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Alaska Oil and Gas Conservation Commission
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From:Conwell, Russell (Russell)
To:McLellan, Bryan J (OGC)
Cc:Tirpack, Robert (Robert); Leahy, Scott (Scott)
Subject:NDB-039 (PTD 225-144) Cement Job Results
Date:Sunday, February 8, 2026 7:09:09 AM
Attachments:Oil_Search_Alaska_LLC_Pikka_NDB_039_R4_7in_Liner_SonicScope475_ReamDown_RM_TOC_PPT_TZD.pdf
PIKKA NBD-039_TOC-RM_4000_Labeled.Pdf
NDB-039 Wellview Cement Summary Report.pdf
NDB-039 Schematic Tier 3 (As Drilled).pdf
Hi Bryan,
Attached is the final 7” INT2 Liner Sonic CBL report from SLB, Sonic CBL Log, Wellview Cementing
Reports, and As-Built schematic (draft). Below is a high-level summary:
Well Design and Geology
9-5/8” Intermediate 1 Liner:
9-5/8” Liner Top at 2,729’ MD
13-3/8” Casing Shoe at 2,883 MD
Tuluvak Sand Top at 3,219’ MD
TS790 at 5,683’ MD
CFLEX Stage Tool at 5,775’ MD
9-5/8” Shoe at 11,497’ MD
7” Intermediate 2 Liner:
7” Liner Top at 11,330’ MD
Top of the Nanushuk at 14,743’ MD / 3,807’ TVD
7” Shoe at 15,745’ MD
Cement Job Planning / Execution
9-5/8” INT1 Liner 1st Stage Cement Job:
1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting 1,000’
MD above 9-5/8” shoe to ~10,497’ MD. This cement job is not isolating any permeable or
hydrocarbon zones.
102 bbls losses while RIH with the liner and ~50% losses during the 1st stage cement job. Total
423 bbls losses cementing with ~42 bbls after cement exited the shoe (~33 psi lift pressure
noted).
More details on the cement job can be referenced in the Wellview Cementing report.
A good FIT to 14.0ppg was achieved at the 9-5/8” shoe.
Indications of a successful 1st stage job.
nd
9-5/8” INT1 Liner 2 Stage Cement Job:
2nd Stage of cement job with CFLEX ~92’ below the TS790. Planned with a full 14.5 ppg tail
slurry at 100% excess, targeting TOC at the 9-5/8” liner top. This cement job is isolating the
hydrocarbon zone within the upper Tuluvak formation.
Opened the CFLEX stage tool at ~5,775’ MD and established circulation up to 8 bpm with no
losses. Pumped the 2nd stage cement job with full returns and good lift pressure. Closed the
CFLEX and set the LTP, then circulated ~100 bbls clean cement back to surface.
More details on the cement job can be referenced in the Wellview Cementing report.
All indications of a successful 2nd stage cement job. Lighter weight 14.5ppg cement seemed
to help reduce ECDs resulting in no losses.
7” INT2 Liner Cement Job
1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting 200’
TVD above Top Nanushuk to ~13,400’ MD. Additionally, this well was planned with 196 bbl
LVT spacer (increased volume after losses) to be pumped ahead of the cement spacer to
further lower cementing ECD. This cement job is isolating hydrocarbons in the Upper
Nanushuk.
Losses were encountered when circulating the liner on bottom (223 bbls) and during the
cement job (403 bbls). ~130 bbls were lost after cement exited the shoe but good lift
pressures were seen (~320 psi).
More details on the cement job can be referenced in the Wellview Cementing report.
A FIT of 14.2ppg was achieved at the 7” shoe. A SLB Sonic CBL was run on the 6-1/8” drilling
BHA – results are discussed below and report is attached.
Observations / Conclusions
9-5/8” Intermediate 1 Liner:
For the 1st stage of the cement job, based on job execution results, cement isolation was
achieved across the 9-5/8” shoe.
For the 2nd stage of the cement job, based on job execution results, cement isolation was
achieved across the hydrocarbon zone within the upper Tuluvak formation.
7” Intermediate 2 Liner:
The SLB Sonic TOC Log indicates there is Decent cement coverage up to roughly the top
Nanushuk with partial cement above the top Nanushuk. Summary as follows:
Poor to Fair Cement from 14,118' MD - 14,749' MD
Decent to Good cement from 14,749' MD – 14870’ MD
Good cement from 14,780’ MD to bottom
Top of Nanushuk is 14,743’ MD / 3,807’ TVD
Based on the above assessment, Santos believes that we meet the requirements of 20 AAC
25.030(d)(5)(B). Our plan will be to proceed as per the approved PTD.
Please let me know if you have any questions or concerns.
Regards
Russell
Russell Conwell
Senior Drilling Engineer
m: +1 907 615 2234| e: russell.conwell@santos.com
Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return
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THE USE OF AND RELIANCE UPON THIS RECORDED -DATA BY THE HEREIN NAMED COMPANY (AND ANY OF ITS AFFILIATES, PARTNERS,
REPRESENTATIVES, AGENTS, CONSULTANTS
AND EMPLOYEES) IS SUBJECT TO THE TERMS
AND CONDITIONS AGREED UPON BETWEEN SLB
AND THE COMPANY, INCLUDING: (a) RESTRICTIONS ON USE OF THE RECORDED -DATA;
(b) DISCLAIMERS
AND WAIVERS OF WARRANTIES AND
REPRESENTATIONS REGARDING COMPANY'S USE AND RELIANCE UPON
THE RECORDED -DATA;
AND (c) CUSTOMER'S
FULL AND SOLE
RESPONSIBILITY FOR ANY INFERENCE DRAWN OR DECISION MADE IN CONNECTION WITH THE USE OF THIS RECORDED -DATA.
1. Header
2. Disclaimer
3. Contents
4. Well Sketch
5. Borehole Size/Casing/Tubing Record
6. Run 1
6.1 Integration Summary
6.2 Software Version
6.3 Composite Summary
6.4 Log (SonicScope Top of Cement RM )
6.5 Parameter Listing
7. Tail
Driller Depth
Casing 20in
Open Hole 20in
Casing 13.375in
68lbm/ft
Open Hole 16in
2912.00 ft________,
9.625in
11350.00 ff______
11500.00 f!
15743.00 ft
15748.00 ft
Casing An
261bri
Open Hole 8-Sin
Bit
7
Bit Size (in)
20
16
12.25
8.5
Top Driller (ft)
46.9
128
2912
11500
Bottom Driller( ft)
128
2912
11500
15748
Casing
Size(in)
20
13.375
9.625
7
Weight(Ibm/ft)
215
68
47
26
Inner Diameter (in)
17.924
12.415
8.681
6.276
Grade
N/A
L80
L80
L80
Top Driller (ft)
46.9
46.9
46.9
11350
Bottom Driller( ft)
128
2912
11500
15743
Acquisition System
Version
Maxwell 2025.0
15.0.232025.3100
Application Patch
DnM_Hotfix-Mandatory-2025.0_15.0.237043
Run Name Pass Objective
Direction
Top
Bottom
Start
Stop Include Parallel Data
Run 1 Ream Down 1
Down
11939.75 ft
15638.42
ft
03-Feb-2026
3:25:48 PM
04-Feb-2026 No
9:29:57 AM
All depths are referenced to toolstring zero
• •
Company:Oil Search (Alaska), LLC Well:PIKKA NDB-039
Description: SonicScope Top of Cement RM Format: Log( SonicScope Top of Cement RM)
Measured Depth Creation Date: 05-Feb-202616:20:25
Index Scale: 0.3 in per 100 ft Index Unit: ft Index Type:
Casing
Casing Inner
Diameter
(CID _CSG)
SONICSCOP
E4 RM
Min
Amplitude
Max
5 in 15
Casing Outer
Diameter
(COD_CSG)
15000
15500
i
} -
t I
t
f
Top of Cement 7in Liner
@ 14870 1 MD
Casing
Min Amplitude Max Min Amplitude Max Casing Amplitude of Non -Filtered
Waveform of Selected Receiver
WF_MH_CSG SONICSCOPE4 RM Receiver Projection Depth (AMP_CSG_RMP) SONICSCOPE4 RM
0 us 2000 RM(SPJ_MH_RA) SONICSCOPE4 RM -25 125
Lower Boundary of Processing Time 40 us/ft 240 Casing Amplitude of Filtered Waveform of
Window for Casing Amplitude with Selected Receiver (AMP _CSG_FIL_RMP)
Digitizing Delay (CSG_TWB) SONICSCOPE4 RM
0 us 2000 -25 125
Upper Boundary of Processing Time
Window for Casing Amplitude with
Digitizing Delay (CSG_TWE)
------------------------
0 us 2000
Casing Inner
Diameter
(CID _CSG)
SONICSCOP
E4 RM
Casing Outer
Diameter
(COD_CSG)
SONICSCOP
E4 RM
5 in 15
True Vertical
Depth (TVD)
RT
10000 5000
ft
Bit Size (BS)
RT
5 in 15
Description: SonicScope Top of Cement RM Format: Log( SonicScope Top of Cement RM) Index Scale: 0.3 in per 100 ft Index Unit: ft Index Type:
Measured Depth Creation Date: 05-Feb-202616:20:25
Run 1- Parameters
Parameter
Description
Tool
Value
Unit
BS
Bit Size
DNMSESSION
8.5
in
CSG_DETE
Peak Detection Mode for Casing Amplitude
SONICSCOPE4
Peak -To —Peak
CSG_RCV_NUM
Receiver Number to Compute Casing Amplitude
SONICSCOPE4
1
CSG_TWB
Lower Boundary of Processing Time Window for Casing
Amplitude with Digitizing Delay
SONICSCOPE4
400
us
CSG_TWE
Upper Boundary of Processing Time window for Casing
Amplitude with Digitizing Delay
SONICSCOPE4
600
us
DEPTH_SEL
Depth Selection Parameter
DNMSESSION
Driller's Depth
STCAL_MH
STC Algorithm Option - Monopole High
SONICSCOPE4
FullArray
STCFL_MH
Pre-STC Filter Length - Monopole High
SONICSCOPE4
17
STCRSEL_MH
STC Sensor Selection - Monopole High
SONICSCOPE4
[On, On, On, On, On, On, On,
On, On, On, On, On]
STCSLL_MH
STC Slowness Lower Limit -Monopole High
SONICSCOPE4
40
us/ft
STCSUL_MH
STC Slowness Upper Limit -Monopole High
SONICSCOPE4
240
us/ft
STCXFH_MH
Pre-STC Filter High Frequency Cutoff - Monopole High
SONICSCOPE4
116000
JHz
STCXFL_MH Pre-STC Filter Low Frequency Cutoff -Monopole High
SONICSCOPE4
10000
Hz
Run is Parameters
Parameter
Description
Tool
Value
Unit
DSIN_MH
Digitizer Sample Interval - Monopole High
SONICSCOPE4
20
us
Santos
Cement - NDB-039
Surface Casing Cement
Surface Casing Cement, Casing, 1/15/2026 18:30
Type
Cementing Start Data
Cementing End Date
Wellbore
String
Casing
1/15/2026
1/15/2026
Original Hole
Surface Casing, 2,883.OftKB
Cementing Company
Evaluation Method
I Cement Evaluation Results
Halliburton Energy
Returns to Surface
Good lift pressures observed. 93 bbls of clean cement to surface and no losses during cement job.
Services
Comment
Cement 13-3/8" Surface casing as follows:
- Rig to pump 40 bbi 10 ppg Power Vis Spacer, at 3 bpm, 85 psi
- Fill lines with 5 bbls water and pressure test to 4,000 psi for 5 minutes - Good test
- Drop 1st bottom plug
- Pump 80 bbls of 10.5 ppg Tuned Spacer at 4.0 bpm, 270 psi.
- Release 2nd bottom plug.
- Pump 472 bbls of 11.0 ppg ArcticCem lead cement at 6 bpm, 462 psi. Excess volume 200% (936
sacks, yield 2.535 cu.ft/sk)
-Pump 65 bbls of 15.3 ppg Type 1/II tail at 3 bpm, 381 psi. Excess volume 50% (297 sacks, yield 1.24 cu.ff/sk)
-Drop top plug and followed by 20 bbls fresh water.
- Perform displacement with rig pumps and 9.4 ppg mud
- 320 bbls displaced at 5 bpm: ICP 306 psi, FCP 821 psi.
-Reduce rate to 4 bpm and pump 78 bbls ICP 670 psi. Final circulating pressure 814 psi prior to plug
bump.
-Bump plug and increase pressure to 1,335 psi, held for 5 min. bled off check floats, good.
-Total displacement volume 398 bbls (measured by strokes at 96% pump efficiency).
-Total losses for cement job and displacement: 0 bbls
- Observed Power Vis interface at 191 bbls into displacement.
- Observed Tuned Spacer with Red Die interface at 295 bbls into displacement.
- Observed 93 bbls clean cement to surface
- CIP at 23:30 hrs.
1, 0.0-2,889.0ftK8
Top Depth (flKB)
Bottom Depth (ftKB)
Full Return'
Vol Cement Ret (bbl)
Top Plug?
Bottom Plug?
0.0
2,889.0
Yes
93.0
Yes
Yes
Initial Pump Rate (bbVmin)
Final Pump Rate (bbVmin)
Avg Pump Rate (bbl/min)
Final Pump Pressure (psi)
Plug Bump Pressure (psi)
4
3
4
821.0
814.0
Pipe Reciprocated?
Reciprocation Stroke Length (ft)
Reciprocation Rate (spm)
Pipe Rotated?
Pipe RPM (rpm)
No
No
Tagged Depth (flKB)
Tag Method
Depth Plug Dulled Out To (ftKB)
Drill Out Diameter (in)
Drill Out Date
Tuned Spacer
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (bbl)
Tuned Spacer
Tuned Spacer
80.0
w/ 8# Red Dye
Estimated Top (flKB)
Percent Excess Pumped (%)
Yield (fY/sack)
Mix H2O Ratio (gaVsack)
Free Water (%)
0.0
1.82
12.17
DensM(lb/gal)
Plastic Viscosity(cP)
mickening Time(hr)
Tat Compressive Strength (psi)
CmprStr Time 1(hr)
10.50
ArticCem Lead
Fluid Type
Fluid Description
Amount (sacks)
class
Volume Pumped (Inch
ArticCem Lead
11.0 pgg ArcticCem Lead
952
1/II
472.0
Estimated Top (flKB)
Percent Excess Pumped (%)
Yield (Wlsack)
Mix H2O Ratio (gaVsack)
Free Water (%)
0.0
200.0
2.54
12.21
0.00
Density(lb/gal)
Plastic Viscosity(cP)
Thickening Time(hr)
tat Compressive Strength (psi)
CmprStr Time 1(hr)
11.00
15.8
22.50
500.0
37.50
Tail
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (Inch
Tail
15.3 ppg Tail
312
1/II
65.0
Estimated Top (flKB)
Percent Excess Pumped (%)
Yield (Wlsack)
Mix H2O Ratio (gaVsack)
Free Water (%)
0.0
50.0
1.24
5.59
0.00
Density(lb/gal)
Plastic Viscosity(cP)
mickening Time(hr)
tat Compressive Strength (psi)
CmprStr Time 1(hr)
15.30
57.8
10.75
500.0
14.50
Page 1 of 1
Santos
Cement - NDB-039 Intermediate 1 Cement 1st stage
Intermediate 1 Cement 1st stage, Casing, 1/22I2026 22:47
Type
Cementing Start Data
Cementing End Date
Walloons
Stang
Casing
1/22/2026
1/23/2026
Original Hole
Intermediate Liner, 11,497.OftKB
Cementing Company
Evaluation Method
Cement Evaluation Results
Hallibunon Energy
Cement job parameters /
-42 bbls lost after cement into annulus, good lift pressures (33psi), good FIT
to 14.Oppg
Services
FIT
Comment
-Fill lines with water and pressure test to 250 low and 5,000 psi high for 2 minutes.
-Pump 80 bbls of 12.5 ppg tuned spacer at 3 bpm.
-ICP 615 psi / FCP 370 psi.
-40 bbls losses.
-Cement wet at 23:48 hrs.
-Release bottom pump down plug.
-Pump 85 bbls 15.3 ppg Versacem tail cement Type 1/11 (355 sacks, yield 1.24 cu ft/sk), at 3-4 bpm,
average circulating pressure 540
psi.
-Release top pump down plug, chase with 20 bbls of washup from Halliburton and overboard to cuttings
box.
-Perform displacement with rig pumps, displace with 11.6 ppg OBM at 3 bpm, 50% returns throughout.
-ICP 332 psi, circulating pressure when cement turned corner 461 psi. Final circulating pressure 494 psi.
-Bump plug, and pressure up to 1051 psi. Hold for 5 mins. Check floats, floats held.
-Total displacement volume 677 bbls (measured by strokes at 96% pump efficiency).
- Estimate 42 bbls of losses after cement into the annulus.
-Total losses for cement job 423 bbls.
-CIP 04:20 his.
1, 10,500.0-11,495.01
Top Depth (ftKB)
Bottom Depth (ftKB)
Full Return?
Vol Cement Ret (Whit
Top Plug?
Bottom Plug?
10,500.0
11,495.0
No
I
Yes
Yes
Initial Pump Rate rx in)
Final Pump Rate rx in)
Avg Pump Rate (bbl in)
Final Pump Pressure (psi)
Plug Bump Pressure (psi)
3
3
3
503.0
1,051.0
Pipe Reciprocated?
Reciprocation Stroke Length (ft)
Reciprocation Rate (spm)
Pipe Rotated?
Pipe RPM (rpm)
No
No
Tagged Depth (ftKB)
Tag Method
Depth Plug Drilled Out To (ftKB)
Drill Out Diameter (in)
Drill Out Date
Spacer
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (Inch
Spacer
Tuned Spacer
1/II
80.0
4# Red Dye, 65 gal Surf B &
Muso1A
Estimated Top (ftKB)
Percent Excess Pumped (%)
Yield (fF sack)
Mix H2O Ratio (gaVsack)
Free Water (%)
2.24
13.09
Density(Ib/gaI)
Plastic Viscosity(cP)
Thickening Time(hr)
1 at Compressive Strength (psi)
CmprStr Time 1(hr)
12.50
Tail
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (bbi)
Tail
Versacem tail cement Type 1/11
355
85.0
Estimated Top (ftKB)
Percent Excess Pumped (%)
Yield (Wlsack)
Mix H2O Ratio (gaVsack)
Free Water (%)
10,500.0
30.0
1.24
5.56
0.00
Density(Ib/gaI)
Plastic Viscosity(cP)
Thickening Time(hr)
tat Compressive Strength (psi)
CmprStr Time 1(hi
15.30
129.0
7.10
500.0
12.51
Page 1 of 1
Santos
Cement - NDB-039 Intermediate 1 Cement 2nd stage
Intermediate 1 Cement 2nd stage, Casing, 1/23/2026 18:00
Type
Cementing Start Data
Cementing End Date
Walloons
String
Casing
1/23/2026
1/23/2026
Original Hole
Intermediate Liner, 11,497.OftKB
Cementing Company
Evaluation Method
Cement Evaluation Results
Halliburton Energy
Returns to Surface
Good lift pressure observed when displacing cement. -100 bbls of clean cement returned to surface when
Services
circulating above the liner top after cement
job. No losses during cement job.
Comment
Perform 9-518" 47# Intermediate liner 2nd stage cement job through C-Flex stage tool as follows:
-Mix and pump 80 bbls of 12.5
ppg mud flush at 3.5 bpm and full returns.
-Mix and pump 80 bbls of 13.5
Tuned Spacer at 3.5 bpm with full returns.
-Mix and pump 335 bbls of
14.5 ppg Swiftcem Tail cement. Pumped first 260 bbls at 4 bpm, ICP 305 psi, FCP 502 psi. Pumped remaining
75 bbls at 3.5 bpm.
ICP 411 psi, FCP 404 psi.
No losses throughout cement job. Dyed spacer observed at surface.
-Excess Volume 100% (1501 sacks, yield 1.237 cu ft/sk).
-Displace to calculated displacement volume of 122 bbls through rig pumps with 11.6 ppg OBM at
3 bpm. ICP 176 psi. FCP 529 psi.
-CIP at 22: 11 hrs.
2, 2,729.0.5,772.OftKB
Top Depth (ftKB)
Bottom Depth (ftKB)
Full Retum?
Vol Cement Ret (WI)
Top Plug?
Bottom Plug?
2,729.0
5,772.0
Yes
100.0
No
No
Initial Pump Rate (bbVmin)
Final Pump Rate (bbMnin)
Avg Pump Rate (bbl/min)
Final Pump Pressure (psi)
Plug Bump Pressure (psi)
4
3
4
522.0
Pipe Reciprocated?
Reciprocation Stroke Length (ft)
Reciprocation Rate (spm)
Pipe Rotated?
