149°06'30.9335"W 12.97 -85.93 -6.79 -11.05 8981.89 193.52 48.26 39.14 268.76
12284.21 91.10 258.66 6833.68 6766.68 -90.63 -9134.89 609753.78 5979138.76 70°21'7.3489"N 149°06'31.7961"W 9.93 -67.244 0.70 -9.91 9011.85 193.84 48.27 39.17 268.74
12314.36 92.18 256.08 6832.81 6765.81 -97.22 -9164.30 609724.49 5979131.70 70°21'7.2838"N 149°06'32.6553"W 9.27 -84.789 3.58 -8.56 9041.95 194.16 48.28 39.20 268.72
12344.89 92.61 251.27 6831.54 6764.54 -105.79 -9193.56 609695.36 5979122.67 70°21'7.1991"N 149°06'33.5103"W 15.80 -42.23 1.41 -15.75 9072.26 194.48 48.29 39.24 268.70
12374.67 95.84 248.32 6829.34 6762.34 -116.05 -9221.43 609667.67 5979111.98 70°21'7.0979"N 149°06'34.3244"W 14.67 -34.375 10.85 -9.91 9101.48 194.79 48.30 39.28 268.66
12404.30 99.07 246.08 6825.50 6758.50 -127.43 -9248.51 609640.78 5979100.17 70°21'6.9857"N 149°06'35.1154"W 13.23 -79.029 10.90 -7.56 9130.13 195.09 48.31 39.32 268.62
12434.29 99.81 242.09 6820.58 6753.58 -140.35 -9275.11 609614.38 5979086.82 70°21'6.8582"N 149°06'35.8925"W 13.35 -109.668 2.47 -13.30 9158.57 195.39 48.33 39.36 268.58
12464.62 98.77 239.18 6815.68 6748.68 -155.03 -9301.19 609588.54 5979071.74 70°21'6.7136"N 149°06'36.6543"W 10.07 -87.034 -3.43 -9.59 9186.81 195.68 48.35 39.39 268.53
12492.34 98.93 235.75 6811.42 6744.42 -169.76 -9324.28 609565.69 5979056.65 70°21'6.5684"N 149°06'37.3285"W 12.24 -91.491 0.58 -12.37 9212.10 195.94 48.38 39.43 268.48
12512.00 98.88 233.97 6808.37 6741.37 -180.94 -9340.16 609549.99 5979045.22 70°21'6.4583"N 149°06'37.7923"W 8.95 176.84 -0.25 -9.05 9229.68 196.46 49.37 40.17 268.67 Top of Billet S-126A
12535.29 93.63 234.26 6805.84 6738.84 -194.50 -9358.91 609531.46 5979031.36 70°21'6.3246"N 149°06'38.3399"W 22.58 -147.832 -22.54 1.25 9250.50 196.60 49.39 40.17 268.64
12545.53 92.12 233.31 6805.32 6738.32 -200.54 -9367.16 609523.30 5979025.18 70°21'6.2651"N 149°06'38.5808"W 17.42 -176.719 -14.75 -9.28 9259.68 196.66 49.40 40.17 268.63
12569.37 90.55 233.22 6804.77 6737.77 -214.80 -9386.26 609504.43 5979010.63 70°21'6.1247"N 149°06'39.1385"W 6.60 -67.107 -6.59 -0.38 9280.96 196.80 49.42 40.18 268.60
12600.48 92.86 227.73 6803.84 6736.84 -234.58 -9410.24 609480.78 5978990.47 70°21'5.9299"N 149°06'39.8385"W 19.14 -94.084 7.43 -17.65 9308.01 196.98 49.47 40.18 268.55
12625.47 92.43 221.90 6802.69 6735.69 -252.28 -9427.83 609463.47 5978972.50 70°21'5.7556"N 149°06'40.3518"W 23.37 -108.508 -1.72 -23.33 9328.40 197.12 49.50 40.19 268.51
12653.87 90.83 217.14 6801.88 6734.88 -274.17 -9445.88 609445.77 5978950.32 70°21'5.5400"N 149°06'40.8788"W 17.68 -119.427 -5.63 -16.76 9349.99 197.26 49.56 40.19 268.46
12673.28 89.82 215.35 6801.77 6734.77 -289.83 -9457.36 609434.54 5978934.49 70°21'5.3859"N 149°06'41.2136"W 10.59 -95.199 -5.20 -9.22 9364.01 197.35 49.60 40.20 268.42
12696.81 89.36 210.28 6801.94 6734.94 -309.59 -9470.11 609422.11 5978914.52 70°21'5.1914"N 149°06'41.5854"W 21.63 -84.239 -1.95 -21.55 9380.00 197.46 49.66 40.20 268.37
12726.86 89.85 205.44 6802.14 6735.14 -336.15 -9484.15 609408.50 5978887.75 70°21'4.9300"N 149°06'41.9947"W 16.19 -88.955 1.63 -16.11 9398.43 197.57 49.75 40.21 268.31
12761.82 89.97 198.90 6802.20 6735.20 -368.51 -9497.33 609395.83 5978855.19 70°21'4.6116"N 149°06'42.3789"W 18.71 -95.046 0.34 -18.71 9417.04 197.69 49.86 40.23 268.23
12791.83 89.48 193.34 6802.34 6735.34 -397.33 -9505.66 609387.96 5978826.24 70°21'4.3281"N 149°06'42.6212"W 18.60 -99.62 -1.63 -18.53 9430.24 197.76 49.97 40.24 268.16
12816.99 88.90 189.91 6802.70 6735.70 -421.97 -9510.73 609383.28 5978801.53 70°21'4.0857"N 149°06'42.7685"W 13.82 59.205 -2.31 -13.63 9439.51 197.81 50.07 40.25 268.10
12851.87 91.66 194.54 6802.53 6735.53 -456.04 -9518.11 609376.44 5978767.35 70°21'3.7505"N 149°06'42.9830"W 15.45 81.988 7.91 13.27 9452.70 197.87 50.23 40.27 268.01
12881.98 92.40 199.86 6801.46 6734.46 -484.78 -9527.01 609368.00 5978738.48 70°21'3.4677"N 149°06'43.2419"W 17.83 110.815 2.46 17.67 9466.45 197.95 50.39 40.29 267.94
12911.84 90.89 203.82 6800.60 6733.60 -512.48 -9538.11 609357.34 5978710.61 70°21'3.1952"N 149°06'43.5653"W 14.19 109.617 -5.06 13.26 9482.19 198.05 50.56 40.31 267.87
12951.57 88.37 210.89 6800.86 6733.86 -547.74 -9556.35 609339.66 5978675.06 70°21'2.8482"N 149°06'44.0971"W 18.89 123.298 -6.34 17.80 9506.28 198.20 50.81 40.34 267.78
12971.75 87.02 212.95 6801.67 6734.67 -564.85 -9567.01 609329.28 5978657.78 70°21'2.6797"N 149°06'44.4080"W 12.20 106.632 -6.69 10.21 9519.75 198.30 50.94 40.35 267.73
13000.00 85.69 217.45 6803.47 6736.47 -587.88 -9583.26 609313.40 5978634.50 70°21'2.4530"N 149°06'44.8819"W 16.58 63.031 -4.71 15.93 9539.75 198.64 50.54 40.43 267.66 Top of the Billet S-126B
13024.66 87.42 220.84 6804.95 6737.95 -606.97 -9598.79 609298.17 5978615.17 70°21'2.2651"N 149°06'45.3353"W 15.41 94.012 7.02 13.75 9558.36 198.77 50.64 40.44 267.61
13056.60 87.08 225.84 6806.48 6739.48 -630.16 -9620.68 609276.65 5978591.63 70°21'2.0367"N 149°06'45.9741"W 15.67 123.147 -1.06 15.65 9583.95 198.94 50.76 40.44 267.55
13087.24 84.18 230.32 6808.82 6741.82 -650.57 -9643.40 609254.26 5978570.87 70°21'1.8357"N 149°06'46.6374"W 17.38 126.326 -9.46 14.62 9609.87 199.13 50.88 40.44 267.50