Pipe RPM (rpm)
No
No
Tagged Depth (ftKB)
Tag Method
Depth Plug Dulled Out To (ftKB)
Dull Out Diameter (in)
Drill Out Date
Preflush
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (bbl)
Preflush
MUD FLUSH Spacer
80.0
8# Red Dye, 65 gal Surf B &
MusolA
Estimated Top (ftKB)
Percent Excess Pumped I)
Yield (Wisack)
Mix H2O Ratio (gaVsack)
Free Water (Yo)
2.22
12.89
Density(lb/gal)
Plastic Viscosity(cP)
Thickening Tim.(hr)
1st Compressive Strength (psi)
CmprStr Time 1(hr)
12.50
Spacer
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (bbl)
Spacer
Tuned Spacer
80.0
4# Red Dye, 65 gal Surf B &
MusolA
Estimated Top (ftKB)
Percent Excess Pumped I)
Yield (W/sack)
Mix H2O Ratio (gaVsack)
Free Water (Vo)
1.91
10.72
Density(lb/gal)
Plastic Viscosity(cP)
Thickening Time(hr)
1st Compressive Strength (psi)
CmprStr Time 1(hr)
123.50
Tail
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (bbl)
Tail
SwiftCem Type 1/11
335.0
Estimated Top (ftKB)
Percent Excess Pumped I)
Yield (Tisack)
Mix H2O Ratio (gaVsack)
Free Water (Yo)
100.0
1.39
6.79
0.00
Density(lb/gal)
Plastic Viscosity(cP)
Thickening Time(hr)
tat Compressive Strength (psi)
CmprStr Time 1(hr)
14.50
49.5
7.20
500.0
23.64
Page 1 of 1
Santos
Cement - NDB-039 Intermediate 2 Casing Cement
Intermediate 2 Casing Cement, Casing, 21112026 17:30
Type
Cementing Start Data
Cementing End Date
Walloons
String
Casing
2/1/2026
2/2/2026
Original Hole
Intermediate 2 Liner,
15,745.OftKB
Cementing Company
Evaluation Method
Cement Evaluation Results
Hallibunon Energy
Cement Bond Log
Good lift pressures when displace cement into
annulus (-320psi). Sonic log
confirms Fair to Poor cement
Services
14118'-14749', Decent cement 14749-14870', and Good cement 14870' to bottom.
Comment
Cement 7" Intermediate 2 liner.
-PJSM with 3rd party and rig personnel
-Fill lines with water and pressure test to 4,000 psi for 5 min.
-Pump 196 bbls of 6.8 ppg LVT at 2 bpm, 1,395 psi.
-Pump 79 bbls of 12.5 ppg Tuned spacer at 2.2 bpm, 725 psi.
-Release bottom pump down plug.
-Pump 150 bbls of 15.3 ppg Versacem tail (type 1/11) at 3 bpm, Excess Volume 30% (703 sacks, yield 1.24 cu.ft/sk).
-Wash up lines to cuttings box with 20 bbls water.
-Release top pump down plug.
-Perform displacement with rig pumps at 3 bpm. Land bottom plug with ICP 620 psi and FCP 940 psi when top plug bumped with 3
bpm, land top plug at 351
bbls displacement.
-Bump plug with 1,440 psi and hold for 5 mins. CIP at 23:30 hrs, cement wet at 21:17 him
-Check floats (holding).
-130 bbls losses after cement into annulus.
-Total 403 bbls loss during cement job.
-Rig down cementing hose.
1, 13,350.0.15,745.OftKB
Top Depth (ftKB)
Bottom Depth (ftKB)
Full Return'
Val Cement Ret (bbl)
Top Plug?
Bottom Plug?
13,350.0
15,745.0
No
0.0
Yes
Yes
Initial Pump Rate (bbgmin)
Final Pump Rate (bbMnin)
Avg Pump Rate (bbl/min)
Final Pump Pressure (psi)
Plug Bump Pressure (psi)
2
3
3
940.0
1,440.0
Pipe Reciprocated?
Reciprocation Stroke Length (ft)
Reciprocation Rate (spm)
Pipe Rotated?
Pipe RPM (rpm)
No
No
Tagged Depth (ftKB)
Tag Method
Depth Plug Drilled Out To (ftKB)
Drill Out Diameter (in)
Drill Out Date
Spacer
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (bb9
Spacer
Spacer had 65gals and Surf B
80.0
and Musol A
Estimated Top (flKB)
Percent Excess Pumped (%)
Yield (Wisack)
Mix H2O Ratio (gaVsack)
Free Water (%)
2.24
13.09
Density(lb/gal)
Plastic Viscosity(cP)
Thickening Time(hr)
1 at Compressive Strength (psi)
Cmpi Time 1(hr)
12.50
Tail
Fluid Type
Fluid Description
Amount (sacks)
Class
Volume Pumped (Inch
Tail
Versacem Tail (Type 1111)
703
1/11
150.0
Estimated Top (flKB)
Percent Excess Pumped (%)
Yield (1Plsack)
Mix H2O Ratio (gaVsack)
Free Water (%)
13,400.0
30.0
1.24
5.57
0.00
Density(lb/gal)
Plastic Viscosity(cP)
Thickening Time(hr)
tat Compressive Strength (psi)
CmprStr Time 1(hr)
15.30
117.8
8.00
500.0
13.88
Page 1 of 1
Tuluvak Sand @ 3,219' MD
Top Nan 3.2 @15,902' MD
Top Nanushuk @14,743' MD
NDB-039 Well Schematic
(As Drilled - DRAFT)
20" Insulated Conductor128' MD
9-5/8" Liner Hanger and Liner Top Packer2,729' MD
13-3/8" 68 ppf L-80 Surface Casing2,883' MD
4-½, 12.6ppf P-110S Production Liner25,595' MD
4-½ Liner Hanger/Top Packer15,595' MD
GL
69.7' RKB Bottom Flange 02/08/2026
9-5/8" Tieback2,729' MD
9-5/8" Cflex Stage Tool (~50' MD below TS790)5,775' MD
7" TOC (Sonic log)14,749' MD
7", 26ppf L-80 Production Liner15,745' MD
9-5/8", 47ppf L-80 Intermediate Liner11,497' MD
9-5/8" Primary TOC (1000' MD above shoe)10,497' MD
7" Liner Hanger and Liner Top Packer11,330' MD
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Conwell, Russell (Russell)
To:McLellan, Bryan J (OGC)
Subject:NDB-039 (PTD 225-144) 7" FIT
Date:Sunday, February 8, 2026 6:02:58 AM
Attachments:NDB-039 Intermediate #2 Csg & LOT.xlsm
NDB-039 7 x 9.625 x 7 casing test & 6.125in prod. FIT.pdf
Hi Bryan,
The rig successfully tested the 9-5/8” x 7” casing to 3500 psi and last night we drilled out and got an
FIT of 14.21ppg as required (results attached). The FIT was performed with 7.7ppg MW utilizing
~600psi of initial surface backpressure held with MPD. The rig is currently drilling ahead in the 6-1/8”
production hole.
I will send a separate note on the cementing summary along with the final Sonic logs.
Let me know if you have any questions. Thanks.
regards
Russell
Russell Conwell
Senior Drilling Engineer
m: +1 907 615 2234| e: russell.conwell@santos.com
Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,
distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return
email and delete the email without making a copy. Please consider the environment before printing this email
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:McLellan, Bryan J (OGC)
To:Conwell, Russell (Russell)
Cc:Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Starns, Ted C (OGC); Wallace, Chris D (OGC)
Subject:RE: NDB-039 (PTD 225-144) 7" Sonic Log Questions
Date:Friday, February 6, 2026 1:01:00 PM
Attachments:Oil_Search_Alaska_LLC_Pikka_NDB_039_R4_7in_Liner_SonicScope475_ReamDown_RM_TOC_PPT_TZD.pdf
Russell,
Thanks for sending the log analysis and discussion on the phone. I don’t believe there is
much benefit to re-running the sonic log after waiting an additional 3 days for cement to
harden. This log was run ~2 days after cement, it shows good cement above the top of
the NT8, Decent cement to within 6’ of the top of the Nanushuk and a transition of fair to
poor cement for >600’ above the Nanushuk which would only get better with time. It is
not necessary from AOGCC’s perspective to re-run the log.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Conwell, Russell (Russell) <Russell.Conwell@santos.com>
Sent: Friday, February 6, 2026 12:21 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: NDB-039 (PTD 225-144) 7" Sonic Log Questions
Hi Bryan,
We managed to get our BHA free yesterday, have done a cleanout run, and will be RIH this
evening with the drilling BHA. We have also just got the final Top Of Cement Report from SLB
which is attached.
In summary:
Top Nanushuk – 14,743’ MD
Estimate top Hydrocarbon – ~14946’ MD (initial estimate to be confirmed)
Cement tops as per SLB report
Would be good to chat through this and our potential forward plan. Feel free to call when
available. Thanks.
Russell Conwell
Senior Drilling Engineer
m: +1 907 615 2234| e: russell.conwell@santos.com
Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return
email and delete the email without making a copy. Please consider the environment before printing this email
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Conwell, Russell (Russell)
To:McLellan, Bryan J (OGC)
Subject:NDB-039 (PTD 225-144) 9-5/8" FIT
Date:Monday, January 26, 2026 7:02:51 AM
Attachments:NDB-039 Intermediate #1 Csg & LOT.xlsm
NDB-039 Int1 FIT-CT-OAT Chart.pdf
Hi Bryan,
Yesterday we finished up the casing test on the 9-5/8” liner and tie-back to 3500 psi and this
morning got a successful FIT to 14.0ppg on the shoe after drill out. Note that we performed this FIT
with MPD online so had a start pressure of ~350 psi as we are holding 12.0ppg on connections. The
rig is currently drilling ahead in the 8-1/2” x 9-7/8” intermediate 2 hole section.
Note we did have ~50% losses while displacing the cement on the 9-5/8” primary cement job but
saw good lift pressures which indicated the loss zone was likely above the cement top in the
annulus. There were no losses on the 9-5/8” 2nd stage job across the Tuluvak with ~100bbls of good
cement circulated off the top of the liner.
Let me know if you have any questions.
Regards
Russell
Russell Conwell
Senior Drilling Engineer
m: +1 907 615 2234| e: russell.conwell@santos.com
Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return
email and delete the email without making a copy. Please consider the environment before printing this email
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:NDB-039 Date:1-26-26
Csg Size/Wt/Grade:Supervisor:Buzby / Whitlatch
Csg Setting Depth:11,497 TMD 3,405 TVD
Mud Weight:9.5 ppg Leakoff pressure =796 psi
FIT/LOT=14.00 ppg Hole Depth =11,520 md
Fluid Pumped=1.5 Volume Back =1.5 bbls
Estimated Pump Output:0.0925 Barrels/Stroke
LEAK-OFF DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->0 353 ->0 0
->2 414 ->4 125
->4 465 ->8 232
->6 517 ->12 345
->8 571 ->16 452
->10 620 ->20 563
->12 673 ->32 882
->14 724 ->40 1079
->16 782 ->50 1325
->17 801 ->60 1592
-> ->70 1853
-> ->80 2121
-> ->90 2391
-> ->120 3249
->136 3694
Enter Holding Enter Holding Enter Holding
Time Here Time Here Pressure Here
->0 801 ->0 3694
->1 793 ->1 3690
->2 788 ->2 3682
->3 783 ->3 3676
->4 779 ->4 3675
->5 776 ->5 3670
->6 772 ->10 3655
->7 768 ->15 3646
->8 764 ->20 3633
->9 761 ->25 3623
->10 757 ->30 3617
-> ->
-> ->
-> ->
9 5/8, 47# L-80 Hyd 563
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150Pressure (psi)Strokes (# of)
LEAK-OFF DATA CASING TEST DATA
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes)
LEAK-OFF DATA CASING TEST DATA
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
Mark Staudinger
Senior Drilling Engineer
Oil Search Alaska, LLC
601 W 5th Avenue
Anchorage, AK, 99501
Re: Pikka Field, Nanushuk Oil Pool, Pikka NDBi-039
Oil Search Alaska, LLC
Permit to Drill Number: 225-144
Surface Location: 2328 FSL, 2015 FWL, Sec4, T11N, RE6, UM
Bottomhole Location: 332 FSL, 4786 FEL, Sec 24, T12N, R5E, UM
Dear Mr. Staudinger:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run
must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first. Proposed dry ditch sample
interval from Attachment 9 accepted with modification of Ivishak (not to exceed 30').
This permit to drill does not exempt you from obtaining additional permits or an approval required by law
from other governmental agencies and does not authorize conducting drilling operations until all other
required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw
the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an
applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC
order, or the terms and conditions of this permit may result in the revocation or suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this 7th day of January 2026.
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address: 6. Proposed Depth: 12. Field/Pool(s):
MD: 25,577' TVD: 4,126'
4a. Location of Well (Governmental Section): 7. Property Designation: ADL: 391445, 393021
Surface:
Top of Productive Horizon: 2426 FSL, 780 FEL, Sec 36, T12N, R5E, UM 8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 332 FSL, 4786 FEL, Sec 24, T12N, R5E, UM 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 69.8' 15. Distance to Nearest Well Open
Surface: x- 421,980 y- 5,972,715 Zone- 4 22.8' to Same Pool: 740 ft
16. Deviated wells: Kickoff depth: 347 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 90.05 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
42" 20"x34" 215# X-52 Welded 80' Surface Surface 128' 128'
16" 13-3/8" 68# L-80 TXP BTC 2,912' Surface Surface 2,912' 2,405'
12-1/4" 9-5/8" 47# L-80 HYD563 8,738' 2,762' 2,337' 11,500' 3,415'
Tie Back 9-5/8" 47# L-80 HYD563 2,762' Surface Surface 2,762' 2,337'
8-1/2" x 9-7/8"7" 26# L-80 HYD563 4,391' 11,350' 3,400' 15,741' 4,066'
6-1/8" 4-1/2" 12.6# P-110S HYD563 9,986' 15,591' 4,024' 25,577' 4,126'
Tubing 4-1/2" 12.6# P-110S HYD563 15,591' Surface Surface 15,591' 4,024'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Authorized Name: Mark Staudinger
Authorized Title: Sr. Drilling Engineer Contact Phone:520-273-6643
Date:
Permit to Drill API Number: Permit Approval
Number: Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Pikka NDB-039
Pikka/ Nanushuk Oil Pool
2/12/2025
Contact Email: mark.staudinger@santos.com
Contact Name: Mark Staudinger
500'
Uncemented
See attachment 6
3,704
Cement Volume MD
Commission Use Only
See cover letter for other
requirements.
Total Depth MD (ft): Total Depth TVD (ft):
IS000361277U
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
See attachment 6
1,479'
LONS 19-003
601 W Fifth Avenue, Anchorage, AK 99501-6301
Oil Search Alaska, LLC
2328 FSL, 2015 FWL, Sec4, T11N, RE6, UM 393019, 392991, 392970, 392968
18. Casing Program: Top - Setting Depth - BottomSpecifications
1,892
Cement Quantity, c.f. or sacks
(including stage data)
Grouted to surface
See attachment 6
Uncemented
N/A
Production
Liner
Intermediate
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Authorized Signature:
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Conductor/Structural
LengthCasing Size
Effect. Depth MD (ft): Effect. Depth TVD (ft):Plugs (measured):
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D
277U
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
lling Engineer
December 29, 2025
225-144
By Grace Christianson at 11:22 am, Dec 29, 2025
See attached conditions of approval
A.Dewhurst 06JAN25
50-103-20937-00-00
BJM 1/6/26
392984
DSR-12/30/25
01/07/26
01/07/26
NDB-039 (PTD 225-144)
Approval
1. Diverter variance
250
-
2. . All a
3. -
-25-
4.
5.
. Cement
9-.
.
-
:
a.
-
-
-
-~
9. 2 .
10. -
are met:
a.
a
-
-
c.
d.
11. -
a.
n
c.
d.
e. -
:
i. A
ii.
iii. -
Page 1 of 1
29 December 2025
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
Re: Application for Permit to Drill
Oil Search (Alaska), LLC, a subsidiary of Santos Limited
NDB-039
Dear Sir/Madam,
Oil Search (Alaska), LLC hereby applies for a Permit to Drill an onshore development well from the NDB
drilling pad on the North Slope of Alaska. NDB-039 is planned to be a horizontal producer targeting the
Nanushuk 3. The approximate spud date is anticipated to be February 12
th, 2026. Nabors Rig 272 will be
used to drill this well.
The 16 Surface Hole will TD above the Tuluvak sand and then 13-3/8 casing will be set and cemented.
The 12-1/4 Intermediate Hole #1 will be drilled into the Seabee formation at an inclination of ~84 degrees.
A 9-5/8 liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8
tieback will be run to the top of the 9-5/8 liner.
The 8-1/2 x 9-7/8 Intermediate Hole #2 will be drilled through the Seabee and Nanushuk formations with
the casing set in the Nanushuk 3 formation at ~74 degrees. A 7 liner will be set and cemented from TD to
cover the Nanushuk formation.
The 6-1/8 Production Hole will be geo-steered and landed in the Nanushuk 3 sand and the lateral will be
drilled to TD. The well will be completed as a stimulated 4-1/2 liner with frac sleeves and isolation packers.
The production liner will be tied back to surface with a 4-1/2 tubing upper completion string.
Managed Pressure Drilling (MPD) will be implemented in the Intermediate #2 and Production Hole intervals.
Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to
Drill containing information as required by 20 AAC 25.005.
If there are any questions and/or additional information desired, please contact me at (520) 273-6643 or
mark.staudinger@santos.com.
Respectfully,
Mark Staudinger
Senior Drilling Engineer
Oil Search (Alaska), LLC
Enclosures:
Form 10-401 Permit to Drill
Application for Permit to Drill
Respectfully,
Mark Staudinger
Application for Permit to Drill
NDB-039 Well
Table of Contents
1. Well Name......................................................................................................................................3
2. Location Summary..........................................................................................................................3
3. Blowout Prevention Equipment Information.................................................................................4
4. Drilling Hazards Information...........................................................................................................5
5. Procedure for Conducting Formation Integrity Tests.....................................................................6
6. Casing and Cementing Program.....................................................................................................6
7. Diverter System Information..........................................................................................................7
8. Drilling Fluid Program.....................................................................................................................7
9. Abnormally Pressured Formation Information ..............................................................................8
10. Seismic Analysis............................................................................................................................8
11. Seabed Condition Analysis............................................................................................................8
12. Evidence of Bonding.....................................................................................................................8
13. Proposed Drilling Program ...........................................................................................................9
14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................12
15. Proposed Variance Requests......................................................................................................12
Attachments..................................................................................................................................................17
Attachment 1: Location Map............................................................................................................18
Attachment 2: Directional Plan........................................................................................................20
Attachment 3: BOPE Equipment ......................................................................................................21
Attachment 4: Drilling Hazards.........................................................................................................22
Attachment 5A: Leak Off Test Procedure (Conventional)................................................................24
Attachment 5B: Leak Off Test Procedure (With MPD).....................................................................25
Attachment 6: Cement Summary.....................................................................................................26
Attachment 7: Prognosed Formation Tops......................................................................................30
Attachment 8: Well Schematic.........................................................................................................31
Attachment 9: Formation Evaluation Program................................................................................32
Attachment 10: Wellhead & Tree Diagram......................................................................................33
Attachment 11: Diverter Variance Request NDB Surface Hole Map View.......................................34
Attachment 12: Oil Search Alaska 21-day BOPE Test Schedule Waiver Approval Letter.................35
Attachment 13: Managed Pressure Drilling.....................................................................................38
Attachment 14: As Staked Survey NDB Well 39 Conductor Final.....................................................40
An application for a Permit to Drill must be accompanied by each of the following items, except for an
item already on file with the commission and identified in the application.
1. Well Name
20 AAC 25.005 (f)
Each well must be identified by a unique name designated by the operator and a unique API
number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well
branches, each branch must similarly be identified by a unique name and API number by adding a
suffix to the name designated for the well by the operator and to the number assigned to the well
by the commission.
The well for which this application for a Permit to Drill is submitted is designated as NDB-039. This
will be a development production well.
2. Location Summary
20 AAC 25.005 (c) (2)
A plat identifying the property and the property's owners and showing:
(A) the coordinates of the proposed location of the well at the surface, at the top of each objective
formation, and at total depth, referenced to governmental section lines;
(B) the coordinates of the proposed location of the well at the surface, referenced to the state plane
coordinate system for this state as maintained by the National Geodetic Survey in the National
Oceanic and Atmospheric Administration;
(C) the proposed depth of the well at the top of each objective formation and at total depth
Location at Surface
Reference to Government Section Lines 2,328 FSL, 2,015 FWL, Sec 4, T11N, R6E, UM
NAD 27 Coordinate System N 5,972,715 E 421,980
Rig KB Elevation 47 above GL
Ground Level 22.8 above MSL
Location at Top of Productive Interval
Reference to Government Section Lines 2,426 FSL, 780 FEL, Sec 36, T12N, R5E, UM
NAD 27 Coordinate System N 5,978,254 E 409,070
Measured Depth, Rig KB (MD)16,214
Total Vertical Depth, Rig KB (TVD)4,134
Total vertical Depth, Subsea (TVDSS)4,064
Location at Bottom of Productive Interval
Reference to Government Section Lines 332 FSL, 4,786 FEL, Sec 24, T12N, R5E, UM
NAD 27 Coordinate System N 5,986,751 E 405,176
Measured Depth, Rig KB (MD)25,577
Total Vertical Depth, Rig KB (TVD)4,126
Total vertical Depth, Subsea (TVDSS)4,056
(D) other information required by 20 AAC 25.050(b);
20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form
10-401) must:
(1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including
all adjacent wellbores within 200 feet of any portion of the proposed well; and
Please refer to Attachment 2: Directional Plan for further details.