13117.03 81.76 233.66 6812.47 6745.47 -668.77 -9666.69 609231.27 5978552.30 70°21'1.6564"N 149°06'47.3174"W 13.78 63.073 -8.12 11.21 9635.97 199.33 50.99 40.45 267.44
13146.91 83.12 236.34 6816.40 6749.40 -685.76 -9690.95 609207.28 5978534.93 70°21'1.4890"N 149°06'48.0257"W 9.99 -123.768 4.55 8.97 9662.81 199.53 51.10 40.46 267.39
13172.38 82.30 235.10 6819.63 6752.63 -699.99 -9711.83 609186.63 5978520.38 70°21'1.3488"N 149°06'48.6353"W 5.80 -107.299 -3.22 -4.87 9685.84 199.71 51.20 40.47 267.35
13202.24 81.36 232.01 6823.87 6756.87 -717.54 -9735.60 609163.14 5978502.45 70°21'1.1759"N 149°06'49.3294"W 10.72 -79.936 -3.15 -10.35 9712.30 199.92 51.32 40.48 267.29
13222.21 81.84 229.33 6826.79 6759.79 -730.06 -9750.88 609148.07 5978489.69 70°21'1.0525"N 149°06'49.7755"W 13.49 -109.587 2.40 -13.42 9729.52 200.06 51.41 40.49 267.25
13243.54 80.99 226.89 6829.98 6762.98 -744.15 -9766.58 609132.59 5978475.36 70°21'0.9138"N 149°06'50.2337"W 11.99 -39.688 -3.98 -11.44 9747.43 200.20 51.51 40.50 267.21
13280.63 83.68 224.65 6834.92 6767.92 -769.78 -9792.92 609106.67 5978449.31 70°21'0.6614"N 149°06'51.0023"W 9.40 -14.641 7.25 -6.04 9777.81 200.45 51.70 40.52 267.13
13310.30 87.70 223.60 6837.15 6770.15 -791.02 -9813.51 609086.42 5978427.75 70°21'0.4523"N 149°06'51.6034"W 14.00 84.217 13.55 -3.54 9801.78 200.64 51.87 40.53 267.06
13340.48 87.95 226.05 6838.30 6771.30 -812.41 -9834.77 609065.50 5978406.03 70°21'0.2416"N 149°06'52.2238"W 8.15 83.025 0.83 8.12 9826.43 200.84 52.04 40.55 267.00
13374.04 88.46 230.18 6839.35 6772.35 -834.80 -9859.73 609040.90 5978383.25 70°21'0.0211"N 149°06'52.9526"W 12.39 87.93 1.52 12.31 9854.90 201.08 52.24 40.57 266.92
13400.80 88.56 232.90 6840.05 6773.05 -851.43 -9880.68 609020.22 5978366.29 70°20'59.8572"N 149°06'53.5641"W 10.17 110.302 0.37 10.16 9878.42 201.29 52.40 40.59 266.86
13430.53 87.27 236.40 6841.13 6774.13 -868.62 -9904.91 608996.27 5978348.72 70°20'59.6879"N 149°06'54.2714"W 12.54 74.318 -4.34 11.77 9905.26 201.53 52.56 40.61 266.80
13455.51 88.56 240.97 6842.04 6775.04 -881.59 -9926.23 608975.16 5978335.41 70°20'59.5600"N 149°06'54.8940"W 19.00 92.039 5.16 18.29 9928.51 201.74 52.69 40.63 266.74
13507.57 88.47 243.54 6843.39 6776.39 -905.82 -9972.28 608929.50 5978310.46 70°20'59.3212"N 149°06'56.2390"W 4.94 82.258 -0.17 4.94 9978.08 202.22 52.94 40.67 266.64
13540.27 89.05 247.78 6844.09 6777.09 -919.29 -10002.06 608899.94 5978296.52 70°20'59.1883"N 149°06'57.1087"W 13.08 82.571 1.77 12.97 10009.74 202.53 53.08 40.69 266.58
13575.48 89.11 248.24 6844.66 6777.66 -932.47 -10034.71 608867.51 5978282.82 70°20'59.0582"N 149°06'58.0622"W 1.32 -88.279 0.17 1.31 10044.18 202.88 53.23 40.72 266.51
13600.66 89.17 246.26 6845.04 6778.04 -942.20 -10057.93 608844.45 5978272.72 70°20'58.9622"N 149°06'58.7403"W 7.87 -132.418 0.24 -7.86 10068.73 203.14 53.33 40.75 266.46
13630.50 88.12 245.11 6845.74 6778.74 -954.49 -10085.11 608817.47 5978260.01 70°20'58.8410"N 149°06'59.5343"W 5.22 -34.617 -3.52 -3.85 10097.64 203.44 53.46 40.77 266.41
13660.69 89.54 244.13 6846.36 6779.36 -967.42 -10112.38 608790.41 5978246.64 70°20'58.7134"N 149°07'0.3307"W 5.71 -90.321 4.70 -3.25 10126.74 203.75 53.60 40.80 266.34
13695.34 89.51 238.34 6846.65 6779.65 -984.09 -10142.74 608760.32 5978229.50 70°20'58.5491"N 149°07'1.2173"W 16.71 175.545 -0.09 -16.71 10159.53 204.10 53.79 40.84 266.27
13725.40 88.74 238.40 6847.11 6780.11 -999.85 -10168.33 608734.99 5978213.33 70°20'58.3937"N 149°07'1.9645"W 2.57 96.863 -2.56 0.20 10187.47 204.40 53.97 40.87 266.19
13755.57 88.28 242.25 6847.89 6780.89 -1014.78 -10194.53 608709.03 5978197.99 70°20'58.2466"N 149°07'2.7296"W 12.85 63.458 -1.52 12.76 10215.87 204.72 54.14 40.91 266.12
13785.39 89.48 244.65 6848.47 6781.47 -1028.11 -10221.20 608682.58 5978184.25 70°20'58.1152"N 149°07'3.5083"W 9.00 59.036 4.02 8.05 10244.44 205.04 54.30 40.94 266.06
13815.45 90.98 247.15 6848.35 6781.35 -1040.38 -10248.63 608655.34 5978171.54 70°20'57.9941"N 149°07'4.3097"W 9.70 70.807 4.99 8.32 10273.60 205.38 54.45 40.98 265.99
13845.64 92.15 250.52 6847.53 6780.53 -1051.27 -10276.77 608627.38 5978160.20 70°20'57.8866"N 149°07'5.1315"W 11.81 101.754 3.88 11.16 10303.20 205.73 54.58 41.02 265.93
13875.39 91.41 254.06 6846.60 6779.60 -1060.32 -10305.09 608599.21 5978150.71 70°20'57.7972"N 149°07'5.9588"W 12.15 78.05 -2.49 11.90 10332.66 206.09 54.69 41.06 265.87
13905.29 92.21 257.86 6845.66 6778.66 -1067.57 -10334.08 608570.34 5978143.00 70°20'57.7255"N 149°07'6.8056"W 12.98 77.805 2.68 12.71 10362.46 206.46 54.77 41.10 265.82
13935.46 92.98 261.45 6844.29 6777.29 -1072.98 -10363.73 608540.79 5978137.12 70°20'57.6719"N 149°07'7.6717"W 12.16 77.23 2.55 11.90 10392.60 206.85 54.83 41.14 265.77
13965.43 93.50 263.76 6842.60 6775.60 -1076.83 -10393.40 608511.19 5978132.80 70°20'57.6336"N 149°07'8.5386"W 7.89 74.554 1.74 7.71 10422.49 207.25 54.86 41.18 265.74
13990.28 94.15 266.13 6840.94 6773.94 -1079.01 -10418.09 608486.53 5978130.23 70°20'57.6118"N 149°07'9.2602"W 9.87 93.055 2.62 9.54 10447.19 207.58 54.87 41.22 265.71
14020.45 93.93 270.08 6838.82 6771.82 -1080.01 -10448.17 608456.48 5978128.75 70°20'57.6016"N 149°07'10.1390"W 13.08 100.372 -0.73 13.09 10476.98 207.99 54.87 41.27 265.68
14050.24 93.22 273.92 6836.96 6769.96 -1078.97 -10477.87 608426.76 5978129.32 70°20'57.6114"N 149°07'11.0072"W 13.08 -149.265 -2.38 12.89 10506.05 208.40 54.84 41.31 265.66
14080.46 92.80 273.67 6835.37 6768.37 -1076.97 -10507.99 608396.63 5978130.84 70°20'57.6306"N 149°07'11.8873"W 1.62 -83.23 -1.39 -0.83 10535.36 208.82 54.79 41.36 265.65
14110.26 93.04 271.63 6833.85 6766.85 -1075.60 -10537.71 608366.88 5978131.74 70°20'57.6438"N 149°07'12.7561"W 6.88 -109.555 0.81 -6.85 10564.40 209.25 54.75 41.41 265.63
14140.34 92.15 269.13 6832.49 6765.49 -1075.40 -10567.76 608336.84 5978131.47 70°20'57.6453"N 149°07'13.6341"W 8.81 -88.092 -2.96 -8.31 10593.95 209.68 54.73 41.46 265.61
14170.32 92.24 266.35 6831.34 6764.34 -1076.58 -10597.69 608306.93 5978129.81 70°20'57.6333"N 149°07'14.5088"W 9.27 -98.75 0.30 -9.27 10623.63 210.12 54.73 41.51 265.59
14200.40 91.90 264.15 6830.25 6763.25 -1079.07 -10627.65 608277.02 5978126.85 70°20'57.6084"N 149°07'15.3840"W 7.40 -113.08 -1.13 -7.31 10653.57 210.57 54.74 41.56 265.56
14230.36 91.35 262.86 6829.40 6762.40 -1082.46 -10657.40 608247.33 5978122.99 70°20'57.5746"N 149°07'16.2534"W 4.68 96.244 -1.84 -4.31 10683.46 211.03 54.77 41.62 265.53
14260.38 91.04 265.68 6828.78 6761.78 -1085.45 -10687.26 608217.52 5978119.52 70°20'57.5448"N 149°07'17.1259"W 9.45 87.481 -1.03 9.39 10713.39 211.49 54.79 41.67 265.49
14300.31 91.20 269.37 6828.00 6761.00 -1087.18 -10727.14 608177.68 5978117.16 70°20'57.5272"N 149°07'18.2912"W 9.25 107.399 0.40 9.24 10752.96 212.11 54.79 41.75 265.46
14330.33 90.40 271.92 6827.58 6760.58 -1086.84 -10757.15 608147.67 5978117.02 70°20'57.5301"N 149°07'19.1683"W 8.90 77.786 -2.66 8.49 10782.45 212.59 54.77 41.81 265.44
Page3of4
14360.26 91.07 275.02 6827.19 6760.19 -1085.03 -10787.02 608117.78 5978118.36 70°20'57.5475"N 149°07'20.0412"W 10.60 94.165 2.24 10.36 10811.56 213.07 54.73 41.87 265.44
14391.92 90.80 278.70 6826.68 6759.68 -1081.25 -10818.45 608086.30 5978121.64 70°20'57.5843"N 149°07'20.9597"W 11.65 86.823 -0.85 11.62 10841.85 213.58 54.66 41.93 265.44
14420.18 90.95 281.42 6826.25 6759.25 -1076.31 -10846.26 608058.41 5978126.14 70°20'57.6324"N 149°07'21.7729"W 9.64 -15.942 0.53 9.62 10868.39 214.03 54.58 41.99 265.45
14452.16 91.23 281.34 6825.64 6758.64 -1070.00 -10877.61 608026.97 5978131.95 70°20'57.6940"N 149°07'22.6892"W 0.91 -76.41 0.88 -0.25 10898.16 214.54 54.49 42.06 265.46
14484.13 91.90 278.56 6824.76 6757.76 -1064.48 -10909.08 607995.41 5978136.97 70°20'57.7479"N 149°07'23.6092"W 8.94 -59.238 2.10 -8.70 10928.20 215.07 54.41 42.13 265.47
14513.96 93.04 276.64 6823.48 6756.48 -1060.54 -10938.62 607965.82 5978140.44 70°20'57.7862"N 149°07'24.4726"W 7.48 -75.933 3.82 -6.44 10956.60 215.57 54.35 42.19 265.48
14543.64 93.62 274.31 6821.75 6754.75 -1057.71 -10968.12 607936.29 5978142.80 70°20'57.8136"N 149°07'25.3346"W 8.08 -92.989 1.95 -7.85 10985.16 216.07 54.30 42.26 265.48
14570.16 93.50 272.06 6820.11 6753.11 -1056.24 -10994.54 607909.84 5978143.85 70°20'57.8277"N 149°07'26.1069"W 8.48 -86.954 -0.45 -8.48 11010.92 216.54 54.27 42.32 265.48
14598.44 93.60 270.14 6818.36 6751.36 -1055.70 -11022.76 607881.62 5978143.94 70°20'57.8326"N 149°07'26.9316"W 6.79 -105.332 0.35 -6.79 11038.62 217.03 54.25 42.38 265.47
14630.16 92.76 267.09 6816.60 6749.60 -1056.47 -11054.42 607849.98 5978142.67 70°20'57.8246"N 149°07'27.8567"W 9.96 -55.627 -2.65 -9.62 11069.93 217.60 54.25 42.46 265.45
14660.12 93.81 265.55 6814.88 6747.88 -1058.39 -11084.27 607820.17 5978140.28 70°20'57.8053"N 149°07'28.7288"W 6.21 -57.822 3.50 -5.14 11099.66 218.14 54.25 42.53 265.43
14690.21 94.98 263.68 6812.57 6745.57 -1061.20 -11114.13 607790.36 5978136.99 70°20'57.7772"N 149°07'29.6015"W 7.32 -73.463 3.89 -6.21 11129.56 218.69 54.27 42.60 265.41
14720.30 95.60 261.57 6809.80 6742.80 -1065.05 -11143.85 607760.71 5978132.68 70°20'57.7389"N 149°07'30.4697"W 7.28 -169.945 2.06 -7.01 11159.49 219.24 54.30 42.68 265.38
14755.20 91.99 260.93 6807.49 6740.49 -1070.34 -11178.26 607726.39 5978126.84 70°20'57.6863"N 149°07'31.4751"W 10.50 -93.044 -10.34 -1.83 11194.30 219.89 54.34 42.77 265.34
14785.07 91.87 258.70 6806.48 6739.48 -1075.62 -11207.64 607697.10 5978121.09 70°20'57.6340"N 149°07'32.3334"W 7.47 0 -0.40 -7.47 11224.15 220.44 54.39 42.85 265.30
14826.00 91.87 258.70 6805.15 6738.15 -1083.64 -11247.75 607657.12 5978112.44 70°20'57.5545"N 149°07'33.5054"W 0.00 N/A 0.00 0.00 11265.05 221.21 54.46 42.95 265.25 Projection to TD
Page4of4
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 02/20/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: PBU S-126B
PTD: 224-084
API: 50-029-23363-02-00
FINAL LWD FORMATION EVALUATION LOGS (01/13/2025 to 01/31/2025)
Multiple Propagation Resistivity & Gamma Ray (2” & 5” MD/TVD Color Logs)
Pressure While Drilling (PWD)
Final Definitive Directional Surveys
SFTP Transfer - Data Main Folders:
SFTP Transfer - Data Sub-Folders:
Please include current contact information if different from above.