(2) for all wells within 200 feet of the proposed wellbore:
(A) list the names of the operators of those wells, to the extent that those names are known or
discoverable in public records, and show that each named operator has been furnished a copy of
the application by certified mail; or
(B) state that the applicant is the only affected owner.
The applicant is the only affected owner.
3. Blowout Prevention Equipment Information
20 AAC 25.005 (c) (3)
A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC
25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable;
A 21-day BOPE test schedule is planned per the waiver acceptance letter and conditional
requirements outlined in Docket Number OTH-25-010 from the AOGCC to Oil Search Alaska for
Nabors 272 operating at NDB (see attachment 12).
Nabors 272 BOP Equipment:
BOP Equipment
NOV Shaffer Spherical annular BOP, 13-5/8 x 5000 psi
NOV T3 6012 double gate, 13-5/8 x 5000 psi
Mud cross, 13-5/8 x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets
Choke Line, 3-1/8 x 5000 psi with 3-1/8 manual and HCR valve
Kill Line, 2-1/16 x 5000 psi with 3-1/8 manual and HCR valve
NOV T3 6012 single gate, 13-5/8 x 5000 psi
Choke Manifold
3-1/8 x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG
mud/gas separator
BOP Closing Unit
NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty-Four 15 gallon
bottles. Equipped with 1 electric and 3 air pumps with emergency power.
Please refer to Attachment 3: BOPE Equipment for further details.
4. Drilling Hazards Information
20 AAC 25.005 (c) (4)
Information on drilling hazards, including
(A) the maximum downhole pressure that may be encountered, criteria used to determine it, and
maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of
true vertical depth, unless the commission approves a different pressure gradient that provides a
more accurate means of determining the maximum potential surface pressure;
12-1/4 Intermediate #1 Hole Pressure Data
Maximum anticipated BHP 1,616 psi at TD in Seabee at 3,415 TVD
(9.1ppg EMW in the Seabee formation to section TD)
Maximum surface pressure 1,275 psi from TD in the Seabee
(0.10 psi/ft gas gradient to surface, 3,415 TVD)
Planned BOP test pressure
Rams test to 5,000 psi / 250 psi (Initial)
Rams test to 3,600 psi / 250 psi (Subsequent)
Annular test to 3,000 psi / 250 psi
(Test pressure driven by annular pressure during frac job)
Integrity Test 12-1/4 hole
FIT after drilling 20-50 of new hole to 14.0 ppg.
(12.8 ppg LOT required for Kick Tolerance with 11.5ppg MW)
13-3/8 Casing Test 2,600 psi surface pressure
(Test pressure driven by 50% of Casing Burst)
8-1/2 Intermediate #2 Hole Pressure Data
Maximum anticipated BHP 1,861 psi in the Nanushuk 3 at 4,066 TVD
(8.8ppg EMW Nanushuk 3 formation to section TD)
Maximum surface pressure 1,455 psi from the Nanushuk 3
(0.10 psi/ft gas gradient to surface, 4,066 TVD)
Planned BOP test pressure
Rams test to 3,600 psi / 250 psi
Annular test to 3,000 psi / 250 psi
(Test pressure driven by annular pressure during frac job)
Integrity Test 8-1/2 hole
FIT after drilling 20-50 of new hole to 14.0 ppg.
(11.4 ppg LOT required for Kick Tolerance with 10.5ppg MW)
9-5/8 Liner Test 4,000 psi surface pressure (MIT-IA after upper completion
run, test pressure driven by annular pressure during frac job)
6-1/8 Production Hole Pressure Data
Maximum anticipated BHP 1,892 psi in the Nanushuk 3.2 at 4,134 TVD
(8.8ppg EMW top NT3.2 formation to heel target)
Maximum surface pressure 1,479 psi from the NT3.2
(0.10 psi/ft gas gradient to surface, 4,134 TVD)
Planned BOP test pressure
Rams test to 3,600 psi / 250 psi
Annular test to 3,000 psi / 250 psi
(Test pressure driven by annular pressure during frac job)
Integrity Test 6-1/8 hole
FIT after drilling 20-50 of new hole to 14.0 ppg.
(10.5ppg required for infinite kick tolerance with 9.8ppg MW)
7 Liner Test 4,000 psi surface pressure (MIT-IA after upper completion
run, test pressure driven by annular pressure during frac job)
(B) data on potential gas zones; and
The Tuluvak formation is expected in this area and has a high potential for gas as based on offset
Exploration and Appraisal well data. The Tuluvak is expected to be over-pressured at 10.2ppg pore
pressure. The well plan is designed to safely manage pressures consistent with offset wells in the
same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before
entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient
overbalance.
(C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost
circulation zones, and zones that have a propensity for differential sticking;
Please refer to Attachment 4: Drilling Hazards
5. Procedure for Conducting Formation Integrity Tests
20 AAC 25.005 (c) (5)
A description of the procedure for conducting formation integrity tests, as required under 20 AAC
25.030(f);
Please refer to Attachment 5: Leak Off Test Procedure
6. Casing and Cementing Program
20 AAC 25.005 (c) (6)
A complete proposed casing and cementing program as required by 20 AAC 25.030, and a
description of any slotted liner, pre-perforated liner, or screen to be installed;
Casing/Tubing Program
Hole Size Liner /
Tbg O.D.Wt/Ft Grade Conn Length Top
MD
Bottom
MD / TVD
42 20x34215# X-52 Welded 80Surface 128 / 128
16 13-3/868# L-80 TXP BTC 2,912Surface 2,912 / 2,405
12-1/4 9-5/847# L-80 HYD 563 8,738 2,762 11,500 / 3,415
Tie Back 9-5/847# L-80 HYD 563 2,762Surface 2,762 / 2,337
8-1/2 x
9-7/87 26 L-80 HYD 563 4,39111,350 15,741 / 4,066
6-1/8 4-1/212.6# P-110S HYD 563 9,98615,591 25,577 / 4,126
Tubing 4-1/212.6# P-110S HYD 563 15,591Surface 15,591 / 4,024
Please refer to Attachment 6: Cement Summary for further details.
7. Diverter System Information
20 AAC 25.005 (c) (7)
A diagram and description of the diverter system as required by 20 AAC 25.035, unless this
requirement is waived by the commission under 20 AAC 25.035(h)(2);
Nabors 272 Diverter Equipment:
Hydril MSP annular BOP, 21 1/4 x 2000 psi, flanged
Diverter Spool 21 1/4 x 2000 psi with 16-3/4 flanged sidearm connection. Interlocked
knife/gate valves.
16 Diverter Line.
Please refer to Attachment 3: BOPE Equipment for further details.
A diverter variance is requested for NDB-039. Please refer to Section 15 for further details.
8. Drilling Fluid Program
20 AAC 25.005 (c) (8)
A drilling fluid program, including a diagram and description of the drilling fluid system, as required
by 20 AAC 25.033;
Drilling Fluid Program Summary
16 Surface Hole 12-1/4
Int #1 Hole
8-1/2
Int #2 Hole
6-1/8
Prod Hole
Mud Type Spud Mud (WBM)MOBM MOBM MOBM
Mud Properties:
Mud Weight
Funnel Vis
PV
YP
API Fluid Loss
HPHT Fluid Loss
pH
MBT
9.0 - 10 ppg
100 - 300 sec
ALAP
30 - 80
< 10 ml/30min
n/a
8.6-10.5
<35
11.0 - 12.0 ppg
50 - 80 sec
ALAP
15 - 30
n/a
< 5 ml/30min
n/a
n/a
9.5 - 12.0 ppg
50 - 80 sec
ALAP
15 - 30
n/a
< 5 ml/30min
n/a
n/a
7.5 - 10.0 ppg
(>9.0ppg via MPD)
50 - 80 sec
ALAP
10 - 20
n/a
< 5 ml/30min
n/a
n/a
A diagram of drilling fluid system on Nabors 272 is on file with AOGCC.
9. Abnormally Pressured Formation Information
20 AAC 25.005 (c) (9)
For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted
abnormally geo-pressured strata as required by 20 AAC 25.033(f);
N/A Application is not for an exploratory or stratigraphic test well.
10. Seismic Analysis
20 AAC 25.005 (c) (10)
For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required
by 20 AAC 25.061(a);
N/A Application is not for an exploratory or stratigraphic test well.
11. Seabed Condition Analysis
20 AAC 25.005 (c) (11)
For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or
floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b);
The NDB-039 well is to be drilled from an onshore location.
12. Evidence of Bonding
20 AAC 25.005 (c) (12)
Evidence showing that the requirements of 20 AAC 25.025 have been met;
Evidence of bonding for Oil Search Alaska is on file with the Commission.
13. Proposed Drilling Program
20 AAC 25.005 (c) (13)
A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for
hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic
fracturing, a person must make a separate request by submitting an Application for Sundry
Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283;
The proposed drilling program to NDB-039 is listed below. Please refer to Attachments 8-10 for a
Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram.
Proposed NDB-039 Drilling Program
1. Drill 20 conductor to ~128 MD/TVD. Cement to surface. Install Cellar and landing ring on
conductor.
2. Move in / rig up Nabors 272.
3. Nipple up spacer spools over the 20 conductor.
4. Pick up 5-7/8 drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make
up 16 motor BHA with MWD and LWD tools.
5. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate
and condition hole to run casing. POOH and lay down BHA.
6. Run 13-3/8 68# surface casing as per casing tally and land on pre-installed landing ring.
Circulate and condition mud prior to commencing cement job.
7. Cement 13-3/8 casing as per cement program. Verify cement returns to surface.
8. NU casing head and spacer spool. NU BOPE with Rotating Control Device (RCD). BOP
configured from top to bottom: annular preventor, 4-1/2 x 7 VBR, blind/shear, mud
cross, 9-5/8 Fixed Rams. Test rams to 5000 psi high (initial test only 3600 psi for
subsequent tests) and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC
48 hrs notice for witnessing BOP test.
9. Close blind shear rams and pressure test casing to 2600 psi for 30 min.
10. Make up 12-1/4 RSS BHA with MWD and LWD tools. RIH, clean out to top of float
equipment and displace well to MOBM.
11. Drill out shoe track and 20 - 50 of new formation. Perform FIT / LOT.
12. Directionally drill 12-1/4 intermediate hole section #1 to TD. Circulate and condition hole
to run liner. POOH.
13. RU and run 9-5/8 intermediate liner #1 as per casing tally then RIH on 5-7/8 DP / HWDP
to TD. Circulate and condition mud prior to commencing cement job.
14. Set liner hanger and release running tool. Cement 9-5/8 liner with 1st stage cement job
as per cement program. Monitor returns during displacement until plug bump.
15. Un-sting from liner hanger and POOH and LD liner running tools.
16. RIH with mechanical shifting tool and open 2
nd stage cement job tools. Pump secondary
cement job, set liner top packer, and circulate cement to surface. POOH and lay down 5-
7/8 drillpipe and liner running tool.
17. RIH with polish mill assembly for cleanout of the 9-5/8 liner top PBR. Run 9-5/8 tieback
string. Freeze protect the 13-3/8 x 9-5/8 annulus with diesel and land tieback. Pressure
test the 13-3/8 x 9-5/8 annulus to 2600 psi for 30 min.
a. NOTE: 9-5/8 tieback may be run after installing the 7 liner, subject to further
detailed engineering analysis.
18. Pressure test 9-5/8 liner/tieback to 3500 psi for 30 min or pressure test 13-3/8 casing
and 9-5/8 liner to 2600 psi for 30 min (dependent on order of 9-5/8 tieback installation).
19. Make up 8-1/2 RSS BHA with MWD and LWD tools. RIH on 5 drillpipe, clean out to top of
float equipment and drill out the shoe track.
20. Drill out the 9-5/8 shoe and 20 - 50 of new formation. Perform FIT / LOT.
21. Install the MPD bearing assembly and adjust mud weight as required for ECD management
with MPD.
22. Directionally drill 8-1/2 x 9-7/8 intermediate hole section #2 to TD utilizing MPD.
23. Circulate and condition hole to run liner. Displace weighted trip fluid as required and
POOH.
24. Run cleanout/string mill assembly to dress the 9-5/8 CFLEX tool.
25. RU and run 7 intermediate liner #2 as per casing tally then RIH on 5 DP / HWDP to TD.
Circulate and condition mud prior to commencing cement job.
26. Set liner hanger and release running tool. Cement 7 liner as per cement program.
Monitor returns during displacement until plug bump.
27. Set liner top packer, un-sting from liner hanger, POOH and LD liner running tools.
28. Change upper BOP rams from 4-1/2 x 7 VBRs to 3-1/2 x 5-1/2 VBRs. Test rams to 3600
psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 24hrs
notice for witnessing BOP test.
29. Pressure test the 9-5/8 liner / tieback and 7 liner to 3500 psi for 30 min.
30. Make up 6-1/8 RSS BHA with MWD and LWD tools. RIH on tapered string with 4 x 5
drillpipe.
31. RIH to top of the float equipment logging 7 liner cement with Sonic LWD tool tripping in.
32. Displace well to MOBM at the required mud weight for MPD while drilling out the shoe
track.
33. Circulate casing clean, install the MPD bearing assembly and test MPD surface equipment
as required.
34. Drill 20 - 50 of new formation. Perform FIT / LOT.
35. Directionally drill 6-1/8 production hole section to TD using MPD.
36. Circulate and condition hole to run liner. Displace weighted trip fluid as required and
POOH.
37. RU and run 4-1/2 production liner as per tally then RIH on tapered 4 x 5 DP to TD.
Perform cement log across 7" liner on trip out of hole. See conditions of approval. -bjm
38. Drop 1.125 ball and circulate to close WIV. Close WIV collar and set liner hanger/top
packer.
39. Pressure test the 9-5/8 x 7 x 4-1/2 IA to liner top packer to 3,500 psi for 10 min.
Release the running tool.
40. Circulate 9.2ppg viscosified brine with Lube 776 and SafeLube at 10 bpm.
41. POOH and LD liner running tool.
42. RU and run 4-1/2 upper completion and downhole jewelry with TEC wire. Space out
seals.
43. Circulate 9.2ppg NaCl Brine with corrosion inhibitor and biocide. Land tubing hanger.
44. Pressure test tubing to 3,500 psi for 30 mins. Pressure up on the annulus to 4,000 psi for
30 mins. Bleed pressure on tubing and shear upper gas lift valve.
45. Reverse circulate freeze protect and U-Tube.
46. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree.
47. Secure well and prepare for rig move.
14. Discussion of Mud and Cuttings Disposal and Annular Disposal
20 AAC 25.005 (c) (14)
A general description of how the operator plans to dispose of drilling mud and cuttings and a
statement of whether the operator intends to request authorization under 20 AAC 25.080 for an
annular disposal operation in the well.
The Oil Search Alaska NGI (Nanushuk Grind & Inject) facility is now operational, and cuttings will be
hauled via truck as generated, processed at NGI, and disposed of into the DW-02 Class 1 disposal
well. The NGI facility is located on NDB.
In the event that NGI is not operational, water-based and oil-based drilling muds and cuttings will
typically be hauled directly offsite via truck as it is generated. Contractual arrangements have been
made with other operators on the North Slope to utilize their waste injection/disposal facilities
(Class 1 and Class 2) at Prudhoe Bay, Kuparuk and Milne Point. If waste cannot be hauled directly
offsite, it may be stored temporarily in drilling waste cuttings bins or a bermed cuttings storage cell
in accordance with a drilling waste temporary storage plan approved by Alaska Department of
Conservation (ADEC) Solid Waste Program until it can be transported for proper disposal.
There is no intention to request authorization under 20 AAC 25.080 for any annular disposal
operation in the well.
15. Proposed Variance Requests
20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention
equipment and diverter requirements.
(h)(2) from the diverter system requirements in (c) of this section if the variance provides at least
equally effective means of diverting flow away from the drill rig or if drilling experience in the near
vicinity indicates that a diverter is not necessary
A diverter variance is requested for the NDB-039 surface hole section. Oil Search Alaska, LLC (OSA)
has conducted internal risk assessments and determined that the risk of needing to use a diverter
is negligible and operationally could pose an increase in HSE risks. NDB-039 surface hole is
surrounded by more than 20 other existing surface holes at the NDB pad location. Additionally,
there are 5 previously drilled wells (NDB-027, NDB-032, NDBi-034, NDB-037, and NDBi-044) within
600 of the proposed NDB-039 surface hole TD location (see attachment 11).
More than 36 wells have been drilled in the NDB pad and Pikka area over the last 54 years with no
signs or indications of shallow free gas above the Tuluvak, including 16 Exploration and Appraisal
wells and more than 20 NDB Pad wells. In addition, OSA has acquired eight openhole logs across
the surface hole intervals in the area consisting of four E-line Density Neutron logs and four LWD
Sonic logs. All logs definitively show no free gas accumulations.
During this time period, there have been zero well control events above the Tuluvak. OSA has built
highly detailed geological models which predict the Top of the Tuluvak with very high
accuracy. There is very low structural uncertainty and a high confidence marker with the MCU
given the number of wells already drilled in the area. The area around NDB is covered by 3D
seismic data that was acquired in 2010 and reprocessed in 2023. The data is of adequate quality
without gaps and obvious noise trains or shallow velocity anomalies. The smallest detectable and
mapped faults in the surrounding area is estimated to be 20-30. There are no observed faults in
the vicinity of this hole section for the NDB-039 well.
NDB-039 surface casing will target a maximum setting depth of 250 TVD below the MCU marker to
maintain a 100 TVD standoff from the gas-bearing Tuluvak sand formation.
OSA will implement drilling practices to effectively manage any hydrates encountered while drilling
surface hole as follows: (1) Mitigate breakout potential: keep mud temperature cool, no extended
circulation at any point in the well, optimized drilling and tripping strategies, utilization of GWD to
minimize stationary time. (2) Identify hydrates (i.e. bubbles in the flow both with no signs of pit
gain or flow from the well). (3) Handle hydrates at surface (i.e. utilization of degasser and isolation
of gas-cut mud in the pits). (4) Drilling practices (i.e. controlling pump rates and maximizing ROP to
get through a hydrate zone).
Nabors Rig 272's current elevated diverter rig-up introduces health, safety, and environmental
(HSE) risks due to the complexities of installation at height. With the ongoing facility
commissioning at NDB pad, the diverter line will need to be moved to ground level in the near
future to be routed beneath the flowlines and pipe racks, passing through support pilings. This
change will increase operational challenges and HSE risks, as the 75-foot diverter line will require
multiple bends to navigate around existing equipment and infrastructure.
With the multiple well penetrations at the NDB Pad and Pikka area, no free gas above the Tuluvak,
the strong geologic understanding, and low structural uncertainty, combined with the increased
HSE risks and challenges of running a diverter line, it is requested that a diverter variance for
NDB-039 be granted.
20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention
equipment and diverter requirements.
(e)(10)(A) when installed, repaired, or changed on a development or service well and at time
intervals not to exceed each 14 days thereafter, BOPE, including kelly valves, emergency valves, and
choke manifolds, must be function pressure-tested to the required working pressure specified in the
approved Permit to Drill, using a non-compressible fluid, except that an annular type preventer
need not be tested to more than 50 percent of its rated working pressure; however, the commission
will require that the BOPE be function pressure-tested weekly, if the commission determines that a
weekly BOPE pressure test interval is indicated by a particular drilling rig's BOPE performance
A 21-day BOPE test schedule is planned as per the waiver acceptance letter and conditional
requirements outlined in Docket Number OTH-25-010 from the AOGCC to Oil Search Alaska for
Nabors 272 operating at NDB (see attachment 12).
20 AAC 25.030. Casing and cementing
(d)(5) intermediate and production casing must be cemented with sufficient cement to fill the
annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true
vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo-
pressured strata or, if zonal coverage is not required under (a) of this section, from the casing shoe
to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater,
above the casing shoe
Recommend approving diverter variance. -A.Dewhurst 06JAN25
A variance is requested to the above regulation 20 AAC 25.030 (d)(5) for the following:
1. 9-5/8 Primary Cement Job:
The primary cement job will target a top of cement 1000 feet MD (~100 feet TVD at ~84°
inclination) above the 9-5/8 shoe. Due to ERD nature of this section, additional TVD height of
the cement top will significantly increase cement volumes and the subsequent risk of losses
due to ECDs exceeding the formation fracture gradient.
Note, with this well design the 9-5/8 is considered as an intermediate drilling liner and the
shoe is not designed to isolate any significant hydrocarbon zones or abnormally geo-pressured
strata. Isolation over the top of the Nanushuk formation will be provided by cement integrity
at the subsequent 7 liner shoe.
2. 9-5/8 Secondary Cement Job:
To not place cement across the entire annular space from the 9-5/8 shoe to above shallowest
significant hydrocarbon zone. A two-stage cement job will be performed to isolate the shoe in
the Seabee, and the second stage cement job will isolate the significant hydrocarbon zone in
the Tuluvak formation. Due to the ERD nature and high angle of the Pikka NDB development
wells, a single stage cement job on the 9-5/8 intermediate liner is not achievable without
exceeding the fracture gradient and compromising cement placement and zonal isolation.
The two-stage cement job will achieve all casing and cementing objectives outlined in AOGCC
regulation 20 AAC 25.030.(a), stating that a well casing and cementing program must be
designed to:
1) provide suitable and safe operating conditions for the total measured depth proposed;
2) confine fluids to the wellbore;
3) prevent migration of fluids from one stratum to another;
4) ensure control of well pressures encountered;
5) protect against thaw subsidence and freezeback effects within permafrost;
6) prevent contamination of freshwater;
7) protect significant hydrocarbon zones; and
8) provide well control until the next casing is set, considering all factors relevant to well
control including formation fracture gradients, formation pressures, casing setting depths,
and proposed total depth.
The formation interval between the top of stage one and the bottom of stage two includes the
Seabee and lower Tuluvak formation. These formations are interbedded silts and shales with
very low permeability and contain no significant hydrocarbons.
Based on offset well logs, cuttings, mudlogging analysis, and the latest petrophysical
interpretation, the base of the significant hydrocarbon zone in the Tuluvak formation is
contained only within the upper portion of TS 880 clinoform of the Upper Tuluvak in the NDB
area. Within the TS 880 clinoform, the base of significant hydrocarbon is at or above 2,640
TVD. The Tuluvak formation below 2,640 TVD is not a significant hydrocarbon zone.
A stage collar placement is proposed 50 MD below the TS 790 formation marker (Upper
Tuluvak). This stage collar depth will isolate any potential gas based on offset well data. The
TS 875 and TS 870 clinoform is between the TS 880 clinoform and TS 790 top. The TS 875 and
TS 870 clinoforms are shale dominated, very low net to gross, has no vertical permeability, and
represents a seal to the hydrocarbon bearing TS 880.
Moving the cementing stage tool to be placed at 50 MD below the TS 790 formation marker
allows placement of higher quality cement that provides better isolation across the significant
hydrocarbon zone in the Tuluvak. Attempting to place cement across the entire Tuluvak will
add risk to the primary objective of cement isolation across the significant hydrocarbon zone
which is only located in the upper portion of the Tuluvak (TS 880). The increased risk is due to:
a) Cementing the entire Tuluvak would require large cement jobs that jeopardize cement
isolation across the upper Tuluvak.
b) Large cement jobs likely require the use of lighter weight cement across the significant
hydrocarbon zone.
3. 7 Liner Cement Job:
The 7 liner cement job will target a top of cement 200 feet TVD above the top of the
Nanushuk formation. Due to ERD nature of this section (inclination 74-84°), additional TVD
height of the cement top will significantly increase cement volumes and the subsequent risk of
losses due to ECDs exceeding the formation fracture gradient.
Additionally, the 200 feet TVD above the top of the Nanushuk is targeted to:
a) Provide additional cement coverage above the topmost hydrocarbon zone in the NT8. The
planned TOC is ~251 feet TVD (~1666 feet MD) above the top of the NT8. Logs within the
Pikka NDB project area have consistently shown that there are no significant hydrocarbon
zones between the top NT8 and the top Nanushuk formation.
b) Allow the use of a single heavier tail slurry to provide the improved cement integrity and
isolation across the top of the Nanushuk. Note, improved cement bond log quality has
generally been observed with heavier weight tail slurries.
c) Minimize the operational risk of cement returns up into the 9-5/8 shoe and above the
top of the 7 liner hanger.
Additional cement volume / excess may be pumped to help ensure the targeted top of cement
is achieved based on detailed cement modelling or operational conditions (i.e. lost circulation,
low fracture gradient or excessive washout) observed prior to execution of the cement job.
20 AAC 25.033. Primary well control for drilling: drilling fluid program and drilling fluid system.
(b)(1)(A) A drilling fluid of sufficient density to overbalance the pressure of uncased formations
penetrated
A variance is requested to the above regulation 20 AAC 25.033 (b)(1)(A) for drilling fluid density in
the production hole only. Due to the ERD nature of these wells, staying under the ECD limit of
13.5ppg has become extremely difficult to manage. Exceeding the 13.5ppg ECD limit greatly
increases the risk of lost circulation and further increases the risk of unsuccessful well execution.
A ~7.5-8.0ppg mud weight will be used with Managed Pressure Drilling (MPD). MPD will be utilized
to drill the production hole while being statically and dynamically overbalanced to the Nanushuk
formation by holding back pressure on connections and while drilling (if needed). A 9.1-10.0ppg
fluid will be circulated in the hole prior to tripping.
Two independent barriers will be maintained throughout the operations:
6-1/8 Drilling: (1) RCD and MPD choke (2) BOP stack
6-1/8 Tripping and 4-1/2 Liner Run: (1) 9.5-10.0ppg mud (2) BOP stack
The Pikka development at NDB pad has well established pore pressures with active monitoring via
downhole pressure gauges. The target interval is an oil reservoir with limited formation
permeability.
The MPD choke will be set up to automatically trap pressure on connections, or anytime the mud
pump is stopped. The choke pressure will be set to maintain a constant bottom hole pressure.
The MPD chokes will prevent a sudden drop in surface pressure if the pumps are stopped
suddenly.
MPD equipment has been installed and in use on the rig since October 2024. The rig crews are
familiar with the equipment and communication between the rig crew and MPD technicians have
been excellent. There is an additional driller responsibility to notify the MPD technician of a
change in pump rate, however, this is a courtesy notification as the MPD system will automatically
trap pressure when the pump is shut down.
The MPD provider (Beyond Energy Services) has extensive experience utilizing the MPD system to
drill dynamically overbalanced. Beyond has established procedures and contingency plans in place
fit for purpose for the Nabors 272 rig to ensure that sufficient surface pressure is kept on the well
to maintain overbalanced to the Nanushuk formation.
All influxes to be circulated out per conventional well kill protocols. Rig crew to monitor flow and
pit levels per standard operations. Rig crew to shut in per standard operations (no change to
standing orders). Influx will be managed conventionally with closed BOP and slow pump rate.
Attachments
Attachment 1: Location Map
Attachment 2: Directional Plan
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 47.0 0.00 0.00 47.0 0.0 0.0 0.00 0.00 0.0
2 347.0 0.00 0.00 347.0 0.0 0.0 0.00 0.00 0.0
3 998.7 16.29 310.00 990.0 59.2 -70.5 2.50 310.00 92.0
4 1148.7 16.29 310.00 1134.0 86.2 -102.8 0.00 0.00 134.1
5 2660.0 61.00 290.00 2288.0 469.2 -931.0 3.04 -24.62 1017.7
6 2760.0 61.00 290.00 2336.5 499.1 -1013.1 0.00 0.00 1100.3
7 3528.5 83.89 287.09 2566.8 729.4 -1703.5 3.00 -7.42 1780.5
813884.3 83.89 287.09 3669.3 3754.6-11546.0 0.00 0.0011315.2
915576.2 73.70 337.92 4020.0 4825.0-12734.0 3.00 106.0812912.5
1015747.1 73.70 337.92 4068.0 4977.1-12795.7 0.00 0.0013056.5
1116214.2 90.05 337.92 4133.8 5404.1-12968.9 3.50 0.0013460.9 NDB-039 Heel Rev 3.0
1220998.6 90.05 337.92 4129.8 9837.6-14767.4 0.00 0.0017659.5 Mid Point Azimuth Change Rev 2.0
1321332.1 90.05 331.25 4129.5 10138.6-14910.5 2.00 -89.9817960.8
1425576.9 90.05 331.25 4125.8 13860.2-16952.2 0.00 0.0021897.1 NDB-039 Toe Rev 4.0
47 500
500 1000
1000 1500
1500 2000
2000 2500
2500 3000
3000 5000
5000 6000
6000 7000
7000 8000
8000 9000
9000 10000
10000 12000
12000 14000
14000 16000
16000 18000
18000 20000
20000 25000
Plan: NDB-039 Rev H.0 Plan Summary
0
3
0 4000 8000 12000 16000 20000 24000
Measured Depth
20" Conductor Driven
13-3/8" Surface Casing
9-5/8" Intermediate Liner 4-1/2" Production Liner
45
45
90
90
0
90
180
270
30
210
60
240 120
300
150
330
Highside Toolface Angle [°] vs Travelling Cylinder Separation [90 usft/in]
475075100125150175200225250275300325
3503754004254504755005255505756006256506757007257507758008258508759009259509751000102510501075110011251150117512001225
125012751300132513501375140014111425145014751500152515501575160016251650167517001725175017751800182518501875190019251950Plan: NDBi-034 Rev M.0
475075100125150175200225250275300325327
350375400425450475500525550575600625650675700725750NDB-035 Slot Saver
475075100125150175200225250
275300325
350375400425450475499500525550575600625650675700725750775800825850875NDBi-036
475075100125150175200225250275300325
350375400400425450475500525550575600625
6506757007257507758008258508759009259509751000102510501075110011251150117512001225125012751300132513501375140014251450147515001525155015751600162516501675170017251750177518001825185018751900192519501975200020252050207521002125215021752200222522502275230023252350237524002425245024752500NDB-037
475075100125150175200225250275300325327
350375400425450475500525550575600625650675700725750775800825850Plan: NDBi-038 Rev A.0
5075100125150175200225250275300
325
350375400425450475500525550575600625650675700725750775800825850NDB-040
475075100125150175200225250275300325
350375400425450475500525550575600625650675700725750775800825850875900925950975100010061025105010751100112511501175120012251250126812751300132513501375140014251450147515001525155015751600162516501675170017251750177518001825185018751900192519501975200020252050207521002125215021752200222522502275230023252350237524002425245024752500252525502575260026252650
Plan: NDBi-041 Rev C.0
475075100125150175200225250275292300325
350375400425450475500525550575600625650675700725750775800825850875900925950975100010251050107511001125115011751200122512501275130013251350137514001425145014751500152515501575160016251650167517001725
175017751800182518501875
NDB-042 Rev E.0
475075100125150175200225250275300325
350375400425450475500525550575600625650675675700725750775800825850875
900NDBi-043
475075100125150175200225250275300325
350375400425450475500525550575600625650675675700725750775800825850875
900NDBi-043A
475075100125150175200225
250275300325
350375400425450475500525
550575600625650675700725750775800825850875900925950975100010251050107511001125113211501175120012251250127513001325135013751400142514501475150015251550157516001625NDBi-044
0
2250
0 3000 6000 9000 12000 15000 18000 21000
Vertical Section at 309.27°
20" Conductor Driven
13-3/8" Surface Casing
9-5/8" Intermediate Liner
7" Intermediate Liner 4-1/2" Production Liner
0
28
55
0 275 550 825 1100 1375 1650 1925
Measured Depth
Equivalent Magnetic Distance
DDI
7.500
SURVEY PROGRAM
Date: 2021-02-16T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
47.0 2000.0 Plan: NDB-039 Rev H.0 (NDB-039)SDI_URSA+SAG
2000.0 2912.0 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
2912.0 11500.0 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
11500.0 15741.0 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
15741.0 25576.9 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
Surface Location
North / 5972463.03
East / 1562012.75
Elevation / 22.8
CASING DETAILS
TVD MD
Name
128.0 128.020" Conductor Driven
2404.8 2912.013-3/8" Surface Casing
3415.4 11500.09-5/8" Intermediate Liner
4066.3 15741.07" Intermediate Liner
4125.8 25576.94-1/2" Production Liner
Mag Model & Date: BGGM2025 28-Feb-26
Magnetic North is 13.33° East of True North (Magnetic Decl
Mag Dip & Field Strength: 80.51° 57085.49280928nT
FORMATION TOP DETAILS
TVDPathFormation
1032.8 Upper SB
1153.8Base Ice Bearing Permafrost
1384.8Base Permafrost
1749.8 MSB
2154.8 MCU
2445.8 Tuluvak
2507.8Tuluvak S
2812.8 TS_790
3363.8 Seabee
3804.8Nanushuk
3855.8NT8 MFS
3904.8NT7 MFS
3941.8NT6 MFS
3982.8NT5 MFS
4029.8NT4 MFS
4065.8NT3 MFS
4081.8NT3.2 Top Res.
By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiisfor the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance.
Prepared by Checked by
BHI DE
Accepted by
BHI PSD
Approved by
Santos DE
Parker 272 @ 69.8usft
Standard Planning Report - Geographic
12 December, 2025
Plan: Plan: NDB-039 Rev H.0
Santos NAD27 Conversion
Pikka
NDB
B-39
NDB-039
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Pikka, North Slope Alaska, United States
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Site Position:
From:
Site
Latitude:
Longitude:
Position Uncertainty:
Northing:
Easting:
NDB
Map
Slot Radius:0.9 usft
usft
usft
"
5,972,909.31
423,383.61
36
70° 20' 10.134 N
150° 37' 17.794 W
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
+E/-W
+N/-S
Position Uncertainty Ground Level:
B-39
Wellhead Elevation:0.5
0.0
0.0
5,972,715.04
421,979.94
0.0
70° 20' 8.081 N
150° 37' 58.730 W
22.8
usft
usft
usft
usft
usft
usft usft
°-0.60Grid Convergence:
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
NDB-039
Model NameMagnetics
IGRF2000 31/12/2004 24.73 80.61 57,282.27508754
Phase:Version:
Audit Notes:
Design Plan: NDB-039 Rev H.0
PLAN
Vertical Section: Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:47.0
309.270.00.047.0
Plan Survey Tool Program
RemarksTool NameSurvey (Wellbore)
Date 12/12/2025
Depth To
(usft)
Depth From
(usft)
SDI_URSA+SAG
SDI URSA gyroMWD + SAG
Plan: NDB-039 Rev H.0 (NDB-03147.0 2,000.0
3_MWD+IFR2+MS+Sag
A013Mb: IIFR dec & multi-s
Plan: NDB-039 Rev H.0 (NDB-0322,000.0 2,912.0
3_MWD+IFR2+MS+Sag
A013Mb: IIFR dec & multi-s
Plan: NDB-039 Rev H.0 (NDB-0332,912.0 11,500.0
3_MWD+IFR2+MS+Sag
A013Mb: IIFR dec & multi-s
Plan: NDB-039 Rev H.0 (NDB-03411,500.0 15,741.0
3_MWD+IFR2+MS+Sag
A013Mb: IIFR dec & multi-s
Plan: NDB-039 Rev H.0 (NDB-03515,741.0 25,576.8
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 2
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
TFO
(°)
+N/-S
(usft)
Measured
Depth
(usft)
Vertical
Depth
(usft)
Dogleg
Rate
(°/100usft)
Build
Rate
(°/100usft)
Turn
Rate
(°/100usft)
Plan Sections
Target
0.000.000.000.000.00.047.00.000.0047.0
0.000.000.000.000.00.0347.00.000.00347.0
310.000.002.502.50-70.559.2990.0310.0016.29998.7
0.000.000.000.00-102.886.21,134.0310.0016.291,148.7
-24.62-1.322.963.04-931.0469.22,288.0290.0061.002,660.0
0.000.000.000.00-1,013.1499.12,336.5290.0061.002,760.0
-7.41-0.382.983.00-1,703.4729.52,566.7287.0983.893,528.4
0.000.000.000.00-11,545.73,755.23,669.3287.0983.8913,884.2
106.083.00-0.603.00-12,733.64,825.64,020.0337.9273.7015,576.0
0.000.000.000.00-12,795.34,977.74,068.0337.9273.7015,746.9
0.000.003.503.50-12,968.55,404.74,133.8337.9290.0516,214.0 NDB-039 Heel Rev
90.000.000.000.00-14,766.69,838.44,129.8337.9390.0520,998.4 Mid Point Azimuth C
-89.98-2.000.002.00-14,909.710,139.64,129.5331.2590.0521,332.1
0.000.000.000.00-16,951.113,861.24,125.8331.2590.0525,576.8 NDB-039 Toe Rev 4
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 3
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)Latitude Longitude
Planned Survey
Vertical
Depth
(usft)
47.0 0.00 47.0 0.0 0.00.00 421,979.945,972,715.04 70° 20' 8.081 N 150° 37' 58.730 W
100.0 0.00 100.0 0.0 0.00.00 421,979.945,972,715.04 70° 20' 8.081 N 150° 37' 58.730 W
128.0 0.00 128.0 0.0 0.00.00 421,979.945,972,715.04 70° 20' 8.081 N 150° 37' 58.730 W
20" Conductor Driven
200.0 0.00 200.0 0.0 0.00.00 421,979.945,972,715.04 70° 20' 8.081 N 150° 37' 58.730 W
300.0 0.00 300.0 0.0 0.00.00 421,979.945,972,715.04 70° 20' 8.081 N 150° 37' 58.730 W
347.0 0.00 347.0 0.0 0.00.00 421,979.945,972,715.04 70° 20' 8.081 N 150° 37' 58.730 W
400.0 1.33 400.0 0.4 -0.5310.00 421,979.475,972,715.44 70° 20' 8.085 N 150° 37' 58.744 W
500.0 3.83 499.9 3.3 -3.9310.00 421,976.065,972,718.37 70° 20' 8.113 N 150° 37' 58.845 W
600.0 6.33 599.5 9.0 -10.7310.00 421,969.355,972,724.12 70° 20' 8.169 N 150° 37' 59.042 W
700.0 8.83 698.6 17.4 -20.8310.00 421,959.345,972,732.70 70° 20' 8.252 N 150° 37' 59.337 W
800.0 11.33 797.1 28.7 -34.2310.00 421,946.065,972,744.08 70° 20' 8.363 N 150° 37' 59.729 W
900.0 13.83 894.6 42.7 -50.9310.00 421,929.535,972,758.24 70° 20' 8.501 N 150° 38' 0.216 W
998.7 16.29 990.0 59.2 -70.5310.00 421,910.055,972,774.94 70° 20' 8.663 N 150° 38' 0.790 W
1,000.0 16.29 991.2 59.4 -70.8310.00 421,909.795,972,775.16 70° 20' 8.665 N 150° 38' 0.797 W
1,043.3 16.29 1,032.8 67.2 -80.1310.00 421,900.555,972,783.08 70° 20' 8.742 N 150° 38' 1.069 W
Upper Schrader Bluff
1,100.0 16.29 1,087.2 77.4 -92.3310.00 421,888.485,972,793.42 70° 20' 8.842 N 150° 38' 1.425 W
1,148.7 16.29 1,134.0 86.2 -102.8310.00 421,878.105,972,802.32 70° 20' 8.929 N 150° 38' 1.731 W
1,169.4 16.87 1,153.8 90.0 -107.3309.10 421,873.595,972,806.12 70° 20' 8.966 N 150° 38' 1.864 W
Base Ice Bearing Permafrost
1,200.0 17.72 1,183.0 95.6 -114.4307.87 421,866.535,972,811.85 70° 20' 9.021 N 150° 38' 2.072 W
1,300.0 20.56 1,277.5 114.9 -140.9304.55 421,840.265,972,831.42 70° 20' 9.211 N 150° 38' 2.845 W
1,400.0 23.44 1,370.2 135.4 -172.2302.01 421,809.145,972,852.25 70° 20' 9.413 N 150° 38' 3.760 W
1,416.0 23.91 1,384.8 138.8 -177.7301.66 421,803.725,972,855.69 70° 20' 9.446 N 150° 38' 3.919 W
Base Permafrost Transition
1,500.0 26.36 1,460.9 157.1 -208.3300.00 421,773.275,972,874.27 70° 20' 9.626 N 150° 38' 4.815 W
1,600.0 29.30 1,549.3 179.8 -249.1298.37 421,732.755,972,897.42 70° 20' 9.849 N 150° 38' 6.005 W
1,700.0 32.26 1,635.2 203.6 -294.4297.01 421,687.685,972,921.64 70° 20' 10.083 N 150° 38' 7.329 W