224-084
T40149
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.21 08:11:46 -09'00'
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU S-126B
Hilcorp Alaska, LLC
Permit to Drill Number: 224-084
Surface Location: 3171 FSL, 4565' FEL, Sec. 35, T12N, R12E, UM, AK
Bottomhole Location: 2188' FNL, 59' FWL, Sec. 33, T12N, R12E, UM, AK
DearMr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
PerStatute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCCreserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCCspecifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCCorder, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this WKday of 6HSWHPEHU 2024.
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2024.09.04
09:55:52 -08'00'
3-1/2"x3-1/4"
Drilling Manager
08/20/24
Monty M
Myers
By Grace Christianson at 2:50 pm, Aug 20, 2024
A.Dewhurst 27AUG24 DSR-8/21/24WCB 8-22-2024
50-029-23363-02-00
92.4
11:07 am, Aug 27, 2024
MGR22AUG23
224-084
*BOPE test to 3500 psi. Annular to 2500 psi.
*Variance to 20 AAC 25.112(I) approved for alternate plug
placement with fully cemented production liner.
*Approved for post-rig perforating w/perf gun BHA not to exceed 500' in length.
*1.5x wellbore volume of KWF on location during drilling.
*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.09.04 09:56:04 -08'00'
09/04/24
09/04/24
RBDMS JSB 090524
To: Alaska Oil & Gas Conservation Commission
From: Trevor Hyatt
Drilling Engineer
Date: August 19, 2024
Re: PBU S-126B Permit to Drill
Approval is requested for drilling a CTD sidetrack lateral from well PBU S-126A with the Nabors CDR2 or
CDR3 Coiled Tubing Drilling.
Proposed plan for PBU S-126A and S-126B Producer:
See S-126 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to
drift for whipstock, caliper and MIT. E-line will set a 4-1/2"x7" whipstock. Coil will mill the XN nipple and window
pre-rig. If unable to set the whipstock or milling the window, for scheduling reasons, the rig will perform that work.
A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 or CDR3 rig. The rig will move in, test BOPE
and kill the well. If unable to set whipstock pre-rig, the rig will set the 4-1/2"x7" whipstock. A single string 3.80"
window + 10'
of formation will be milled. START OF S-126A PTD - The well will kick off drilling in the Kuparuk C and land in the
Kuparuk B. The lateral will continue into the adjacent fault block to the west then turn to the south and drill into the
southern fault block to find the oil/water contact. Liner will not be ran in S-126A. START OF S-126B PTD - The rig
will then set a billet and drill a sidetrack to S-126B. This plan will be targeting the Kuparuk C sands across the two
fault blocks which will then be completed with a 3-1/2"x3-1/4"x2-7/8” L80 solid liner, cemented in place to top of
liner. The well will have a post rig single stage toe frac with 30' of post rig perforations (to be performed under
separate sundry). Future add perfs and surveillance will help us understand frac growth in the C2 interval. This
completion will completely isolate and abandon the parent Kuparuk perfs.
The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is
attached for reference.
Pre-Rig Work:
x Reference PBU S-126 Sundry submitted in concert with this request for full details.
1. SL : Drift for whipstock and caliper
2. E-line : Set Whipstock
3.Service Coil : Mill XN and Window
4. FullBore : MITxIA
5. Valve Shop : Pre-CTD Tree Work
6. Operations : Remove wellhouse and level pad.
Rig Work: (Estimated to start in October 2024)
1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,700 psi).
2. Mill 3.80” Window (if not done pre-rig).
3. Drill S-126A Build section: 4.25" OH, ~248' (26 deg DLS planned).
4. Drill S-126A Lateral section: 4.25" OH, ~3,045' (12 deg DLS planned).
5. Billet Sidetrack & Drill S-126B Lateral: 4.25" OH, ~1,770' (12 deg DLS planned).
6. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr liner
7. Pump primary cement job: 43 bbls, 15.3 ppg Class G, TOC at TOL*.
8. Close in tree, RDMO.
* Approved alternate plug placement per 20 AAC 25.112(i)
S-126 Sundry:
S-126A PTD:
S-126B PTD:
START OF S-126B PTD -
224-084
224-079
Post Rig Work:
Post-Rig Work
1Valve ShopValve & tree work
2 Slickline
Set LTP* (if necessary).
3 Service Coil
Post rig perforate (~30’) and CBL.
4FracSingle Stage Frac
5 Slickline
SBHPS & Set live GLVs.
6TestingPortable test separator flowback.
Managed Pressure Drilling:
Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole
pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface
pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying
annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or
fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of
the WC choke.
Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will
be accomplished utilizing 3” (big hole) & 2-3/8” (slim hole) pipe/slip rams (see attached BOP configurations). The
annular preventer will act as a secondary containment during deployment and not as a stripper.
Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements
while drilling and shale behavior. The following scenario is expected:
MPD Pressure at the Planned Window (11,509' MD -6,728' TVD)
Pumps On Pumps Oī
A Target BHP at Window (ppg)4,128 psi 4,128 psi
11.8
B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 691 psi 0 psi
0.06
C DƵĚ,LJĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,009 psi 3,009 psi
8.6
B+C Mud + ECD Combined 3,699 psi 3,009 psi
(no choke pressure)
A-(B+C)Choke Pressure Required to Maintain 429 psi 1,120 psi
Target BHP at window and deeper
Operation Details:
Reservoir Pressure for both S-126A and S-126B:
x The estimated reservoir pressure is expected to be 3,374 psi at 6,700 TVDSS. (9.7 ppg equivalent).
x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,700 psi (from estimated
reservoir pressure).
Mud Program:
x Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain
constant BHP.
Disposal:
x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4.
x Fluids >1% hydrocarbons or flammables must go to GNI.
x Fluids >15% solids by volume must go to GNI.
x Fluids with solids that will not pass through 1/4” screen must go to GNI.
x Fluids with PH >11 must go to GNI.
Hole Size:
x 4.25" hole for the entirety of the production hole section.
Liner Program for S-126A:
x No liner will be run.
x Anchored billet will be set and the well will be sidetracked to S-126B.
Liner Program for S-126B:
x 3-1/2", 9.3#, L80 Solid: 11,290' MD – 11,490' MD (200' liner)
x 3-1/4", 6.6#, L80 Solid: 11,490' MD – 11,900' MD (410' liner)
x 2-7/8", 6.5#, L80 Solid: 11,900' MD – 14,680' MD (2,780' liner)
x The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary.
x A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole.
Well Control:
x BOP diagram is attached. MPD and pressure deployment is planned.
x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi.
x The annular preventer will be tested to 250 psi and 2,500 psi.
x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations.
x Solid 2-7/8” Liner Running Ram Change: Change out 3” pipe/slip rams (for drilling) to 2-3/8” x 3-1/2” VBR
rams for liner run. Test VBR rams to 250 psi and 3,500 psi.
x A X-over shall be made up to a 2 3/8" safety joint including a TIW valve for all tubulars ran in hole.
x 2 3/8" safety joint will be utilized while running solid or slotted liner. The desire is to keep the same
standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint
with pre-installed TIW valve). When closing on a 2 3/8" safety joint, 2 sets of pipe/slip rams will be
available, above and below the flow cross providing better well control option.
Directional:
x Directional plan attached. Maximum planned hole angle is 108°. Inclination at kick off point is 30°.
x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
x Distance to nearest property line – 8950 ft (S-126A), 8800ft (S-126B)
x Distance to nearest well within pool – 1580 ft (S-126A and S-126B)
Logging:
x MWD directional, Gamma Ray and Resistivity will be run through the entire open hole section.
x Real time bore pressure to aid in MPD and ECD management.
Perforating plan for S-126A:
x Will not be completed or perforated.