1,800.0 35.22 1,718.3 228.3 -344.2295.85 421,638.215,972,946.85 70° 20' 10.326 N 150° 38' 8.781 W
1,838.8 36.38 1,749.8 238.1 -364.6295.45 421,617.865,972,956.88 70° 20' 10.422 N 150° 38' 9.379 W
Middle Schrader Bluff
1,900.0 38.20 1,798.5 253.8 -398.2294.86 421,584.465,972,972.99 70° 20' 10.577 N 150° 38' 10.359 W
2,000.0 41.19 1,875.4 280.2 -456.3293.99 421,526.595,972,999.98 70° 20' 10.837 N 150° 38' 12.057 W
2,100.0 44.18 1,948.9 307.4 -518.5293.22 421,464.765,973,027.75 70° 20' 11.104 N 150° 38' 13.872 W
2,200.0 47.18 2,018.8 335.2 -584.4292.52 421,399.145,973,056.22 70° 20' 11.377 N 150° 38' 15.797 W
2,300.0 50.18 2,084.8 363.5 -653.9291.89 421,329.925,973,085.31 70° 20' 11.656 N 150° 38' 17.827 W
2,400.0 53.18 2,146.8 392.4 -726.8291.31 421,257.295,973,114.94 70° 20' 11.940 N 150° 38' 19.958 W
2,413.4 53.58 2,154.8 396.3 -736.9291.24 421,247.325,973,118.94 70° 20' 11.978 N 150° 38' 20.250 W
MCU
2,500.0 56.19 2,204.6 421.7 -803.0290.78 421,181.465,973,145.02 70° 20' 12.228 N 150° 38' 22.182 W
2,600.0 59.19 2,258.1 451.3 -882.1290.28 421,102.645,973,175.48 70° 20' 12.519 N 150° 38' 24.493 W
2,660.0 61.00 2,288.0 469.2 -931.0290.00 421,054.005,973,193.89 70° 20' 12.695 N 150° 38' 25.919 W
2,700.0 61.00 2,307.4 481.2 -963.8290.00 421,021.265,973,206.20 70° 20' 12.813 N 150° 38' 26.879 W
2,760.0 61.00 2,336.5 499.1 -1,013.1290.00 420,972.145,973,224.65 70° 20' 12.989 N 150° 38' 28.320 W
2,800.0 62.19 2,355.5 511.1 -1,046.2289.83 420,939.195,973,236.98 70° 20' 13.107 N 150° 38' 29.286 W
2,900.0 65.17 2,399.8 541.2 -1,130.6289.40 420,855.095,973,267.93 70° 20' 13.403 N 150° 38' 31.752 W
2,912.0 65.52 2,404.8 544.8 -1,140.9289.35 420,844.845,973,271.66 70° 20' 13.438 N 150° 38' 32.052 W
13-3/8" Surface Casing
3,000.0 68.14 2,439.4 571.4 -1,217.3289.00 420,768.725,973,299.02 70° 20' 13.700 N 150° 38' 34.284 W
3,017.3 68.66 2,445.8 576.6 -1,232.5288.93 420,753.585,973,304.40 70° 20' 13.751 N 150° 38' 34.728 W
Tuluvak Shale
3,100.0 71.12 2,474.2 601.6 -1,306.1288.62 420,680.325,973,330.16 70° 20' 13.997 N 150° 38' 36.875 W
3,200.0 74.10 2,504.1 631.8 -1,396.6288.25 420,590.125,973,361.26 70° 20' 14.293 N 150° 38' 39.519 W
3,213.6 74.51 2,507.8 635.9 -1,409.0288.20 420,577.735,973,365.49 70° 20' 14.333 N 150° 38' 39.883 W
Tuluvak Sand
3,300.0 77.08 2,529.0 661.8 -1,488.7287.88 420,498.385,973,392.25 70° 20' 14.588 N 150° 38' 42.209 W
3,400.0 80.06 2,548.8 691.6 -1,582.0287.53 420,405.345,973,423.02 70° 20' 14.881 N 150° 38' 44.936 W
3,500.0 83.04 2,563.5 721.1 -1,676.4287.19 420,311.265,973,453.51 70° 20' 15.171 N 150° 38' 47.693 W
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 4
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)Latitude Longitude
Planned Survey
Vertical
Depth
(usft)
3,528.4 83.89 2,566.7 729.5 -1,703.4287.09 420,284.355,973,462.11 70° 20' 15.253 N 150° 38' 48.481 W
3,600.0 83.89 2,574.4 750.4 -1,771.4287.09 420,216.565,973,483.73 70° 20' 15.459 N 150° 38' 50.468 W
3,700.0 83.89 2,585.0 779.6 -1,866.5287.09 420,121.845,973,513.93 70° 20' 15.746 N 150° 38' 53.244 W
3,800.0 83.89 2,595.7 808.8 -1,961.5287.09 420,027.125,973,544.13 70° 20' 16.033 N 150° 38' 56.020 W
3,900.0 83.89 2,606.3 838.0 -2,056.6287.09 419,932.395,973,574.33 70° 20' 16.320 N 150° 38' 58.796 W
4,000.0 83.89 2,617.0 867.2 -2,151.6287.09 419,837.675,973,604.54 70° 20' 16.607 N 150° 39' 1.572 W
4,100.0 83.89 2,627.6 896.5 -2,246.7287.09 419,742.955,973,634.74 70° 20' 16.894 N 150° 39' 4.348 W
4,200.0 83.89 2,638.2 925.7 -2,341.7287.09 419,648.225,973,664.94 70° 20' 17.181 N 150° 39' 7.125 W
4,300.0 83.89 2,648.9 954.9 -2,436.7287.09 419,553.505,973,695.14 70° 20' 17.468 N 150° 39' 9.901 W
4,400.0 83.89 2,659.5 984.1 -2,531.8287.09 419,458.775,973,725.35 70° 20' 17.755 N 150° 39' 12.677 W
4,500.0 83.89 2,670.2 1,013.3 -2,626.8287.09 419,364.055,973,755.55 70° 20' 18.042 N 150° 39' 15.453 W
4,600.0 83.89 2,680.8 1,042.5 -2,721.9287.09 419,269.335,973,785.75 70° 20' 18.329 N 150° 39' 18.229 W
4,700.0 83.89 2,691.5 1,071.8 -2,816.9287.09 419,174.605,973,815.95 70° 20' 18.616 N 150° 39' 21.006 W
4,800.0 83.89 2,702.1 1,101.0 -2,911.9287.09 419,079.885,973,846.16 70° 20' 18.903 N 150° 39' 23.782 W
4,900.0 83.89 2,712.8 1,130.2 -3,007.0287.09 418,985.155,973,876.36 70° 20' 19.190 N 150° 39' 26.558 W
5,000.0 83.89 2,723.4 1,159.4 -3,102.0287.09 418,890.435,973,906.56 70° 20' 19.477 N 150° 39' 29.335 W
5,100.0 83.89 2,734.1 1,188.6 -3,197.1287.09 418,795.715,973,936.76 70° 20' 19.764 N 150° 39' 32.111 W
5,200.0 83.89 2,744.7 1,217.9 -3,292.1287.09 418,700.985,973,966.97 70° 20' 20.051 N 150° 39' 34.887 W
5,300.0 83.89 2,755.4 1,247.1 -3,387.2287.09 418,606.265,973,997.17 70° 20' 20.338 N 150° 39' 37.664 W
5,400.0 83.89 2,766.0 1,276.3 -3,482.2287.09 418,511.535,974,027.37 70° 20' 20.625 N 150° 39' 40.440 W
5,500.0 83.89 2,776.7 1,305.5 -3,577.2287.09 418,416.815,974,057.57 70° 20' 20.912 N 150° 39' 43.217 W
5,600.0 83.89 2,787.3 1,334.7 -3,672.3287.09 418,322.095,974,087.78 70° 20' 21.199 N 150° 39' 45.993 W
5,700.0 83.89 2,797.9 1,363.9 -3,767.3287.09 418,227.365,974,117.98 70° 20' 21.486 N 150° 39' 48.770 W
5,800.0 83.89 2,808.6 1,393.2 -3,862.4287.09 418,132.645,974,148.18 70° 20' 21.773 N 150° 39' 51.546 W
5,839.5 83.89 2,812.8 1,404.7 -3,899.9287.09 418,095.215,974,160.12 70° 20' 21.886 N 150° 39' 52.643 W
TS_790
5,900.0 83.89 2,819.2 1,422.4 -3,957.4287.09 418,037.915,974,178.38 70° 20' 22.060 N 150° 39' 54.323 W
6,000.0 83.89 2,829.9 1,451.6 -4,052.4287.09 417,943.195,974,208.59 70° 20' 22.347 N 150° 39' 57.099 W
6,100.0 83.89 2,840.5 1,480.8 -4,147.5287.09 417,848.475,974,238.79 70° 20' 22.633 N 150° 39' 59.876 W
6,200.0 83.89 2,851.2 1,510.0 -4,242.5287.09 417,753.745,974,268.99 70° 20' 22.920 N 150° 40' 2.652 W
6,300.0 83.89 2,861.8 1,539.3 -4,337.6287.09 417,659.025,974,299.19 70° 20' 23.207 N 150° 40' 5.429 W
6,400.0 83.89 2,872.5 1,568.5 -4,432.6287.09 417,564.305,974,329.40 70° 20' 23.494 N 150° 40' 8.206 W
6,500.0 83.89 2,883.1 1,597.7 -4,527.7287.09 417,469.575,974,359.60 70° 20' 23.781 N 150° 40' 10.982 W
6,600.0 83.89 2,893.8 1,626.9 -4,622.7287.09 417,374.855,974,389.80 70° 20' 24.067 N 150° 40' 13.759 W
6,700.0 83.89 2,904.4 1,656.1 -4,717.7287.09 417,280.125,974,420.00 70° 20' 24.354 N 150° 40' 16.536 W
6,800.0 83.89 2,915.1 1,685.3 -4,812.8287.09 417,185.405,974,450.21 70° 20' 24.641 N 150° 40' 19.312 W
6,900.0 83.89 2,925.7 1,714.6 -4,907.8287.09 417,090.685,974,480.41 70° 20' 24.928 N 150° 40' 22.089 W
7,000.0 83.89 2,936.4 1,743.8 -5,002.9287.09 416,995.955,974,510.61 70° 20' 25.214 N 150° 40' 24.866 W
7,100.0 83.89 2,947.0 1,773.0 -5,097.9287.09 416,901.235,974,540.81 70° 20' 25.501 N 150° 40' 27.643 W
7,200.0 83.89 2,957.6 1,802.2 -5,192.9287.09 416,806.505,974,571.02 70° 20' 25.788 N 150° 40' 30.419 W
7,300.0 83.89 2,968.3 1,831.4 -5,288.0287.09 416,711.785,974,601.22 70° 20' 26.075 N 150° 40' 33.196 W
7,400.0 83.89 2,978.9 1,860.7 -5,383.0287.09 416,617.065,974,631.42 70° 20' 26.361 N 150° 40' 35.973 W
7,500.0 83.89 2,989.6 1,889.9 -5,478.1287.09 416,522.335,974,661.62 70° 20' 26.648 N 150° 40' 38.750 W
7,600.0 83.89 3,000.2 1,919.1 -5,573.1287.09 416,427.615,974,691.83 70° 20' 26.935 N 150° 40' 41.527 W
7,700.0 83.89 3,010.9 1,948.3 -5,668.2287.09 416,332.885,974,722.03 70° 20' 27.221 N 150° 40' 44.304 W
7,800.0 83.89 3,021.5 1,977.5 -5,763.2287.09 416,238.165,974,752.23 70° 20' 27.508 N 150° 40' 47.081 W
7,900.0 83.89 3,032.2 2,006.7 -5,858.2287.09 416,143.445,974,782.43 70° 20' 27.795 N 150° 40' 49.858 W
8,000.0 83.89 3,042.8 2,036.0 -5,953.3287.09 416,048.715,974,812.64 70° 20' 28.081 N 150° 40' 52.635 W
8,100.0 83.89 3,053.5 2,065.2 -6,048.3287.09 415,953.995,974,842.84 70° 20' 28.368 N 150° 40' 55.412 W
8,200.0 83.89 3,064.1 2,094.4 -6,143.4287.09 415,859.275,974,873.04 70° 20' 28.654 N 150° 40' 58.189 W
8,300.0 83.89 3,074.8 2,123.6 -6,238.4287.09 415,764.545,974,903.24 70° 20' 28.941 N 150° 41' 0.966 W
8,400.0 83.89 3,085.4 2,152.8 -6,333.4287.09 415,669.825,974,933.45 70° 20' 29.228 N 150° 41' 3.743 W
8,500.0 83.89 3,096.1 2,182.1 -6,428.5287.09 415,575.095,974,963.65 70° 20' 29.514 N 150° 41' 6.520 W
8,600.0 83.89 3,106.7 2,211.3 -6,523.5287.09 415,480.375,974,993.85 70° 20' 29.801 N 150° 41' 9.297 W
8,700.0 83.89 3,117.3 2,240.5 -6,618.6287.09 415,385.655,975,024.05 70° 20' 30.087 N 150° 41' 12.074 W
8,800.0 83.89 3,128.0 2,269.7 -6,713.6287.09 415,290.925,975,054.26 70° 20' 30.374 N 150° 41' 14.851 W
8,900.0 83.89 3,138.6 2,298.9 -6,808.7287.09 415,196.205,975,084.46 70° 20' 30.660 N 150° 41' 17.628 W
9,000.0 83.89 3,149.3 2,328.1 -6,903.7287.09 415,101.475,975,114.66 70° 20' 30.947 N 150° 41' 20.406 W
9,100.0 83.89 3,159.9 2,357.4 -6,998.7287.09 415,006.755,975,144.86 70° 20' 31.233 N 150° 41' 23.183 W
9,200.0 83.89 3,170.6 2,386.6 -7,093.8287.09 414,912.035,975,175.07 70° 20' 31.520 N 150° 41' 25.960 W
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 5
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)Latitude Longitude
Planned Survey
Vertical
Depth
(usft)
9,300.0 83.89 3,181.2 2,415.8 -7,188.8287.09 414,817.305,975,205.27 70° 20' 31.806 N 150° 41' 28.737 W
9,400.0 83.89 3,191.9 2,445.0 -7,283.9287.09 414,722.585,975,235.47 70° 20' 32.093 N 150° 41' 31.515 W
9,500.0 83.89 3,202.5 2,474.2 -7,378.9287.09 414,627.855,975,265.67 70° 20' 32.379 N 150° 41' 34.292 W
9,600.0 83.89 3,213.2 2,503.5 -7,474.0287.09 414,533.135,975,295.88 70° 20' 32.666 N 150° 41' 37.069 W
9,700.0 83.89 3,223.8 2,532.7 -7,569.0287.09 414,438.415,975,326.08 70° 20' 32.952 N 150° 41' 39.847 W
9,800.0 83.89 3,234.5 2,561.9 -7,664.0287.09 414,343.685,975,356.28 70° 20' 33.238 N 150° 41' 42.624 W
9,900.0 83.89 3,245.1 2,591.1 -7,759.1287.09 414,248.965,975,386.48 70° 20' 33.525 N 150° 41' 45.401 W
10,000.0 83.89 3,255.8 2,620.3 -7,854.1287.09 414,154.245,975,416.69 70° 20' 33.811 N 150° 41' 48.179 W
10,100.0 83.89 3,266.4 2,649.5 -7,949.2287.09 414,059.515,975,446.89 70° 20' 34.098 N 150° 41' 50.956 W
10,200.0 83.89 3,277.0 2,678.8 -8,044.2287.09 413,964.795,975,477.09 70° 20' 34.384 N 150° 41' 53.734 W
10,300.0 83.89 3,287.7 2,708.0 -8,139.2287.09 413,870.065,975,507.29 70° 20' 34.670 N 150° 41' 56.511 W
10,400.0 83.89 3,298.3 2,737.2 -8,234.3287.09 413,775.345,975,537.50 70° 20' 34.957 N 150° 41' 59.289 W
10,500.0 83.89 3,309.0 2,766.4 -8,329.3287.09 413,680.625,975,567.70 70° 20' 35.243 N 150° 42' 2.066 W
10,600.0 83.89 3,319.6 2,795.6 -8,424.4287.09 413,585.895,975,597.90 70° 20' 35.529 N 150° 42' 4.844 W
10,700.0 83.89 3,330.3 2,824.9 -8,519.4287.09 413,491.175,975,628.10 70° 20' 35.816 N 150° 42' 7.621 W
10,800.0 83.89 3,340.9 2,854.1 -8,614.5287.09 413,396.445,975,658.31 70° 20' 36.102 N 150° 42' 10.399 W
10,900.0 83.89 3,351.6 2,883.3 -8,709.5287.09 413,301.725,975,688.51 70° 20' 36.388 N 150° 42' 13.176 W
11,000.0 83.89 3,362.2 2,912.5 -8,804.5287.09 413,207.005,975,718.71 70° 20' 36.674 N 150° 42' 15.954 W
11,014.8 83.89 3,363.8 2,916.8 -8,818.6287.09 413,192.955,975,723.19 70° 20' 36.717 N 150° 42' 16.366 W
Seabee
11,100.0 83.89 3,372.9 2,941.7 -8,899.6287.09 413,112.275,975,748.91 70° 20' 36.961 N 150° 42' 18.732 W
11,200.0 83.89 3,383.5 2,970.9 -8,994.6287.09 413,017.555,975,779.12 70° 20' 37.247 N 150° 42' 21.509 W
11,300.0 83.89 3,394.2 3,000.2 -9,089.7287.09 412,922.825,975,809.32 70° 20' 37.533 N 150° 42' 24.287 W
11,400.0 83.89 3,404.8 3,029.4 -9,184.7287.09 412,828.105,975,839.52 70° 20' 37.819 N 150° 42' 27.065 W
11,500.0 83.89 3,415.5 3,058.6 -9,279.7287.09 412,733.385,975,869.72 70° 20' 38.105 N 150° 42' 29.842 W
9-5/8" Intermediate Liner
11,600.0 83.89 3,426.1 3,087.8 -9,374.8287.09 412,638.655,975,899.93 70° 20' 38.392 N 150° 42' 32.620 W
11,700.0 83.89 3,436.7 3,117.0 -9,469.8287.09 412,543.935,975,930.13 70° 20' 38.678 N 150° 42' 35.398 W
11,800.0 83.89 3,447.4 3,146.3 -9,564.9287.09 412,449.215,975,960.33 70° 20' 38.964 N 150° 42' 38.176 W
11,900.0 83.89 3,458.0 3,175.5 -9,659.9287.09 412,354.485,975,990.53 70° 20' 39.250 N 150° 42' 40.954 W
12,000.0 83.89 3,468.7 3,204.7 -9,755.0287.09 412,259.765,976,020.74 70° 20' 39.536 N 150° 42' 43.731 W
12,100.0 83.89 3,479.3 3,233.9 -9,850.0287.09 412,165.035,976,050.94 70° 20' 39.822 N 150° 42' 46.509 W
12,200.0 83.89 3,490.0 3,263.1 -9,945.0287.09 412,070.315,976,081.14 70° 20' 40.109 N 150° 42' 49.287 W
12,300.0 83.89 3,500.6 3,292.3 -10,040.1287.09 411,975.595,976,111.34 70° 20' 40.395 N 150° 42' 52.065 W
12,400.0 83.89 3,511.3 3,321.6 -10,135.1287.09 411,880.865,976,141.55 70° 20' 40.681 N 150° 42' 54.843 W
12,500.0 83.89 3,521.9 3,350.8 -10,230.2287.09 411,786.145,976,171.75 70° 20' 40.967 N 150° 42' 57.621 W
12,600.0 83.89 3,532.6 3,380.0 -10,325.2287.09 411,691.415,976,201.95 70° 20' 41.253 N 150° 43' 0.399 W
12,700.0 83.89 3,543.2 3,409.2 -10,420.2287.09 411,596.695,976,232.15 70° 20' 41.539 N 150° 43' 3.177 W
12,800.0 83.89 3,553.9 3,438.4 -10,515.3287.09 411,501.975,976,262.36 70° 20' 41.825 N 150° 43' 5.955 W
12,900.0 83.89 3,564.5 3,467.7 -10,610.3287.09 411,407.245,976,292.56 70° 20' 42.111 N 150° 43' 8.733 W
13,000.0 83.89 3,575.2 3,496.9 -10,705.4287.09 411,312.525,976,322.76 70° 20' 42.397 N 150° 43' 11.511 W
13,100.0 83.89 3,585.8 3,526.1 -10,800.4287.09 411,217.795,976,352.96 70° 20' 42.683 N 150° 43' 14.289 W
13,200.0 83.89 3,596.4 3,555.3 -10,895.5287.09 411,123.075,976,383.17 70° 20' 42.969 N 150° 43' 17.067 W
13,300.0 83.89 3,607.1 3,584.5 -10,990.5287.09 411,028.355,976,413.37 70° 20' 43.255 N 150° 43' 19.845 W
13,400.0 83.89 3,617.7 3,613.7 -11,085.5287.09 410,933.625,976,443.57 70° 20' 43.541 N 150° 43' 22.623 W
13,500.0 83.89 3,628.4 3,643.0 -11,180.6287.09 410,838.905,976,473.77 70° 20' 43.827 N 150° 43' 25.402 W
13,600.0 83.89 3,639.0 3,672.2 -11,275.6287.09 410,744.185,976,503.98 70° 20' 44.113 N 150° 43' 28.180 W
13,700.0 83.89 3,649.7 3,701.4 -11,370.7287.09 410,649.455,976,534.18 70° 20' 44.399 N 150° 43' 30.958 W
13,800.0 83.89 3,660.3 3,730.6 -11,465.7287.09 410,554.735,976,564.38 70° 20' 44.685 N 150° 43' 33.736 W
13,884.2 83.89 3,669.3 3,755.2 -11,545.7287.09 410,474.985,976,589.81 70° 20' 44.926 N 150° 43' 36.075 W
13,900.0 83.76 3,671.0 3,759.9 -11,560.7287.55 410,460.025,976,594.64 70° 20' 44.971 N 150° 43' 36.514 W
14,000.0 82.94 3,682.6 3,792.2 -11,654.6290.45 410,366.475,976,627.95 70° 20' 45.288 N 150° 43' 39.259 W
14,100.0 82.13 3,695.6 3,829.2 -11,746.6293.37 410,274.895,976,665.89 70° 20' 45.650 N 150° 43' 41.948 W
14,200.0 81.35 3,709.9 3,870.8 -11,836.4296.29 410,185.535,976,708.37 70° 20' 46.058 N 150° 43' 44.574 W
14,300.0 80.59 3,725.6 3,916.8 -11,923.8299.23 410,098.645,976,755.27 70° 20' 46.509 N 150° 43' 47.129 W
14,400.0 79.86 3,742.6 3,967.1 -12,008.5302.18 410,014.455,976,806.46 70° 20' 47.002 N 150° 43' 49.607 W
14,500.0 79.15 3,760.8 4,021.6 -12,090.3305.15 409,933.215,976,861.81 70° 20' 47.537 N 150° 43' 52.001 W
14,600.0 78.47 3,780.2 4,080.1 -12,169.1308.13 409,855.125,976,921.15 70° 20' 48.111 N 150° 43' 54.303 W
14,700.0 77.82 3,800.8 4,142.5 -12,244.4311.12 409,780.415,976,984.33 70° 20' 48.724 N 150° 43' 56.509 W
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 6
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)Latitude Longitude
Planned Survey
Vertical
Depth
(usft)
14,718.9 77.70 3,804.8 4,154.7 -12,258.3311.69 409,766.715,976,996.66 70° 20' 48.844 N 150° 43' 56.913 W
Nanushuk
14,800.0 77.20 3,822.4 4,208.6 -12,316.3314.13 409,709.275,977,051.17 70° 20' 49.373 N 150° 43' 58.611 W
14,900.0 76.62 3,845.1 4,278.2 -12,384.4317.15 409,641.915,977,121.49 70° 20' 50.056 N 150° 44' 0.604 W
14,945.9 76.36 3,855.8 4,311.3 -12,414.3318.54 409,612.335,977,154.85 70° 20' 50.381 N 150° 44' 1.480 W
NT8 MFS
15,000.0 76.07 3,868.7 4,351.2 -12,448.5320.18 409,578.515,977,195.10 70° 20' 50.773 N 150° 44' 2.482 W
15,100.0 75.56 3,893.2 4,427.3 -12,508.6323.23 409,519.245,977,271.80 70° 20' 51.520 N 150° 44' 4.241 W
15,146.1 75.34 3,904.8 4,463.4 -12,534.9324.64 409,493.335,977,308.16 70° 20' 51.875 N 150° 44' 5.011 W
NT7 MFS
15,200.0 75.09 3,918.5 4,506.3 -12,564.4326.30 409,464.265,977,351.37 70° 20' 52.296 N 150° 44' 5.876 W
15,289.2 74.71 3,941.8 4,579.1 -12,610.5329.04 409,418.965,977,424.62 70° 20' 53.011 N 150° 44' 7.226 W
NT6 MFS
15,300.0 74.66 3,944.6 4,588.0 -12,615.8329.37 409,413.735,977,433.60 70° 20' 53.099 N 150° 44' 7.382 W
15,400.0 74.27 3,971.4 4,672.2 -12,662.6332.46 409,367.785,977,518.26 70° 20' 53.926 N 150° 44' 8.754 W
15,441.8 74.13 3,982.8 4,708.0 -12,680.8333.75 409,349.985,977,554.28 70° 20' 54.278 N 150° 44' 9.287 W
NT5 MFS
15,500.0 73.93 3,998.8 4,758.6 -12,704.8335.56 409,326.555,977,605.12 70° 20' 54.775 N 150° 44' 9.990 W
15,576.0 73.70 4,020.0 4,825.6 -12,733.6337.92 409,298.445,977,672.42 70° 20' 55.434 N 150° 44' 10.835 W
15,600.0 73.70 4,026.7 4,847.0 -12,742.2337.92 409,289.995,977,693.89 70° 20' 55.644 N 150° 44' 11.090 W
15,610.9 73.70 4,029.8 4,856.7 -12,746.2337.92 409,286.175,977,703.60 70° 20' 55.739 N 150° 44' 11.205 W
NT4 MFS
15,700.0 73.70 4,054.8 4,936.0 -12,778.3337.92 409,254.845,977,783.19 70° 20' 56.518 N 150° 44' 12.148 W
15,739.1 73.70 4,065.8 4,970.8 -12,792.4337.92 409,241.085,977,818.15 70° 20' 56.860 N 150° 44' 12.563 W
NT3 MFS
15,741.0 73.70 4,066.3 4,972.4 -12,793.1337.92 409,240.435,977,819.81 70° 20' 56.877 N 150° 44' 12.582 W
7" Intermediate Liner
15,746.9 73.70 4,068.0 4,977.7 -12,795.3337.92 409,238.355,977,825.09 70° 20' 56.928 N 150° 44' 12.645 W
15,799.0 75.52 4,081.8 5,024.2 -12,814.1337.92 409,219.965,977,871.80 70° 20' 57.386 N 150° 44' 13.199 W
NT3.2 Top Res.
15,800.0 75.56 4,082.1 5,025.1 -12,814.5337.92 409,219.615,977,872.71 70° 20' 57.395 N 150° 44' 13.210 W
15,900.0 79.06 4,104.0 5,115.5 -12,851.2337.92 409,183.885,977,963.47 70° 20' 58.283 N 150° 44' 14.286 W
16,000.0 82.56 4,120.0 5,207.0 -12,888.3337.92 409,147.745,978,055.30 70° 20' 59.182 N 150° 44' 15.375 W
16,100.0 86.06 4,129.9 5,299.2 -12,925.7337.92 409,111.305,978,147.87 70° 21' 0.088 N 150° 44' 16.472 W
16,200.0 89.56 4,133.7 5,391.7 -12,963.2337.92 409,074.715,978,240.83 70° 21' 0.998 N 150° 44' 17.575 W
16,214.0 90.05 4,133.8 5,404.7 -12,968.5337.92 409,069.595,978,253.85 70° 21' 1.125 N 150° 44' 17.729 W
16,300.0 90.05 4,133.7 5,484.4 -13,000.8337.92 409,038.095,978,333.88 70° 21' 1.908 N 150° 44' 18.678 W
16,400.0 90.05 4,133.6 5,577.1 -13,038.4337.92 409,001.475,978,426.92 70° 21' 2.819 N 150° 44' 19.781 W
16,500.0 90.05 4,133.5 5,669.7 -13,076.0337.92 408,964.855,978,519.96 70° 21' 3.730 N 150° 44' 20.885 W
16,600.0 90.05 4,133.5 5,762.4 -13,113.6337.92 408,928.235,978,613.00 70° 21' 4.641 N 150° 44' 21.988 W
16,700.0 90.05 4,133.4 5,855.1 -13,151.2337.92 408,891.615,978,706.05 70° 21' 5.551 N 150° 44' 23.091 W
16,800.0 90.05 4,133.3 5,947.7 -13,188.8337.92 408,854.995,978,799.09 70° 21' 6.462 N 150° 44' 24.195 W
16,900.0 90.05 4,133.2 6,040.4 -13,226.4337.92 408,818.375,978,892.14 70° 21' 7.373 N 150° 44' 25.298 W
17,000.0 90.05 4,133.1 6,133.1 -13,263.9337.92 408,781.755,978,985.18 70° 21' 8.283 N 150° 44' 26.401 W
17,100.0 90.05 4,133.0 6,225.7 -13,301.5337.92 408,745.135,979,078.22 70° 21' 9.194 N 150° 44' 27.505 W
17,200.0 90.05 4,133.0 6,318.4 -13,339.1337.92 408,708.515,979,171.27 70° 21' 10.105 N 150° 44' 28.608 W
17,300.0 90.05 4,132.9 6,411.1 -13,376.7337.92 408,671.895,979,264.31 70° 21' 11.016 N 150° 44' 29.712 W
17,400.0 90.05 4,132.8 6,503.7 -13,414.3337.92 408,635.275,979,357.36 70° 21' 11.926 N 150° 44' 30.815 W
17,500.0 90.05 4,132.7 6,596.4 -13,451.9337.92 408,598.655,979,450.40 70° 21' 12.837 N 150° 44' 31.919 W
17,600.0 90.05 4,132.6 6,689.1 -13,489.5337.92 408,562.045,979,543.44 70° 21' 13.748 N 150° 44' 33.022 W
17,700.0 90.05 4,132.5 6,781.7 -13,527.1337.92 408,525.425,979,636.49 70° 21' 14.658 N 150° 44' 34.126 W
17,800.0 90.05 4,132.5 6,874.4 -13,564.6337.92 408,488.805,979,729.53 70° 21' 15.569 N 150° 44' 35.229 W
17,900.0 90.05 4,132.4 6,967.1 -13,602.2337.92 408,452.195,979,822.58 70° 21' 16.480 N 150° 44' 36.333 W
18,000.0 90.05 4,132.3 7,059.7 -13,639.8337.92 408,415.575,979,915.62 70° 21' 17.390 N 150° 44' 37.436 W
18,100.0 90.05 4,132.2 7,152.4 -13,677.4337.92 408,378.955,980,008.67 70° 21' 18.301 N 150° 44' 38.540 W
18,200.0 90.05 4,132.1 7,245.1 -13,715.0337.92 408,342.345,980,101.71 70° 21' 19.212 N 150° 44' 39.644 W
18,300.0 90.05 4,132.0 7,337.7 -13,752.6337.92 408,305.725,980,194.76 70° 21' 20.123 N 150° 44' 40.747 W
18,400.0 90.05 4,132.0 7,430.4 -13,790.2337.92 408,269.115,980,287.80 70° 21' 21.033 N 150° 44' 41.851 W
18,500.0 90.05 4,131.9 7,523.1 -13,827.7337.92 408,232.495,980,380.85 70° 21' 21.944 N 150° 44' 42.955 W
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 7
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)Latitude Longitude
Planned Survey
Vertical
Depth
(usft)
18,600.0 90.05 4,131.8 7,615.7 -13,865.3337.92 408,195.885,980,473.90 70° 21' 22.855 N 150° 44' 44.058 W
18,700.0 90.05 4,131.7 7,708.4 -13,902.9337.92 408,159.265,980,566.94 70° 21' 23.765 N 150° 44' 45.162 W
18,800.0 90.05 4,131.6 7,801.1 -13,940.5337.92 408,122.655,980,659.99 70° 21' 24.676 N 150° 44' 46.266 W
18,900.0 90.05 4,131.5 7,893.7 -13,978.1337.92 408,086.045,980,753.03 70° 21' 25.587 N 150° 44' 47.370 W
19,000.0 90.05 4,131.5 7,986.4 -14,015.7337.92 408,049.425,980,846.08 70° 21' 26.497 N 150° 44' 48.473 W
19,100.0 90.05 4,131.4 8,079.1 -14,053.2337.93 408,012.815,980,939.13 70° 21' 27.408 N 150° 44' 49.577 W
19,200.0 90.05 4,131.3 8,171.8 -14,090.8337.93 407,976.205,981,032.17 70° 21' 28.319 N 150° 44' 50.681 W
19,300.0 90.05 4,131.2 8,264.4 -14,128.4337.93 407,939.595,981,125.22 70° 21' 29.229 N 150° 44' 51.785 W
19,400.0 90.05 4,131.1 8,357.1 -14,166.0337.93 407,902.985,981,218.27 70° 21' 30.140 N 150° 44' 52.889 W
19,500.0 90.05 4,131.0 8,449.8 -14,203.6337.93 407,866.365,981,311.31 70° 21' 31.051 N 150° 44' 53.992 W
19,600.0 90.05 4,130.9 8,542.4 -14,241.1337.93 407,829.755,981,404.36 70° 21' 31.962 N 150° 44' 55.096 W
19,700.0 90.05 4,130.9 8,635.1 -14,278.7337.93 407,793.145,981,497.41 70° 21' 32.872 N 150° 44' 56.200 W
19,800.0 90.05 4,130.8 8,727.8 -14,316.3337.93 407,756.535,981,590.46 70° 21' 33.783 N 150° 44' 57.304 W
19,900.0 90.05 4,130.7 8,820.4 -14,353.9337.93 407,719.925,981,683.50 70° 21' 34.694 N 150° 44' 58.408 W
20,000.0 90.05 4,130.6 8,913.1 -14,391.5337.93 407,683.315,981,776.55 70° 21' 35.604 N 150° 44' 59.512 W
20,100.0 90.05 4,130.5 9,005.8 -14,429.0337.93 407,646.705,981,869.60 70° 21' 36.515 N 150° 45' 0.616 W
20,200.0 90.05 4,130.4 9,098.5 -14,466.6337.93 407,610.095,981,962.65 70° 21' 37.426 N 150° 45' 1.720 W
20,300.0 90.05 4,130.4 9,191.1 -14,504.2337.93 407,573.495,982,055.70 70° 21' 38.336 N 150° 45' 2.824 W
20,400.0 90.05 4,130.3 9,283.8 -14,541.8337.93 407,536.885,982,148.74 70° 21' 39.247 N 150° 45' 3.928 W
20,500.0 90.05 4,130.2 9,376.5 -14,579.4337.93 407,500.275,982,241.79 70° 21' 40.158 N 150° 45' 5.032 W
20,600.0 90.05 4,130.1 9,469.1 -14,616.9337.93 407,463.665,982,334.84 70° 21' 41.068 N 150° 45' 6.136 W
20,700.0 90.05 4,130.0 9,561.8 -14,654.5337.93 407,427.055,982,427.89 70° 21' 41.979 N 150° 45' 7.240 W
20,800.0 90.05 4,129.9 9,654.5 -14,692.1337.93 407,390.455,982,520.94 70° 21' 42.890 N 150° 45' 8.344 W
20,900.0 90.05 4,129.9 9,747.2 -14,729.7337.93 407,353.845,982,613.99 70° 21' 43.800 N 150° 45' 9.448 W
20,998.4 90.05 4,129.8 9,838.4 -14,766.6337.93 407,317.825,982,705.56 70° 21' 44.697 N 150° 45' 10.535 W
21,000.0 90.05 4,129.8 9,839.8 -14,767.2337.90 407,317.235,982,707.04 70° 21' 44.711 N 150° 45' 10.552 W
21,100.0 90.05 4,129.7 9,931.8 -14,806.5335.90 407,278.965,982,799.41 70° 21' 45.615 N 150° 45' 11.705 W
21,200.0 90.05 4,129.6 10,022.4 -14,848.9333.90 407,237.495,982,890.38 70° 21' 46.505 N 150° 45' 12.951 W
21,300.0 90.05 4,129.5 10,111.4 -14,894.5331.90 407,192.865,982,979.86 70° 21' 47.379 N 150° 45' 14.288 W
21,332.1 90.05 4,129.5 10,139.6 -14,909.7331.25 407,177.875,983,008.26 70° 21' 47.657 N 150° 45' 14.737 W
21,400.0 90.05 4,129.4 10,199.1 -14,942.4331.25 407,145.855,983,068.11 70° 21' 48.241 N 150° 45' 15.695 W
21,500.0 90.05 4,129.3 10,286.8 -14,990.5331.25 407,098.685,983,156.27 70° 21' 49.103 N 150° 45' 17.107 W
21,600.0 90.05 4,129.3 10,374.5 -15,038.6331.25 407,051.505,983,244.43 70° 21' 49.964 N 150° 45' 18.518 W
21,700.0 90.05 4,129.2 10,462.2 -15,086.7331.25 407,004.335,983,332.60 70° 21' 50.825 N 150° 45' 19.930 W
21,800.0 90.05 4,129.1 10,549.8 -15,134.8331.25 406,957.165,983,420.76 70° 21' 51.687 N 150° 45' 21.341 W
21,900.0 90.05 4,129.0 10,637.5 -15,182.8331.25 406,909.995,983,508.93 70° 21' 52.548 N 150° 45' 22.753 W
22,000.0 90.05 4,128.9 10,725.2 -15,230.9331.25 406,862.815,983,597.09 70° 21' 53.409 N 150° 45' 24.164 W
22,100.0 90.05 4,128.8 10,812.9 -15,279.0331.25 406,815.645,983,685.25 70° 21' 54.271 N 150° 45' 25.576 W
22,200.0 90.05 4,128.7 10,900.5 -15,327.1331.25 406,768.475,983,773.42 70° 21' 55.132 N 150° 45' 26.988 W
22,300.0 90.05 4,128.6 10,988.2 -15,375.2331.25 406,721.295,983,861.58 70° 21' 55.993 N 150° 45' 28.400 W
22,400.0 90.05 4,128.6 11,075.9 -15,423.3331.25 406,674.125,983,949.75 70° 21' 56.855 N 150° 45' 29.811 W
22,500.0 90.05 4,128.5 11,163.6 -15,471.4331.25 406,626.955,984,037.91 70° 21' 57.716 N 150° 45' 31.223 W
22,600.0 90.05 4,128.4 11,251.2 -15,519.5331.25 406,579.785,984,126.07 70° 21' 58.577 N 150° 45' 32.635 W
22,700.0 90.05 4,128.3 11,338.9 -15,567.6331.25 406,532.605,984,214.24 70° 21' 59.439 N 150° 45' 34.047 W
22,800.0 90.05 4,128.2 11,426.6 -15,615.7331.25 406,485.435,984,302.40 70° 22' 0.300 N 150° 45' 35.459 W
22,900.0 90.05 4,128.1 11,514.3 -15,663.8331.25 406,438.265,984,390.57 70° 22' 1.161 N 150° 45' 36.871 W
23,000.0 90.05 4,128.0 11,602.0 -15,711.9331.25 406,391.095,984,478.73 70° 22' 2.022 N 150° 45' 38.283 W
23,100.0 90.05 4,127.9 11,689.6 -15,759.9331.25 406,343.915,984,566.89 70° 22' 2.884 N 150° 45' 39.695 W
23,200.0 90.05 4,127.9 11,777.3 -15,808.0331.25 406,296.745,984,655.06 70° 22' 3.745 N 150° 45' 41.107 W
23,300.0 90.05 4,127.8 11,865.0 -15,856.1331.25 406,249.575,984,743.22 70° 22' 4.606 N 150° 45' 42.519 W
23,400.0 90.05 4,127.7 11,952.7 -15,904.2331.25 406,202.405,984,831.39 70° 22' 5.468 N 150° 45' 43.931 W
23,500.0 90.05 4,127.6 12,040.3 -15,952.3331.25 406,155.225,984,919.55 70° 22' 6.329 N 150° 45' 45.343 W
23,600.0 90.05 4,127.5 12,128.0 -16,000.4331.25 406,108.055,985,007.71 70° 22' 7.190 N 150° 45' 46.755 W
23,700.0 90.05 4,127.4 12,215.7 -16,048.5331.25 406,060.885,985,095.88 70° 22' 8.051 N 150° 45' 48.168 W
23,800.0 90.05 4,127.3 12,303.4 -16,096.6331.25 406,013.715,985,184.04 70° 22' 8.913 N 150° 45' 49.580 W
23,900.0 90.05 4,127.2 12,391.0 -16,144.7331.25 405,966.535,985,272.20 70° 22' 9.774 N 150° 45' 50.992 W
24,000.0 90.05 4,127.2 12,478.7 -16,192.8331.25 405,919.365,985,360.37 70° 22' 10.635 N 150° 45' 52.405 W
24,100.0 90.05 4,127.1 12,566.4 -16,240.9331.25 405,872.195,985,448.53 70° 22' 11.496 N 150° 45' 53.817 W
24,200.0 90.05 4,127.0 12,654.1 -16,289.0331.25 405,825.025,985,536.70 70° 22' 12.358 N 150° 45' 55.229 W
24,300.0 90.05 4,126.9 12,741.7 -16,337.0331.25 405,777.845,985,624.86 70° 22' 13.219 N 150° 45' 56.642 W
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 8
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)Latitude Longitude
Planned Survey
Vertical
Depth
(usft)
24,400.0 90.05 4,126.8 12,829.4 -16,385.1331.25 405,730.675,985,713.02 70° 22' 14.080 N 150° 45' 58.054 W
24,500.0 90.05 4,126.7 12,917.1 -16,433.2331.25 405,683.505,985,801.19 70° 22' 14.941 N 150° 45' 59.467 W
24,600.0 90.05 4,126.6 13,004.8 -16,481.3331.25 405,636.325,985,889.35 70° 22' 15.803 N 150° 46' 0.879 W
24,700.0 90.05 4,126.5 13,092.5 -16,529.4331.25 405,589.155,985,977.52 70° 22' 16.664 N 150° 46' 2.292 W
24,800.0 90.05 4,126.5 13,180.1 -16,577.5331.25 405,541.985,986,065.68 70° 22' 17.525 N 150° 46' 3.704 W
24,900.0 90.05 4,126.4 13,267.8 -16,625.6331.25 405,494.815,986,153.84 70° 22' 18.386 N 150° 46' 5.117 W
25,000.0 90.05 4,126.3 13,355.5 -16,673.7331.25 405,447.635,986,242.01 70° 22' 19.248 N 150° 46' 6.530 W
25,100.0 90.05 4,126.2 13,443.2 -16,721.8331.25 405,400.465,986,330.17 70° 22' 20.109 N 150° 46' 7.942 W
25,200.0 90.05 4,126.1 13,530.8 -16,769.9331.25 405,353.295,986,418.34 70° 22' 20.970 N 150° 46' 9.355 W
25,300.0 90.05 4,126.0 13,618.5 -16,818.0331.25 405,306.125,986,506.50 70° 22' 21.831 N 150° 46' 10.768 W
25,400.0 90.05 4,125.9 13,706.2 -16,866.1331.25 405,258.945,986,594.66 70° 22' 22.692 N 150° 46' 12.180 W
25,500.0 90.05 4,125.8 13,793.9 -16,914.1331.25 405,211.775,986,682.83 70° 22' 23.554 N 150° 46' 13.593 W
25,576.8 90.05 4,125.8 13,861.2 -16,951.1331.25 405,175.565,986,750.51 70° 22' 24.215 N 150° 46' 14.678 W
Target Name
- hit/miss target
- Shape
TVD
(usft)
Northing
(usft)
Easting
(usft)
+N/-S
(usft)
+E/-W
(usft)
Design Targets
LongitudeLatitude
Dip Angle
(°)
Dip Dir.