Perforating plan for S-126B:
x <500' perforated post rig – See attached extended perforating procedure. If interval is 30-60’, perf guns
will be lubricated.
x 2.0" Perf Guns at 6 spf
x If post rig extended perforating with service coil is not an option, the well will be perforated with the rig or
post rig under this PTD.
x The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely
in the Kuparuk C pool.
x Formations: Top of Kuparuk at 11,473’ MD in the parent.
Anti-Collision Failures:
x Anti-Collision Summary – All wells pass AC
Hazards:
x S Pad is an H2S pad. No H2S readings on PBU S-126 being an injector.
x Max H2S recorded on S Pad: 500 ppm (S-201 in 2005).
x 4 fault crossings expected.
x Medium lost circulation risk.
Trevor Hyatt CC: Well File
Drilling Engineer Joseph Lastufka
(907-223-3087)
Post-Rig Service Coil Perforating Procedure:
Coiled Tubing
Notes:
x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS
coverage is required.
x Note: The well will be killed and monitored before making up the initial perfs guns. This will provide
guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the
job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH
or circulating bottoms up through the same port that opened to shear the firing head.
Coil Tubing
1. MIRU Coiled Tubing Unit and spot ancillary equipment.
2.MU nozzle drift BHA (include SCMT and/or RPM log as needed).
3. RIH to PBTD.
a.Displace well with weighted brine while RIH (minimum 10.0 ppg to be overbalanced).
4. POOH (and RPM log if needed) and lay down BHA.
5. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through
the brass upon POOH with guns.
6.There will be no perforations to bullhead kill the well. Well will already be loaded w/ weighted brine or KCl
per previous steps. Re-load well at WSS discretion.
7.At surface, prepare for deployment of TCP guns.
8.Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, weighted brine as needed
(minimum 10.0 ppg). Maintain continuous hole fill taking returns to tank until lubricator connection is
reestablished. Fluids man-watch must be performed while deploying perf guns to ensure the well
remains killed and there is no excess flow.
9.Pickup safety joint and TIW valve and space out before MU guns.Review well control steps with crew
prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint
and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working
platform for quick deployment if necessary.
10.Break lubricator connection at QTS and begin makeup of TCP guns and blanks per schedule below.Max
BHA length per PTD is 500ft. Fluids man-watch must be performed while deploying perf guns to ensure
the well remains killed and there is no excess flow.
a. Perforation details
i.Perf Interval:The well will be perforated between the CTD whipstock and TD of the
newly drilled CTD well, completely in the Kuparuk pool.
ii.Perf Length:500’
iii.Gun Length:500’
iv.Weight of Guns (lbs):2300lbs (4.6ppf)
11. MU lubricator and RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate perforation
intervals (TBD). POOH.
a.Note any tubing pressure change in WSR.
12.After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and
stick the BHA.Confirm well is dead and re-kill if necessary before pulling to surface.
13. Pump pipe displacement while POOH.Stop at surface to reconfirm well dead and hole full.
14. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of
TCP gun string. Standing orders flow chart included with this sundry request. Ensure safety joint and TIW
valve assembly are on-hand before breaking off lubricator to LD gun BHA.
15.Freeze protect well to 2,000’ TVD.
16.RDMO CTU.
Coiled Tubing BOPs
Standing Orders for Open Hole Well Control during Perf Gun Deployment
Equipment Layout Diagram
Well Date
Quick Test Sub to Otis -1.1 ft
Top of 7" Otis 0.0 ft
Distances from top of riser
Excluding quick-test sub
Top of Annular 2.75 ft
C L Annular 3.40 ft
Bottom Annular 4.75 ft
CL Blind/Shears 6.09 ft
CL 2.0" Pipe / Slips 6.95 ft B3 B4
B1 B2
Kill Line Choke Line
CL 2-3/8" Pipe / Slip 9.54 ft
CL 2.0" Pipe / Slips 10.40 ft
TV1 TV2
T1 T2
Flow Tee
Master
Master
LDS
IA
OA
LDS
Ground Level
3" LP hose open ended to Flowline
CDR2-AC BOP Schematic
CDR2 Rig's Drip Pan
Fill Line from HF2
Normally Disconnected
3" HP hose to Micromotion
Hydril 7 1/16"
Annular
Blind/Shear
2-3/8" Pipe/Slips
2 3/8" Pipe/Slips
2 3/8" Pipe/Slips
7-1/16"
5k Mud
Cross
2-3/8" Pipe/Slips
3.0" Pipe / Slip
HF
nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee
Well Date
Quick Test Sub to Otis
Top of 7" Otis
Top of Annular
C L Annular
Bottom Annular
CL Blind/Shears
CL 2-3/8" Pipe / Slips B6 B5
B8 B7
Choke Line Kill Line
CL 3" Pipe / Slip
CL 2-3/8" Pipe / Slips
TV1 TV2
T1 T2
Flow Tee
Master
Master
LDS
IA
OA
LDS
Ground Level
CDR3-AC BOP Schematic
CDR3 Rig's Drip Pan
Fill Line
Normally Disconnected
2" HP hose to Micromotion
Hydril 7 1/16"
Annular
Blind/Shear
2-3/8" Pipe/Slips
2 3/8" Pipe/Slips
2 3/8" Pipe/Slips
7-1/16"
5k Mud
Cross
2-3/8" Pipe/Slips
3" Pipe / Slip
neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee
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M-05A
NKUPST
S-01
S-01A S-01B
S-01C
S-02
S-02A
S-03
S-04
S-08
S-08A
S-08B
S-09
S-09A
S-10
S-100
S-101
S-103
S-104
S-105
S-105A
S-108
S-10A
S-113
S-113A
S-113B
S-114
S-114A
S-115
S-116
S-116A
S-117
S-118
S-120
S-125
S-126
S-128
S-129
S-129A
S-134
S-135
S-13A
S-16
S-17
S-17A
S-17B
S-17C
S-18
S-18A
S-18B
S-19
S-20
S-200
S-201
S-201A
S-202
S-202L3
S-202L4
S-20A
S-21
S-210
S-213
S-213A
S-213AL3
S-215
S-216
S-217
S-218
S-22
S-22A
S-22B
S-23
S-24A
S-24B
S-25
S-26
S-27
S-27A
S-27B
S-28S-28AS-28B
S-29
S-29A
S-31
S-31A
S-33
S-34
S-35
S-36
S-400
S-400A
S-401
S-42
S-42A
S-44
S-44A
S-504
TW-C
V-200
W-202
W-204
W-220
W-221
Prudhoe
Bay Unit
Sec. 21
Sec. 35
Sec. 29 Sec. 27
Sec. 32
Sec. 5
Sec. 26
Sec. 22
Sec. 28
Sec. 23
Sec. 8 Sec. 9 Sec. 10
Sec. 2
Sec. 33 Sec. 34
Sec. 11
Sec. 3Sec. 4
U012N012E
U011N012E
S PAD
ADL28259
ADL28258
ADL28261
ADL47450
ADL28255 ADL47448
ADL28260
ADL28256
ADL28257
_S-126A_SHL
_S-126A_TPH
_S-126A_BHL
Map Date: 5/29/2024
Prudhoe Bay Unit
S-126B Well
wp09 E0 1,200 2,400
Feet
Legend
$)_S-126A_BHL
!_S-126A_SHL
D _S-126A_TPH
$)Other Bottom Holes (BHL)
Other Well Paths
Oil and Gas Unit Boundary
Pad Footprint
Aurora PA
Aurora CO 457B
Aurora AIO 22F
Document Path: O:\AWS\GIS\Products\Alaska\NS\Wells\TRS_Distance\mxds\2024\NorthSlope_PBU_S-126A_wp09.mxd
-2000-1500-1000-50005001000South(-)/North(+) (1000 usft/in)-11500
-11000
-10500
-10000
-9500
-9000
-8500
-8000
West(-)/East(+) (1000 usft/in)56006000640068007076S-12668006926S-126A wp086845S-126B wp09Top of Billet - 12910'MDTD - 14680'MD67506800685069006950True Vertical Depth (100 usft/in)8200
8400
8600
8800
9000
9200
9400
9600
9800
10000
10200
10400
10600
10800
11000
11200
11400
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12000