(°)
NDB-039 Toe Rev 3.0 4,125.8 5,986,758.73 405,171.1613,869.3 -16,955.60.00 0.00 70° 22' 24.295 N 150° 46' 14.810 W
- plan misses target center by 9.3usft at 25576.8usft MD (4125.8 TVD, 13861.2 N, -16951.1 E)
- Point
NDB-039 Toe Rev 4.0 4,125.8 5,986,750.51 405,175.5613,861.2 -16,951.10.00 0.00 70° 22' 24.215 N 150° 46' 14.678 W
- plan hits target center
- Point
Mid Point Azimuth Cha 4,129.8 5,982,705.56 407,317.829,838.4 -14,766.60.00 0.00 70° 21' 44.697 N 150° 45' 10.535 W
- plan hits target center
- Point
NDB-039 Heel Rev 3.4,133.8 5,978,253.85 409,069.595,404.7 -12,968.50.00 0.00 70° 21' 1.125 N 150° 44' 17.729 W
- plan hits target center
- Polygon
-977.5Point 1 5,977,268.98 409,781.414,133.8 722.1 True
4,153.7Point 2 5,982,420.82 407,779.094,133.8 -1,333.9 True
4,355.9Point 3 5,982,623.83 407,700.114,133.8 -1,415.0 True
4,554.8Point 4 5,982,823.81 407,595.094,133.8 -1,522.1 True
8,827.3Point 5 5,987,119.78 405,323.884,133.8 -3,838.1 True
8,750.7Point 6 5,987,044.68 405,179.904,133.8 -3,981.3 True
8,465.6Point 7 5,986,759.67 405,171.944,133.8 -3,986.3 True
8,092.6Point 8 5,986,386.69 405,171.964,133.8 -3,982.4 True
7,914.2Point 9 5,986,208.76 405,126.914,133.8 -4,025.6 True
4,303.1Point 10 5,982,577.82 407,047.154,133.8 -2,067.5 True
4,067.4Point 11 5,982,340.84 407,171.084,133.8 -1,941.1 True
3,863.1Point 12 5,982,135.80 407,243.154,133.8 -1,866.9 True
-1,202.4Point 13 5,977,049.91 409,222.364,133.8 165.3 True
Vertical
Depth
(usft)
Measured
Depth
(usft)
Casing
Diameter
(")
Hole
Diameter
(")Name
Casing Points
20" Conductor Driven128.0128.0 20 20
13-3/8" Surface Casing2,404.82,912.0 13-3/8 16
9-5/8" Intermediate Liner3,415.511,500.0 9-5/8 12-1/4
7" Intermediate Liner4,066.315,741.0 7 8-1/2
4-1/2" Production Liner25,576.9 4-1/2 6-1/8
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 9
Planning Report - Geographic
Well B-39Local Co-ordinate Reference:Database:EDM STO Alaska
Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany:
Parker 272 @ 69.8usftMD Reference:PikkaProject:
TrueNorth Reference:NDBSite:
Minimum CurvatureSurvey Calculation Method:B-39Well:
NDB-039Wellbore:
Plan: NDB-039 Rev H.0Design:
Measured
Depth
(usft)
Vertical
Depth
(usft)
Dip
Direction
(°)Name Lithology
Dip
(°)
Formations
1,043.3 Upper Schrader Bluff1,032.8
1,169.4 Base Ice Bearing Permafrost1,153.8
1,416.0 Base Permafrost Transition1,384.8
1,838.8 Middle Schrader Bluff1,749.8
2,413.4 MCU2,154.8
3,017.3 Tuluvak Shale2,445.8
3,213.6 Tuluvak Sand2,507.8
5,839.5 TS_7902,812.8
11,014.8 Seabee3,363.8
14,718.9 Nanushuk3,804.8
14,945.9 NT8 MFS3,855.8
15,146.1 NT7 MFS3,904.8
15,289.2 NT6 MFS3,941.8
15,441.8 NT5 MFS3,982.8
15,610.9 NT4 MFS4,029.8
15,739.1 NT3 MFS4,065.8
15,799.0 NT3.2 Top Res.4,081.8
12/12/2025 11:27:23AM COMPASS 5000.17 Build 02 Page 10
0250050007500100001250015000South(-)/North(+) (2500 usft/in)-20000 -17500 -15000 -12500 -10000 -7500 -5000 -2500 0 2500West(-)/East(+) (2500 usft/in)Mid Point Azimuth Change Rev 2.0NDB-039 Heel Rev 3.085%NDB-039 Toe Rev 4.020" Conductor Driven13-3/8" Surface Casing9-5/8" Intermediate Liner7" Intermediate Liner4-1/2" Production Liner3000Plan: NDB-039 Rev H.0Plan View
-95009501900285038004750True Vertical Depth-3000 0 3000 6000 9000 12000 15000 18000 21000Vertical Section at 309.27°20" Conductor Driven13-3/8" Surface Casing9-5/8" Intermediate Liner7" Intermediate Liner4-1/2" Production Liner140001600017000
18000
19000
20000
21000
22000
23000
24000
25000
25577
0°90°90°
90°
Plan: NDB-039 Rev H.0
Upper Schrader BluffBase Ice Bearing PermafrostBase Permafrost TransitionMiddle Schrader BluffMCUTuluvak ShaleTuluvak SandTS_790SeabeeNanushukNT8 MFSNT7 MFSNT6 MFSNT5 MFSNT4 MFSNT3 MFSNT3.2 Top Res.Plan: NDB-039 Rev H.011:10, December 12 2025
12 December, 2025
Anticollision Summary Report
Santos
Pikka
NDB
B-39
NDB-039
Plan: NDB-039 Rev H.0
Anticollision Summary Report
Well B-39 - Slot B-39Local Co-ordinate Reference:SantosCompany:
Parker 272 @ 69.8usftTVD Reference:PikkaProject:
Parker 272 @ 69.8usftMD Reference:NDBReference Site:
TrueNorth Reference:0.9 usftSite Error:
Minimum CurvatureSurvey Calculation Method:B-39Reference Well:
Output errors are at 2.79 sigmaWell Error:0.5 usft
Reference Wellbore NDB-039 Database:EDM STO Alaska
Offset DatumReference Design:Plan: NDB-039 Rev H.0 Offset TVD Reference:
Interpolation Method:
Depth Range:
Reference
Error Model:
Scan Method:
Error Surface:
Filter type:
ISCWSA
Closest Approach 3D
Combined Pedal Curve
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere
MD Interval 25.0usft
Unlimited
Maximum centre distance of 2,753.0usft
Plan: NDB-039 Rev H.0
Results Limited by:
SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method:
From
(usft)
Survey Tool Program
DescriptionTool NameSurvey (Wellbore)
To
(usft)
Date 12/12/2025
SDI_URSA+SAG SDI URSA gyroMWD + SAG47.0 2,000.0 Plan: NDB-039 Rev H.0 (NDB-039)
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,000.0 2,912.0 Plan: NDB-039 Rev H.0 (NDB-039)
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,912.0 11,500.0 Plan: NDB-039 Rev H.0 (NDB-039)
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag11,500.0 15,741.0 Plan: NDB-039 Rev H.0 (NDB-039)
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag15,741.0 25,576.9 Plan: NDB-039 Rev H.0 (NDB-039)
Offset Well - Wellbore - Design
Reference
Measured
Depth
(usft)
Offset
Measured
Depth
(usft)
Between
Centres
(usft)
Between
Ellipses
(usft)
Separation
Factor
Warning
Summary
Site Name
Distance
Fiord 3
SFFiord 2 - Fiord 2 - Fiord 2 24,850.0 5,093.0 2,382.4 1,914.8 6.390
ESFiord 2 - Fiord 2 - Fiord 2 25,100.0 5,237.3 2,368.0 1,906.9 6.441
CCFiord 2 - Fiord 2 - Fiord 2 25,188.9 5,289.1 2,367.0 1,908.7 6.478
SFFiord 3 - Fiord 3A - Fiord 3A 20,425.0 5,801.4 1,688.5 1,357.8 6.412
ESFiord 3 - Fiord 3A - Fiord 3A 20,500.0 5,739.2 1,687.4 1,357.2 6.419
CCFiord 3 - Fiord 3A - Fiord 3A 20,527.9 5,716.0 1,687.3 1,357.4 6.424
NDB
CCB-25 - NDB-025 - NDB-025 368.6 369.8 279.1 269.5 51.111
ESB-25 - NDB-025 - NDB-025 375.0 376.3 279.1 269.5 51.006
SFB-25 - NDB-025 - NDB-025 10,025.0 13,886.0 1,048.7 883.9 8.055
CCB-27 - NDB-027 - NDB-027 52.0 51.9 240.2 231.0 50.514
ESB-27 - NDB-027 - NDB-027 375.0 375.6 240.8 230.4 40.003
SFB-27 - NDB-027 - NDB-027 25,576.9 23,253.2 2,583.1 1,715.7 3.728
CCB-27 - NDB-027 MWD - NDB-027 MWD 47.0 47.0 240.2 231.1 51.287
ESB-27 - NDB-027 MWD - NDB-027 MWD 375.0 375.7 240.8 230.5 40.224
SFB-27 - NDB-027 MWD - NDB-027 MWD 8,800.0 8,544.1 2,744.1 2,416.2 10.533
CCB-27 - NDB-027 PB1 - NDB-027 PB1 52.0 52.0 240.2 231.0 50.514
ESB-27 - NDB-027 PB1 - NDB-027 PB1 375.0 375.7 240.8 230.4 40.003
SFB-27 - NDB-027 PB1 - NDB-027 PB1 3,200.0 3,242.3 696.7 610.7 10.406
CCB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 325.0 325.2 219.3 209.5 39.812
ESB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 350.0 350.2 219.3 209.4 39.405
SFB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 1,100.0 1,113.9 293.8 277.4 26.980
CCB-29 - NDB-029 - NDB-29 Slot Saver 325.0 325.2 199.2 189.6 36.905
ESB-29 - NDB-029 - NDB-29 Slot Saver 350.0 350.2 199.2 189.6 36.643
SFB-29 - NDB-029 - NDB-29 Slot Saver 850.0 846.2 234.8 222.5 31.090
CCB-30 - NDBi-030 - NDBi-030 47.0 46.4 180.1 171.0 38.309
ESB-30 - NDBi-030 - NDBi-030 225.0 223.9 180.2 171.0 35.063
SFB-30 - NDBi-030 - NDBi-030 9,350.0 9,109.7 2,698.2 2,339.4 9.460
CCB-31 - NDB-031 - NDB-031 580.4 591.8 156.1 145.3 24.437
ESB-31 - NDB-031 - NDB-031 600.0 611.4 156.2 145.3 24.045
SFB-31 - NDB-031 - NDB-031 800.0 807.3 169.2 156.9 22.007
CCB-32 - NDB-032 - NDB-032 47.0 47.0 140.2 131.1 29.866
ESB-32 - NDB-032 - NDB-032 325.0 324.7 140.4 130.7 25.278
SFB-32 - NDB-032 - NDB-032 2,425.0 2,573.7 235.1 201.7 9.541
CCB-33 - NDB-033 - Plan: NDB-033 Rev A.0 325.0 325.2 119.2 109.5 21.836
ESB-33 - NDB-033 - Plan: NDB-033 Rev A.0 350.0 350.2 119.2 109.5 21.685
SFB-33 - NDB-033 - Plan: NDB-033 Rev A.0 750.0 753.0 144.9 132.9 19.644
12/12/2025 11:13:47AM COMPASS 5000.17 Build 02
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
Page 2
Anticollision Summary Report
Well B-39 - Slot B-39Local Co-ordinate Reference:SantosCompany:
Parker 272 @ 69.8usftTVD Reference:PikkaProject:
Parker 272 @ 69.8usftMD Reference:NDBReference Site:
TrueNorth Reference:0.9 usftSite Error:
Minimum CurvatureSurvey Calculation Method:B-39Reference Well:
Output errors are at 2.79 sigmaWell Error:0.5 usft
Reference Wellbore NDB-039 Database:EDM STO Alaska
Offset DatumReference Design:Plan: NDB-039 Rev H.0 Offset TVD Reference:
Offset Well - Wellbore - Design
Reference
Measured
Depth
(usft)
Offset
Measured
Depth
(usft)
Between
Centres
(usft)
Between
Ellipses
(usft)
Separation
Factor
Warning
Summary
Site Name
Distance
NDB
CCB-34 - NDBi-034 - Plan: NDBi-034 Rev M.0 1,411.1 1,435.9 83.3 65.3 6.727
ESB-34 - NDBi-034 - Plan: NDBi-034 Rev M.0 1,475.0 1,501.1 83.5 65.0 6.511
SFB-34 - NDBi-034 - Plan: NDBi-034 Rev M.0 25,576.9 24,128.9 1,318.2 650.3 2.471
CCB-35 - NDB-035 - NDB-035 Slot Saver 325.0 325.2 79.1 69.5 14.389
ESB-35 - NDB-035 - NDB-035 Slot Saver 350.0 350.2 79.1 69.5 14.287
SFB-35 - NDB-035 - NDB-035 Slot Saver 575.0 574.8 86.0 75.4 13.446
CCB-36 - NDBi-036 - NDBi-036 499.4 502.2 56.4 46.1 9.135
ESB-36 - NDBi-036 - NDBi-036 525.0 527.9 56.4 46.0 8.962
SFB-36 - NDBi-036 - NDBi-036 625.0 627.7 59.4 48.2 8.622
CCB-37 - NDB-037 - NDB-037 399.8 399.9 39.6 29.9 6.831
ESB-37 - NDB-037 - NDB-037 450.0 450.4 39.8 29.8 6.618
SFB-37 - NDB-037 - NDB-037 3,425.0 3,510.9 157.6 96.4 3.313
CCB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 325.0 325.2 19.0 9.3 3.102
ESB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 350.0 350.2 19.0 9.3 3.080
SFB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 375.0 375.2 19.1 9.3 3.073
CCB-40 - NDB-040 - NDB-040 47.0 47.3 20.0 10.9 3.753
ESB-40 - NDB-040 - NDB-040 225.0 225.2 20.4 10.8 3.403
SFB-40 - NDB-040 - NDB-040 300.0 300.1 20.9 10.9 3.263
CCB-41 - NDBi-041 - Plan: NDBi-041 Rev C.0 1,268.4 1,260.0 39.1 23.2 3.529
ESB-41 - NDBi-041 - Plan: NDBi-041 Rev C.0 1,475.0 1,462.8 39.8 22.1 3.168
SFB-41 - NDBi-041 - Plan: NDBi-041 Rev C.0 25,576.9 27,051.2 1,319.2 550.8 2.149
CCB-42 - NDB-042 - NDB-042 Rev E.0 291.6 291.8 61.1 50.9 10.174
ESB-42 - NDB-042 - NDB-042 Rev E.0 325.0 324.8 61.1 50.8 9.915
SFB-42 - NDB-042 - NDB-042 Rev E.0 25,576.9 28,320.3 2,572.7 1,752.9 3.930
CCB-43 - NDBi-043 - NDBi-043 674.7 671.7 70.0 59.0 10.420
ESB-43 - NDBi-043 - NDBi-043 675.0 672.0 70.0 59.0 10.419
SFB-43 - NDBi-043 - NDBi-043 9,350.0 10,927.7 2,105.8 1,827.9 9.548
CCB-43 - NDBi-043A - NDBi-043A 674.7 671.7 70.0 59.0 10.420
ESB-43 - NDBi-043A - NDBi-043A 675.0 672.0 70.0 59.0 10.419
SFB-43 - NDBi-043A - NDBi-043A 700.0 695.6 70.4 59.3 10.368
CC, ESB-44 - NDBi-044 - NDBi-044 1,132.0 1,119.2 73.4 59.3 7.951
SFB-44 - NDBi-044 - NDBi-044 17,650.0 17,839.0 1,443.5 971.5 3.835
CC, ESB-45 - NDB-045 - Plan: NDB-045 Rev A.0 607.9 603.3 116.4 105.2 17.329
SFB-45 - NDB-045 - Plan: NDB-045 Rev A.0 700.0 688.0 119.4 107.8 16.908
CCB-46 - NDBi-046 - NDBi-046 47.0 46.8 139.8 130.7 29.624
ESB-46 - NDBi-046 - NDBi-046 300.0 299.2 140.3 130.8 25.993
SFB-46 - NDBi-046 - NDBi-046 9,025.0 8,158.3 2,709.4 2,394.6 10.835
CCB-46 - NDBi-046 L1 - NDBi-046 L1 47.0 46.8 139.8 130.7 29.624
ESB-46 - NDBi-046 L1 - NDBi-046 L1 300.0 299.2 140.3 130.8 25.993
SFB-46 - NDBi-046 L1 - NDBi-046 L1 9,025.0 8,158.3 2,709.4 2,394.6 10.835
CC, ESB-47 - NDB-047 - NDB-047 Slot Saver 658.5 653.0 157.9 147.1 24.581
SFB-47 - NDB-047 - NDB-047 Slot Saver 775.0 758.1 162.4 151.1 24.004
CCB-48 - NDB-048 - NDB-048 453.5 448.6 179.9 169.9 31.157
ESB-48 - NDB-048 - NDB-048 500.0 492.1 180.0 169.7 30.201
SFB-48 - NDB-048 - NDB-048 7,525.0 6,635.8 2,743.1 2,506.5 14.628
CCB-49 - NDBi-049 - NDBi-049 52.0 51.9 200.0 190.9 41.987
ESB-49 - NDBi-049 - NDBi-049 550.0 539.5 200.5 190.0 32.578
SFB-49 - NDBi-049 - NDBi-049 15,125.0 19,302.0 2,191.7 1,678.7 5.359
CC, ESB-50 - NDBi-050 - NDBi-050 52.0 51.8 219.9 210.7 46.218
SFB-50 - NDBi-050 - NDBi-050 6,525.0 5,486.3 2,740.5 2,573.6 20.826
CC, ESB-50 - NDBi-050 PB1 - NDBi-050 PB1 52.0 51.8 219.9 210.7 46.218
SFB-50 - NDBi-050 PB1 - NDBi-050 PB1 6,375.0 5,284.7 2,751.3 2,588.6 21.444
CCB-51 - NDB-051 - NDB-051 209.5 209.0 239.8 230.6 47.214
Take Immediate Action, EB-51 - NDB-051 - NDB-051 15,275.0 17,478.0 283.5 -26.6 1.144
Take Immediate Action, SB-51 - NDB-051 - NDB-051 15,300.0 17,478.0 296.6 -28.5 1.141
12/12/2025 11:13:47AM COMPASS 5000.17 Build 02
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
Page 3
Anticollision Summary Report
Well B-39 - Slot B-39Local Co-ordinate Reference:SantosCompany:
Parker 272 @ 69.8usftTVD Reference:PikkaProject:
Parker 272 @ 69.8usftMD Reference:NDBReference Site:
TrueNorth Reference:0.9 usftSite Error:
Minimum CurvatureSurvey Calculation Method:B-39Reference Well:
Output errors are at 2.79 sigmaWell Error:0.5 usft
Reference Wellbore NDB-039 Database:EDM STO Alaska
Offset DatumReference Design:Plan: NDB-039 Rev H.0 Offset TVD Reference:
Offset Well - Wellbore - Design
Reference
Measured
Depth
(usft)
Offset
Measured
Depth
(usft)
Between
Centres
(usft)
Between
Ellipses
(usft)
Separation
Factor
Warning
Summary
Site Name
Distance
Wildcat
SFFiord 3 - Fiord 3 - Fiord 3 21,975.0 4,124.0 2,303.0 1,872.7 6.718
ESFiord 3 - Fiord 3 - Fiord 3 22,400.0 4,125.7 2,242.5 1,835.7 6.923
CCFiord 3 - Fiord 3 - Fiord 3 22,511.4 4,126.2 2,239.7 1,841.0 7.055
SFFiord 3 - Fiord 3A - Fiord 3A 20,500.0 5,686.5 1,306.7 971.0 4.891
ESFiord 3 - Fiord 3A - Fiord 3A 20,575.0 5,630.5 1,302.6 968.3 4.897
CCFiord 3 - Fiord 3A - Fiord 3A 20,666.0 5,580.6 1,300.7 971.9 4.972
CCQugruk-301 - Qugruk-301 - Qugruk-301 10,407.3 6,803.2 899.6 827.6 16.146
ESQugruk-301 - Qugruk-301 - Qugruk-301 10,450.0 6,800.7 900.6 826.3 15.639
SFQugruk-301 - Qugruk-301 - Qugruk-301 11,050.0 6,772.2 1,105.1 983.0 11.528
12/12/2025 11:13:47AM COMPASS 5000.17 Build 02
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
Page 4
Anticollision Summary Report
Well B-39 - Slot B-39Local Co-ordinate Reference:SantosCompany:
Parker 272 @ 69.8usftTVD Reference:PikkaProject:
Parker 272 @ 69.8usftMD Reference:NDBReference Site:
TrueNorth Reference:0.9 usftSite Error:
Minimum CurvatureSurvey Calculation Method:B-39Reference Well:
Output errors are at 2.79 sigmaWell Error:0.5 usft
Reference Wellbore NDB-039 Database:EDM STO Alaska
Offset DatumReference Design:Plan: NDB-039 Rev H.0 Offset TVD Reference:
0
700
1400
2100
2800
0 4500 9000 13500 18000 22500 27000
Measured Depth
Ladder Plot
Fiord 2, Fiord 2, Fiord 2 V0
Fiord 3, Fiord 3A, Fiord 3A V0
B-25, NDB-025, NDB-025 V0
B-27, NDB-027, NDB-027 V0
B-27, NDB-027 MWD, NDB-027 MWD V0
B-27, NDB-027 PB1, NDB-027 PB1 V0
B-28, NDBi-028, Plan NDBi-028 Rev A.0 V0
B-29, NDB-029, NDB-29 Slot Saver V0
B-30, NDBi-030, NDBi-030 V0
B-31, NDB-031, NDB-031 V0
B-32, NDB-032, NDB-032 V0
B-33, NDB-033, Plan: NDB-033 Rev A.0 V0
B-34, NDBi-034, Plan: NDBi-034 Rev M.0 V0
B-35, NDB-035, NDB-035 Slot Saver V0
B-36, NDBi-036, NDBi-036 V0
B-37, NDB-037, NDB-037 V0
B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0
B-40, NDB-040, NDB-040 V0
B-41, NDBi-041, Plan: NDBi-041 Rev C.0 V0
B-42, NDB-042, NDB-042 Rev E.0 V0
B-43, NDBi-043, NDBi-043 V0
B-43, NDBi-043A, NDBi-043A V0
B-44, NDBi-044, NDBi-044 V0
B-45, NDB-045, Plan: NDB-045 Rev A.0 V0
B-46, NDBi-046, NDBi-046 V0
B-46, NDBi-046 L1, NDBi-046 L1 V0
B-47, NDB-047, NDB-047 Slot Saver V0
B-48, NDB-048, NDB-048 V0
B-49, NDBi-049, NDBi-049 V0
B-50, NDBi-050, NDBi-050 V0
B-50, NDBi-050 PB1, NDBi-050 PB1 V0
B-51, NDB-051, NDB-051 V0
Fiord 3, Fiord 3, Fiord 3 V0
Fiord 3, Fiord 3A, Fiord 3A V0
Qugruk-301, Qugruk-301, Qugruk-301 V0
L E G E N D
Coordinates are relative to: B-39 - Slot B-39
Coordinate System is US State Plane 1983, Alaska Zone 4
Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W
Offset Depths are relative to Offset Datum
Reference Depths are relative to Parker 272 @ 69.8usft
12/12/2025 11:13:47AM COMPASS 5000.17 Build 02
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
Page 5
Anticollision Summary Report
Well B-39 - Slot B-39Local Co-ordinate Reference:SantosCompany:
Parker 272 @ 69.8usftTVD Reference:PikkaProject:
Parker 272 @ 69.8usftMD Reference:NDBReference Site:
TrueNorth Reference:0.9 usftSite Error:
Minimum CurvatureSurvey Calculation Method:B-39Reference Well:
Output errors are at 2.79 sigmaWell Error:0.5 usft
Reference Wellbore NDB-039 Database:EDM STO Alaska
Offset DatumReference Design:Plan: NDB-039 Rev H.0 Offset TVD Reference:
0.00
3.00
6.00
9.00
0 4500 9000 13500 18000 22500
Measured Depth
Stop Drilling
Caution - Monitor Closely
Normal Operations
Separation Factor Plot
Fiord 2, Fiord 2, Fiord 2 V0
Fiord 3, Fiord 3A, Fiord 3A V0
B-25, NDB-025, NDB-025 V0
B-27, NDB-027, NDB-027 V0
B-27, NDB-027 MWD, NDB-027 MWD V0
B-27, NDB-027 PB1, NDB-027 PB1 V0
B-28, NDBi-028, Plan NDBi-028 Rev A.0 V0
B-29, NDB-029, NDB-29 Slot Saver V0
B-30, NDBi-030, NDBi-030 V0
B-31, NDB-031, NDB-031 V0
B-32, NDB-032, NDB-032 V0
B-33, NDB-033, Plan: NDB-033 Rev A.0 V0
B-34, NDBi-034, Plan: NDBi-034 Rev M.0 V0
B-35, NDB-035, NDB-035 Slot Saver V0
B-36, NDBi-036, NDBi-036 V0
B-37, NDB-037, NDB-037 V0
B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0
B-40, NDB-040, NDB-040 V0
B-41, NDBi-041, Plan: NDBi-041 Rev C.0 V0
B-42, NDB-042, NDB-042 Rev E.0 V0
B-43, NDBi-043, NDBi-043 V0
B-43, NDBi-043A, NDBi-043A V0