Vertical Section at 260.00° (400 usft/in)S-126S-126A wp08S-126B wp09Top of Billet - 12910'MDTD - 14680'MDSecMD Inc AziTVD+N/-S+E/-W Dleg TFaceVSect1 12910.00 88.24 208.55 6826.06 -469.45 -9637.36 0.00 0.00 9572.472 12980.00 88.26 216.95 6828.19 -528.24 -9675.18 12.00 90.00 9619.923 13200.00 88.44 243.36 6834.63 -667.89 -9842.53 12.00 90.00 9808.984 13400.00 88.58 219.35 6839.90 -791.82 -9997.55 12.00 -90.00 9983.165 13810.00 90.21 268.53 6844.53 -966.41 -10354.65 12.00 88.50 10365.156 13910.00 89.89 256.54 6844.45 -979.38 -10453.62 12.00 -91.50 10464.877 14150.00 89.90 285.34 6844.89 -975.50 -10691.07 12.00 90.00 10698.048 14410.00 90.18 254.14 6844.70 -976.69 -10947.86 12.00 -89.50 10951.149 14680.00 89.61 286.53 6845.21 -975.13 -11214.28 12.00 91.00 11213.23Project: Prudhoe BaySite: SWell: S-126Wellbore: Plan: S-126BPlan: S-126B wp09WELLBORE DETAILSParent Wellbore:Plan: S-126ATop of Window: 12910.00S-126B wp09Depth From Depth To Survey/Plan Tool100.00 700.10 S-126 Srvy 1 GYD CT DMS (S-126) 3_Gyro-CT_Drill pipe760.46 11509.00 S-126 Srvy 2 MWD+IFR+MS (S-126) 3_MWD (BP MWD+IFR+MS-WOCA)11509.00 12910.00 S-126A wp08 (Plan: S-126A) 3_MWD12910.00 14680.00 S-126B wp09 (Plan: S-126B) 3_MWDWELL DETAILSNorthing: 5979374.30Easting: 618885.30Lattitude: 70° 21' 8.2950 NLongitude: 149° 2' 4.8101 WS-126B wp09SECTION DETAILSHilcorp Alaska, LLCSURVEY PROGRAMNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04PROJECT DETAILSREFERENCE INFORMATIONCoordinate(N/E) Reference: Well S-126, True NorthVertical (TVD) Reference: KB @ 67.00usft (ORIG KELLY BUSHING)Measured Depth Reference: KB @ 67.00usft (ORIG KELLY BUSHING)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureREFERENCE INFORMATION
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Planned S-126A TD - 14,802' MD
Planned billet at 12,910' MD
Open Hole - no liner (S-126A)
B
02
B
11,490'11,490'
3-1/2"x3-1/4"
Drilling Manager
06/10/24
Monty M
Myers
11509
92
By Grace Christianson at 12:08 pm, Aug 02, 2024
* 1.5x wellbore volume of KWF on-site during lateral drilling/completing.
* BOPE test to 3500 psi. Annular to 2500 psi.
* Variance to 20 AAC 25.112(i) approved for alternate plug placement
with fully cemented liner on upcoming sidetrack.
461&34&%&%
3-1/2"x3-1/4"
Drilling Manager
06/10/24
Monty M
Myers
By Grace Christianson at 8:47 am, Jun 11, 2024
50-029-23363-02-00224-084
DSR-6/11/24
Superseded
To: Alaska Oil & Gas Conservation Commission
From: Trevor Hyatt
Drilling Engineer
Date: June 10, 2024
Re: PBU S-126B Permit to Drill
Approval is requested for drilling a CTD sidetrack lateral from well PBU S-126A with the Nabors CDR2
Coiled Tubing Drilling.
Proposed plan for PBU S-126A and S-126B Producer:
See S-126 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to
drift for whipstock, caliper and MIT. E-line will set a 4-1/2"x7" whipstock. Coil will mill the XN nipple and window
pre-rig. If unable to set the whipstock or milling the window, for scheduling reasons, the rig will perform that work.
A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the
well. If unable to set whipstock pre-rig, the rig will set the 4-1/2"x7" whipstock. A single string 3.80" window + 10'
of formation will be milled. The well will kick off drilling in the Kuparuk C and land in the Kuparuk B. The lateral
will continue into the adjacent fault block to the west then turn to the south and drill into the southern fault block to
find the oil/water contact. The rig will then set a billet and drill a sidetrack (to S-126B). This plan will be targeting
the Kuparuk C sands across the two fault blocks which will then be completed with a 3-1/2"x3-1/4"x2-7/8” L80
solid liner, cemented in place to top of liner. The well will have a post rig single stage toe frac with 30' of post rig
perforations (to be performed under separate sundry). Future add perfs and surveillance will help us understand
frac growth in the C2 interval. This completion will completely isolate and abandon the parent Kuparuk perfs.
The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is
attached for reference.
Pre-Rig Work:
x Reference PBU S-126 Sundry submitted in concert with this request for full details.
1. SL : Drift for whipstock and caliper
2. E-line : Set Whipstock
3. Service Coil : Mill XN and Window
4. FullBore : MITxIA
5. Valve Shop : Pre-CTD Tree Work
6. Operations : Remove wellhouse and level pad.
Rig Work: (Estimated to start in October 2024)
1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,700 psi).
2. Mill 3.80” Window (if not done pre-rig).
3. Drill A Build section: 4.25" OH, ~248' (26 deg DLS planned).
4. Drill A Lateral section: 4.25" OH, ~3,045' (12 deg DLS planned).
5. Billet Sidetrack & Drill B Lateral: 4.25" OH, ~1,770' (12 deg DLS planned).
6. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr liner
7. Pump primary cement job: 43 bbls, 15.3 ppg Class G, TOC at TOL*.
8. Close in tree, RDMO.
* Approved alternate plug placement per 20 AAC 25.112(i)
Post Rig Work:
Post-Rig Work
1Valve ShopValve & tree work
2 Slickline
Set LTP* (if necessary).
3 Service Coil
Post rig perforate (~30’) and CBL.
4FracSingle Stage Frac
5 Slickline
SBHPS & Set live GLVs.
6TestingPortable test separator flowback.
Managed Pressure Drilling:
Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole
pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface
pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying
annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or
fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of
the WC choke.
Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will
be accomplished utilizing 3” (big hole) & 2-3/8” (slim hole) pipe/slip rams (see attached BOP configurations). The
annular preventer will act as a secondary containment during deployment and not as a stripper.
Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements
while drilling and shale behavior. The following scenario is expected:
MPD Pressure at the Planned Window (11,509' MD -6,728' TVD)
Pumps On Pumps Oī
A Target BHP at Window (ppg)4,128 psi 4,128 psi
11.8
B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 691 psi 0 psi
0.06
C DƵĚ,LJĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,009 psi 3,009 psi
8.6
B+C Mud + ECD Combined 3,699 psi 3,009 psi
(no choke pressure)
A-(B+C)Choke Pressure Required to Maintain 429 psi 1,120 psi
Target BHP at window and deeper
Operation Details:
Reservoir Pressure:
x The estimated reservoir pressure is expected to be 3,374 psi at 6,700 TVDSS. (9.7 ppg equivalent).
x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,700 psi (from estimated
reservoir pressure).
Mud Program:
x Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain
constant BHP.
Disposal:
x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4.
x Fluids >1% hydrocarbons or flammables must go to GNI.
x Fluids >15% solids by volume must go to GNI.
x Fluids with solids that will not pass through 1/4” screen must go to GNI.
x Fluids with PH >11 must go to GNI.
Hole Size:
x 4.25" hole for the entirety of the production hole section.
Liner Program for S-126B:
x 3-1/2", 9.3#, L80 Solid: 11,290' MD – 11,490' MD (200' liner)
x 3-1/4", 6.6#, L80 Solid: 11,490' MD – 11,900' MD (410' liner)
x 2-7/8", 6.5#, L80 Solid: 11,900' MD – 14,680' MD (2,780' liner)
x The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary.
x A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole.
Well Control:
x BOP diagram is attached. MPD and pressure deployment is planned.
x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi.
x The annular preventer will be tested to 250 psi and 2,500 psi.
x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations.
x Solid 2-7/8” Liner Running Ram Change: Change out 3” pipe/slip rams (for drilling) to 2-3/8” x 3-1/2” VBR
rams for liner run. Test VBR rams to 250 psi and 3,500 psi.
x A X-over shall be made up to a 2 3/8" safety joint including a TIW valve for all tubulars ran in hole.
x 2 3/8" safety joint will be utilized while running solid or slotted liner. The desire is to keep the same
standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint
with pre-installed TIW valve). When closing on a 2 3/8" safety joint, 2 sets of pipe/slip rams will be
available, above and below the flow cross providing better well control option.
Directional:
x Directional plan attached. Maximum planned hole angle is 90°. Inclination at kick off point is 30°.
x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
x Distance to nearest property line – 8950 ft (A), 8800ft (B)
x Distance to nearest well within pool – 1580 ft (A and B)
Logging:
x MWD directional, Gamma Ray and Resistivity will be run through the entire open hole section.
x Real time bore pressure to aid in MPD and ECD management.
Perforating:
x <500' perforated post rig – See attached extended perforating procedure. If interval is 30-60’, perf guns
will be lubricated.
x 2.0" Perf Guns at 6 spf
x If post rig extended perforating with service coil is not an option, the well will be perforated with the rig or
post rig under this PTD.
x The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely
in the Kuparuk C pool.
x Formations: Top of Kuparuk at 11,473’ MD in the parent.
Anti-Collision Failures:
x Anti-Collision Summary – All wells pass AC
Hazards:
x S Pad is an H2S pad. No H2S readings on PBU S-126 being an injector.
x Max H2S recorded on S Pad: 500 ppm (S-201 in 2005).
x 4 fault crossings expected.
x Medium lost circulation risk.
Trevor Hyatt CC: Well File
Drilling Engineer Joseph Lastufka
(907-223-3087)
Post-Rig Service Coil Perforating Procedure:
Coiled Tubing
Notes:
x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS
coverage is required.
x Note: The well will be killed and monitored before making up the initial perfs guns. This will provide
guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the
job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH
or circulating bottoms up through the same port that opened to shear the firing head.
Coil Tubing
1. MIRU Coiled Tubing Unit and spot ancillary equipment.
2. MU nozzle drift BHA (include SCMT and/or RPM log as needed).
3. RIH to PBTD.
a. Displace well with weighted brine while RIH (minimum 10.0 ppg to be overbalanced).
4. POOH (and RPM log if needed) and lay down BHA.
5. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through
the brass upon POOH with guns.
6. There will be no perforations to bullhead kill the well. Well will already be loaded w/ weighted brine or KCl
per previous steps. Re-load well at WSS discretion.
7. At surface, prepare for deployment of TCP guns.
8.Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, weighted brine as needed
(minimum 10.0 ppg). Maintain continuous hole fill taking returns to tank until lubricator connection is
reestablished. Fluids man-watch must be performed while deploying perf guns to ensure the well
remains killed and there is no excess flow.
9.Pickup safety joint and TIW valve and space out before MU guns.Review well control steps with crew
prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint
and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working
platform for quick deployment if necessary.
10. Break lubricator connection at QTS and begin makeup of TCP guns and blanks per schedule below.Max
BHA length per PTD is 500ft. Fluids man-watch must be performed while deploying perf guns to ensure
the well remains killed and there is no excess flow.
a. Perforation details
i.Perf Interval:The well will be perforated between the CTD whipstock and TD of the
newly drilled CTD well, completely in the Kuparuk pool.
ii.Perf Length:500’
iii.Gun Length:500’
iv.Weight of Guns (lbs):2300lbs (4.6ppf)
11. MU lubricator and RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate perforation
intervals (TBD). POOH.
a. Note any tubing pressure change in WSR.
12. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and
stick the BHA.Confirm well is dead and re-kill if necessary before pulling to surface.
13. Pump pipe displacement while POOH.Stop at surface to reconfirm well dead and hole full.
14. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of
TCP gun string. Standing orders flow chart included with this sundry request. Ensure safety joint and TIW
valve assembly are on-hand before breaking off lubricator to LD gun BHA.
15. Freeze protect well to 2,000’ TVD.
16. RDMO CTU.
Coiled Tubing BOPs
Standing Orders for Open Hole Well Control during Perf Gun Deployment
Equipment Layout Diagram
Well Date
Quick Test Sub to Otis -1.1 ft
Top of 7" Otis 0.0 ft
Distances from top of riser
Excluding quick-test sub
Top of Annular 2.75 ft
C L Annular 3.40 ft
Bottom Annular 4.75 ft
CL Blind/Shears 6.09 ft
CL 2.0" Pipe / Slips 6.95 ft B3 B4
B1 B2
Kill Line Choke Line
CL 2-3/8" Pipe / Slip 9.54 ft
CL 2.0" Pipe / Slips 10.40 ft
TV1 TV2
T1 T2
Flow Tee
Master
Master
LDS
IA
OA
LDS
Ground Level
3" LP hose open ended to Flowline
CDR2-AC BOP Schematic
CDR2 Rig's Drip Pan
Fill Line from HF2
Normally Disconnected
3" HP hose to Micromotion
Hydril 7 1/16"
Annular
Blind/Shear
2-3/8" Pipe/Slips
2 3/8" Pipe/Slips
2 3/8" Pipe/Slips
7-1/16"
5k Mud
Cross
2-3/8" Pipe/Slips
3.0" Pipe / Slip
HF
nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee
Planned PB1 - 14,802' MD
Planned billet at 12,910' MD
Open Hole (S-126A)
B
02
B
B
Superseded
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M-05A
NKUPST
S-01
S-01A S-01B
S-01C
S-02
S-02A
S-03
S-04
S-08
S-08A
S-08B
S-09
S-09A
S-10
S-100
S-101
S-103
S-104
S-105
S-105A
S-108
S-10A
S-113
S-113A
S-113B
S-114
S-114A
S-115
S-116
S-116A
S-117
S-118
S-120
S-125
S-126
S-128
S-129
S-129A
S-134
S-135
S-13A
S-16
S-17
S-17A
S-17B
S-17C
S-18
S-18A
S-18B
S-19
S-20
S-200
S-201
S-201A
S-202
S-202L3
S-202L4
S-20A
S-21
S-210
S-213
S-213A
S-213AL3
S-215
S-216
S-217
S-218
S-22
S-22A
S-22B
S-23
S-24A
S-24B
S-25
S-26
S-27
S-27A
S-27B
S-28S-28AS-28B
S-29
S-29A
S-31
S-31A
S-33
S-34
S-35
S-36
S-400
S-400A
S-401
S-42
S-42A
S-44
S-44A
S-504
TW-C
V-200
W-202
W-204
W-220
W-221
Prudhoe
Bay Unit
Sec. 21
Sec. 35
Sec. 29 Sec. 27
Sec. 32
Sec. 5
Sec. 26
Sec. 22
Sec. 28
Sec. 23
Sec. 8 Sec. 9 Sec. 10
Sec. 2
Sec. 33 Sec. 34
Sec. 11
Sec. 3Sec. 4
U012N012E
U011N012E
S PAD
ADL28259
ADL28258
ADL28261
ADL47450
ADL28255 ADL47448
ADL28260
ADL28256
ADL28257
_S-126A_SHL
_S-126A_TPH
_S-126A_BHL
Map Date: 5/29/2024
Prudhoe Bay Unit
S-126B Well
wp09 E0 1,200 2,400
Feet
Legend
$)_S-126A_BHL
!_S-126A_SHL
D _S-126A_TPH
$)Other Bottom Holes (BHL)
Other Well Paths
Oil and Gas Unit Boundary
Pad Footprint
Aurora PA
Aurora CO 457B
Aurora AIO 22F
Document Path: O:\AWS\GIS\Products\Alaska\NS\Wells\TRS_Distance\mxds\2024\NorthSlope_PBU_S-126A_wp09.mxd
-2000-1500-1000-50005001000South(-)/North(+) (1000 usft/in)-11500
-11000
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-10000
-9500
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-8500
-8000
West(-)/East(+) (1000 usft/in)56006000640068007076S-12668006926S-126A wp086845S-126B wp09Top of Billet - 12910'MDTD - 14680'MD67506800685069006950True Vertical Depth (100 usft/in)8200
8400
8600
8800
9000
9200
9400
9600
9800
10000
10200
10400
10600
10800
11000
11200
11400
11600
11800
12000
Vertical Section at 260.00° (400 usft/in)S-126S-126A wp08S-126B wp09Top of Billet - 12910'MDTD - 14680'MDSecMD Inc AziTVD+N/-S+E/-W Dleg TFaceVSect1 12910.00 88.24 208.55 6826.06 -469.45 -9637.36 0.00 0.00 9572.472 12980.00 88.26 216.95 6828.19 -528.24 -9675.18 12.00 90.00 9619.923 13200.00 88.44 243.36 6834.63 -667.89 -9842.53 12.00 90.00 9808.984 13400.00 88.58 219.35 6839.90 -791.82 -9997.55 12.00 -90.00 9983.165 13810.00 90.21 268.53 6844.53 -966.41 -10354.65 12.00 88.50 10365.156 13910.00 89.89 256.54 6844.45 -979.38 -10453.62 12.00 -91.50 10464.877 14150.00 89.90 285.34 6844.89 -975.50 -10691.07 12.00 90.00 10698.048 14410.00 90.18 254.14 6844.70 -976.69 -10947.86 12.00 -89.50 10951.149 14680.00 89.61 286.53 6845.21 -975.13 -11214.28 12.00 91.00 11213.23Project: Prudhoe BaySite: SWell: S-126Wellbore: Plan: S-126BPlan: S-126B wp09WELLBORE DETAILSParent Wellbore:Plan: S-126ATop of Window: 12910.00S-126B wp09Depth From Depth To Survey/Plan Tool100.00 700.10 S-126 Srvy 1 GYD CT DMS (S-126) 3_Gyro-CT_Drill pipe760.46 11509.00 S-126 Srvy 2 MWD+IFR+MS (S-126) 3_MWD (BP MWD+IFR+MS-WOCA)11509.00 12910.00 S-126A wp08 (Plan: S-126A) 3_MWD12910.00 14680.00 S-126B wp09 (Plan: S-126B) 3_MWDWELL DETAILSNorthing: 5979374.30Easting: 618885.30Lattitude: 70° 21' 8.2950 NLongitude: 149° 2' 4.8101 WS-126B wp09SECTION DETAILSHilcorp Alaska, LLCSURVEY PROGRAMNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04PROJECT DETAILSREFERENCE INFORMATIONCoordinate(N/E) Reference: Well S-126, True NorthVertical (TVD) Reference: KB @ 67.00usft (ORIG KELLY BUSHING)Measured Depth Reference: KB @ 67.00usft (ORIG KELLY BUSHING)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureREFERENCE INFORMATION
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1
Dewhurst, Andrew D (OGC)
From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent:Tuesday, 27 August, 2024 13:27
To:Dewhurst, Andrew D (OGC)
Cc:Trevor Hyatt; Boman, Wade C (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] PBU S-126A (PTD 224-079) and S-126B (224-084): Questions
Correct. Sorry, I missed that! I got confused when you already gave me the right answer!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Tuesday, August 27, 2024 1:18 PM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Trevor Hyatt <Trevor.Hyatt@hilcorp.com>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] PBU S-126A (PTD 224-079) and S-126B (224-084): Questions
Joe,
Thanks. S-126A has ADL 025257 listed on the 10-401, so just wanted to conĮrm the correcƟon:
Andy
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Tuesday, 27 August, 2024 13:09
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Cc: Trevor Hyatt <Trevor.Hyatt@hilcorp.com>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] PBU S-126A (PTD 224-079) and S-126B (224-084): Questions
Andy,
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
2
I show Sections 25, 26, 35 & 36 T12N R12E as being in lease # ADL 028257 (Surface Location), and Sections 21, 22,
33 & 34 T12N, R12E as being in lease # ADL 028258 (TPH and TD Locations). If I have these sections, townships or
ranges incorrect or am using an incorrect lease number please don’t hesitate to correct me.
Currently, the well is on our CDR2 schedule, but these CTD wells frequently change on our schedule and having
the Permit to Drill be approved for either one gives us optimal Ʋexibility especially with the same BOP
conƱguration.
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Tuesday, August 27, 2024 11:45 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Trevor Hyatt <Trevor.Hyatt@hilcorp.com>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: [EXTERNAL] PBU S-126A (PTD 224-079) and S-126B (224-084): Questions
Joe,
Two quick quesƟons:
x Would you conĮrm that the correct leases for S-126A are the following: ADL028257 and ADL028258?
x Has the rig selecƟon been Įnalized [between CDR2 or CDR3]?
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas ConservaƟon Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
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3
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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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.
PBU S-126B
PRUDHOE BAY
224-084
AURORA OIL
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN AURO S-126BInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240840PRUDHOE BAY, AURORA OIL - 640120NA1Permit fee attachedYesADL028257 and ADL0282582Lease number appropriateYes3Unique well name and numberYesPRUDHOE BAY, AURORA OIL - 640120 - governed by CO 457B4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NAThis well ia an in-zone CTD sidetrack from an existing wellbore with pressure integrity.18Conductor string providedNAAll drilling on this sidetrack will be below the existing SC shoe.19Surface casing protects all known USDWsNAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.20CMT vol adequate to circulate on conductor & surf csgNAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.21CMT vol adequate to tie-in long string to surf csgYesFully cemented production liner. Parent well isolates the wellbore.22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesCDR2 has adequate tankage and good trucking support.24Adequate tankage or reserve pitYesSundry 324-32025If a re-drill, has a 10-403 for abandonment been approvedYesNo wells with SF <1.26Adequate wellbore separation proposedNAAll drilling will be below the SC shoe.27If diverter required, does it meet regulationsYesMPD w/8.4ppg mud, and res press of 9.7ppg. 1.5x wellbore vol KWF to be on-site.28Drilling fluid program schematic & equip list adequateYesCT packoff, flow cross, annular, blind/shear, CT pipe slips, flow cross, BHA pipe slips, CT pipe slips29BOPEs, do they meet regulationYes7-1/16" 5000 psi stack, pressure tested to 3500 psi.30BOPE press rating appropriate; test to (put psig in comments)YesFlanged choke and kill lines between dual combis w/remote choke.31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesPrudhoe's S-Pad is an H2S pad, with max reading of 500 ppm. Monitoring will be conducted.33Is presence of H2S gas probableNAThis is a development well.34Mechanical condition of wells within AOR verified (For service well only)NoPBU S-Pad wells are H2S-bearing; measures required. Max reading 500 ppm from S-201 (2005)35Permit can be issued w/o hydrogen sulfide measuresYesPore pressure anticipated to be 9.7 ppg EMW. MPD to be employed. Four fault crossings expected.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate8/27/2024ApprDateApprADDDate8/27/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&: :&% JLC 9/4/2024