B-44, NDBi-044, NDBi-044 V0
B-45, NDB-045, Plan: NDB-045 Rev A.0 V0
B-46, NDBi-046, NDBi-046 V0
B-46, NDBi-046 L1, NDBi-046 L1 V0
B-47, NDB-047, NDB-047 Slot Saver V0
B-48, NDB-048, NDB-048 V0
B-49, NDBi-049, NDBi-049 V0
B-50, NDBi-050, NDBi-050 V0
B-50, NDBi-050 PB1, NDBi-050 PB1 V0
B-51, NDB-051, NDB-051 V0
Fiord 3, Fiord 3, Fiord 3 V0
Fiord 3, Fiord 3A, Fiord 3A V0
Qugruk-301, Qugruk-301, Qugruk-301 V0
L E G E N D
Coordinates are relative to: B-39 - Slot B-39
Coordinate System is US State Plane 1983, Alaska Zone 4
Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W
Offset Depths are relative to Offset Datum
Reference Depths are relative to Parker 272 @ 69.8usft
12/12/2025 11:13:47AM COMPASS 5000.17 Build 02
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
Page 6
Northing (5000 usft/in)Easting (5000 usft/in)Northing (5000 usft/in)Easting (5000 usft/in)Fiord 2Fiord 3ANDB-025NDB-027NDB-027 MWDNDB-027 PB1Plan NDBi-028 Rev A.0NDB-29 Slot SaverNDBi-030NDB-031NDB-032Plan: NDB-033 Rev A.0Plan: NDBi-034 Rev M.0NDB-035 Slot SaverNDBi-036NDB-037Plan: NDBi-038 Rev A.0NDB-040Plan: NDBi-041 Rev C.0NDB-042 Rev E.0NDBi-043NDBi-043ANDBi-044Plan: NDB-045 Rev A.0NDBi-046NDBi-046 L1NDB-047 Slot SaverNDB-048NDBi-049NDBi-050NDBi-050 PB1NDB-051Fiord 3Fiord 3AQugruk-3013000Plan: NDB-039 Rev H.0NDANDBNPF11:14, December 12 2025
0
30
60
0 450 900 1350 1800 2250
Partial Measured Depth
Equivalent Magnetic Distance
Plan: NDB-039 Rev H.0 Ladder View
0
150
300
0 4000 8000 12000 16000 20000 24000
Measured Depth
Equivalent Magnetic Distance
SURVEY PROGRAM
Depth From Depth To Survey/Plan Tool
47.0 2000.0 Plan: NDB-039 Rev H.0 (NDB-039)SDI_URSA+SAG
2000.0 2912.0 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
2912.011500.0 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
11500.015741.0 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
15741.025576.9 Plan: NDB-039 Rev H.0 (NDB-039)3_MWD+IFR2+MS+Sag
11:20, December 12 2025
CASING DETAILS
TVD MD Name
128.0 128.020" Conductor Driven
2404.8 2912.013-3/8" Surface Casing
3415.4 11500.09-5/8" Intermediate Liner
4066.3 15741.07" Intermediate Liner
4125.8 25576.94-1/2" Production Liner
Plan: NDB-039 Rev H.0AC FlipbookSURVEY PROGRAMDepth From Depth To Tool47.0 2000.0 SDI_URSA+SAG2000.0 2912.0 3_MWD+IFR2+MS+Sag2912.0 11500.0 3_MWD+IFR2+MS+Sag11500.0 15741.0 3_MWD+IFR2+MS+Sag15741.0 25576.9 3_MWD+IFR2+MS+SagCASING DETAILSTVD MD Name128.0 128.020" Conductor Driven2404.8 2912.013-3/8" Surface Casing3415.4 11500.09-5/8" Intermediate Liner4066.3 15741.0 7" Intermediate Liner4125.8 25576.94-1/2" Production Liner2525505075751001001251251501501751750901802703021060240 120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [50 usft/in]475176101NDBi-030475075100125150175200225250275300325350374398422446470494517541565588611635658681704727750772794817839NDB-031475075100125150175200225250275300325350374398422446471495519543567591615639662686710734757781805828852NDB-0327075100125150175200225250275300325350374398423447471495519543567590614637661684707730753776800821843865887909931Plan: NDB-033 Rev A.0475075100125150175200225250275300325350374399423448472496521545570594618643667692716740765789814838863887911936960985100910341059108411091134115911831207123112551280130413281352137614001425144914731497152215461570159416191643166716921716174017651789181318381862188619111935195919842008203320572081210621302154217922032228225222772301232523502374239924232448247224962521Plan: NDBi-034 Rev M.0475075100125150175200225250275300325350374399423448472497521545570594618642666690714738762786809833856879903926948971NDB-035 Slot Saver475075100125150175200225250275300325350374399424448473497522546571595619643667691715738762785809832855877900922943965987100910311054NDBi-03647507510012515017520022525027530032535037540042544947449952454957359862364867369772274777279782184687189692094597099410191044106910941119114411691193121712421266129013151339136313871412143614601484150815321557158116051629165316771700172517491773179718211845186918931917194119651989201320372061208521092132215621802204222822522276230023232347237123952419244324662490251425382562258526092633265726822706273127562780280428272851287529002922294629702994301830423065308931133137316131853209323332573281330533293353337734003425344934733497352135453570359536203645NDB-037475075100125150175200225250275300325350375400424449474498523547571596620644667691715738762785808831854876900921944966988101010331056Plan: NDBi-038 Rev A.04750751001251501752002252502753003253503754004254504755005255505755996236486726967197437667908138368588819039269489709911014NDB-0404750751001251501752002252502753003253503754014264514765025275525776036286536787037297547798048308558809059319569811006103110561081110611311156118212071233125812841309133513601385141114361462148715121538156315891614163916651690171517411766179218171842186718931918194319691994201920442070209521202145217021952221224622712296232123462371239624212446247224972522254725722596262126462671269627212746277127962820284528702895292029452970299530203045307030953120314531703195Plan: NDBi-041 Rev C.0475075100125150175200225250275300325350375401426451477502528553578604629655680706731757782808833858884909935960986101110361061108611111136116211881214124012661292131813441370139614221448147415001526155215781604163016561682170817341760178618121838186418901916194119671993201920452071209721232149217422002226225222782304232923552381240624322458248425092535256025862612NDB-042 Rev E.04750751001251501752002252502753003253503764014274524785035295545796046296536787027267507747988218458688919139369589811003102610501073NDBi-0434750751001251501752002252502753003253503764014274524785035295545796046296536787027267507747988218458688919139369589811003102610501073NDBi-043A4750751001251501752002252502753003253503764024274534795045305555816076326586847097357607868118378628889139389649891014103910631088111311381163118812141239126412891315134013651390141514401465149015151539156415891614163816631688171217371761178518101834185818821907193119551979200320272051207521002123NDBi-044475075100125150175200225250275300325350376401427453478504529555580605630654679704728752777801825849872896919943966989Plan: NDB-045 Rev A.04750751001251501752002252502753003253503764024284544805065325585836096356616877137397647908168428688949209459719971022104710721097112211471174120012271254128113071334NDBi-0464750751001251501752002252502753003253503764024284544805065325585836096356616877137397647908168428688949209459719971022104710721097112211471174120012271254128113071334NDBi-046 L1475075100125150175200225250275300325350376402427453479504530555580606631656680705730754779803828852876900NDB-047 Slot Saver475075100125150175200225250275300325350377403429455481507NDB-04847 500500 10001000 15001500 20002000 25002500 30003000 50005000 60006000 70007000 80008000 90009000 1000010000 1200012000 1400014000 1600016000 1800018000 2000020000 25000From Colour To MD47.0 To 25576.9MD Azi TFace47.0 0.00 0.00347.0 0.00 0.00998.7 310.00 310.001148.7 310.00 0.002660.0 290.00 -24.622760.0 290.00 0.003528.5 287.09 -7.4213884.3 287.09 0.0015576.2 337.92 106.0815747.1 337.92 0.0016214.2 337.92 0.0020998.6 337.92 0.0021332.1 331.25 -89.9825576.9 331.25 0.00
Attachment 3: BOPE Equipment
21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#
21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#
13-5/8" X 5,000#13-5/8" X 5,000#30"13-5/8" X 5,000#186"13-5/8" X 5,000#
Choke Linefrom BOPPressure Gauge1502 Pressure SensorPressure TransducerBill of MaterialItemDescriptionTo Panic LineItemDescriptionA 31/8 5,000psi W.P.Remote HydraulicOperated ChokeB 31/85,000 psi W.P.Adjustable ManualChoke1 14 31/8 5,000psi W.P.Manual Gate Valve1521/165 000 i WP1521/165,000psiW.P.Manual Gate ValveTo Mud GasLegendBlind SpareTo Tiger TankSeparatorValve Normally OpenValve Normally Closed
Attachment 4: Drilling Hazards
16 Surface Hole Section
Hazard Mitigations
Conductor Broach Monitor conductor for any indications of broaching. Monitor pit
volumes for any losses.
Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess
circulation.
Lost Returns Pump LCM as required (consult prepared lost returns decisions
tree), slow pump rates, reduce ROP or trip speed when necessary.
Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole
if required.
Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA,
monitor torque and drag trends.
Anti-Collision Closely monitor real-time surveys and run GWD in BHA
12-1/4 and 8-1/2 Intermediate Hole Sections
Hazard Mitigations
Lost Returns Optimal drillpipe sizing. MPD to be used to manage ECD loads (8-
1/2 hole only). Monitor ECD with MWD tools. Pump LCM as
required, slow pump rates and RPM, reduce ROP or trip speed
when necessary. ECD modelling for optimized cement jobs.
Challenging liner runs The Intermediate liner runs requires relatively low OH friction
factor to run to TD (hole cleaning and lubricants). Ability to rotate
while RIH to overcome drag.
Washouts/Hole Enlargement Drill with oil-based mud, maintain mud in specifications, use
sufficient mud weight / back-pressure to hold back formations.
Tight Hole/Stuck Pipe Hole cleaning and tripping practices, drilling jars included in BHA,
monitor torque and drag trends, use sufficient mud weight / back-
pressure to hold back formations.
Hole Cleaning in 84° Sail Conduct T&D and hydraulics modeling, control ROP limits based
on cuttings returns and comparison to the models.
Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage
circulation rates up while running in hole with liner. Circulate
bottoms up at multiple depths to condition mud the way in the
hole. Circulate at TD to planned cementing rates and ensure hole
is clean.
Wireline Inaccessibility The sail angle on this section is too high for wireline to be run
conventionally. If wireline logs are required for operations a
tractor will be required.
Operational complexity with
Mechanical two stage
cement equipment (9-5/8
Liner)
The 2nd stage of the cement job will be conducted through a
mechanically shifted sleeve. This will require the LTP to not be set
until the 2nd stage is pumped giving a higher complexity leading to
complications with setting the LTP.
6-1/8 Production Hole Section
Hazard Mitigations
Lost Returns Optimal drillpipe sizing. MPD to be used to control ECD loading.
Monitor ECD with MWD tools. Pump LCM as required, slow pump
rates and RPM, reduce ROP or trip speed when necessary.
Well Control MPD utilized with 7.5-8.0ppg MW to provide adequate dynamic
and static overbalance. Normal BOP well control procedures.
Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole
if required.
Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA,
monitor torque and drag trends, use sufficient mud weight / back-
pressure to hold back formations.
Wellbore Instability Maintain adequate mud weight / back-pressure for wellbore
stability. Monitor cuttings returns, LWD logs, and drilling
parameters for signs of washout. MPD to minimize pressure cycles
on formation.
Challenging liner run The production liner run requires relatively low OH friction factor
to run to TD (hole cleaning and lubricants). Ability to rotate while
RIH to overcome drag.
* Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well.
Attachment 5A: Leak Off Test Procedure (Conventional)
1. Drill out shoe track, cement plus minimum of 20 of new formation. Circulate bottoms up and
confirm cuttings are observed at surface.
2. Circulate and condition the mud:
a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired
mud properties. Consider pulling the bit into the casing shoe to prevent wash out.
b. Accurately measure the mud weight with a recently calibrated pressurized mud balance;
c. Confirm that mud weight-in is equal to mud weight-out;
d. Do not change the mud weight until after the test.
3. Pull the bit back into the casing shoe.
4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above
expected test pressure.
a. Record pressure at surface with calibrated chart recorder.
5. Break circulation down the string.
6. Verify the hole is filled up and close the BOP (annular or upper pipe ram).
7. Perform the LOT or FIT pumping at a constant rate of 0.50bbl/min (or as low as possible). Record
pump pressures at 0.25bbl increments (~2 stokes).
8. Record and plot the volume pumped against pressure until leak-off is observed, or until the
predetermined limit pressure/EMW has been reached for a FIT.
a. Leak-off is defined as the first point on the volume/pressure plot where either the initial
static pressure or the final static pressure deviates from the trend observed in the
previous observations.
b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This
indicates a leak in the system, cement failure or formation breakdown. Record the
pressures every minute until they stabilize. If the drop in pressure is related to formation
breakdown, this data can be used to derive the minimum in-situ stress.
c. If FIT skip step 9.
9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off.
10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial
shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments
for the first five minutes and then every one minute for the remainder of the shut in period.
11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement
bond.
12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to
establish the volume of mud lost to the formation. Top up and close the annulus valve between
the casing and the previous casing string.
13. Open the BOP.
Attachment 5B: Leak Off Test Procedure (With MPD)
1. Drill out shoe track and cement. Install MPD Bearing Assembly and drill a minimum of 20 of new
formation, holding required EMW using the MPD choke manifold. Circulate bottoms up and
confirm cuttings are observed at surface.
2. Circulate and condition the mud:
a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired
mud properties. Consider pulling the bit into the casing shoe to prevent wash out.
b. Accurately measure the mud weight with a recently calibrated pressurized mud balance;
c. Confirm that mud weight-in is equal to mud weight-out;
d. Do not change the mud weight until after the test.
3. Pull the bit back into the casing shoe, continuing to hold required EMW using the MPD choke.
4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above
expected test pressure.
a. Record pressure at surface with calibrated chart recorder.
5. Break circulation down the string with the MPD chokes closed (i.e. well shut-in).
6. Starting at the MPD set-point pressure (back pressure needed for required baseline EMW),
perform the LOT or FIT pumping at a constant rate of 0.50bbl/min (or as low as possible). Record
pump pressures at 0.25bbl increments (~2 stokes).
7. Record and plot the volume pumped against pressure until leak-off is observed, or until the
predetermined limit pressure/EMW has been reached for a FIT.
a. Leak-off is defined as the first point on the volume/pressure plot where either the initial
static pressure or the final static pressure deviates from the trend observed in the
previous observations.
b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This
indicates a leak in the system, cement failure or formation breakdown. Record the
pressures every minute until they stabilize. If the drop in pressure is related to formation
breakdown, this data can be used to derive the minimum in-situ stress.
c. If FIT skip step 9.
8. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off.
9. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial
shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments
for the first five minutes and then every one minute for the remainder of the shut in period.
10. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement
bond.
11. Bleed off pressure (through MPD choke) down to the starting MPD set-point pressure and record
the volume returned to establish the volume of mud lost to the formation.
Attachment 6: Cement Summary
Surface Casing Cement
Casing
Size 13-3/8 68# L-80 BTC/TXP-BTC Surface Casing
Basis
Lead Open hole volume + 150% excess in permafrost / 50% excess below permafrost
Lead TOC Surface
Tail Open hole volume + 50% excess + 65 ft shoe track
Tail TOC 500 ft MD above casing shoe
Total
Cement
Volume
Spacer ~80 bbls of 10.5 ppg Tuned Spacer
Lead 11.0ppg Lead: 368 bbls, 2068 cuft, 818 sks ArcticCem, Yield: 2.53 cuft/sk
Tail 15.3ppg Tail: 66 bbls, 370 cuft, 298 sks HalCem Type I/II 1.24 cuft/sk
Temp BHST ~60° F (2.25°/100 TVD below PermaFrost)
Verification Method Cement returns to surface
Notes Job will be mixed on the fly
NDB-039 13-3/8in Surface Casing Cement Job
Well Details
Casing Stick Up on Rig Floor -4 ft MD 16.000 "
Float Collar Depth 2847 ft MD 13.375 "
Casing Shoe Depth 2912 ft MD 12.415 "
TD Hole Depth 2912 ft MD 19.250 "
Base Permafrost 1416 ft MD
Previous Casing Shoe 128 ft MD
Top of Previous Casing/Surface 46 ft MD
Tail Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
13-3/8" Shoe Track 2847 2912 65 12.415 0.1497 9.7 0% 0 9.7
16" Open Hole x 13-3/8" Casing below base Permafrost 2412 2912 500 16.000 13.375 0.0749 37.5 50% 18.7 56.2
65.9
Lead Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
16" Open Hole x 13-3/8" Casing below base Permafrost 1416 2412 996 16.000 13.375 0.0749 74.6 50% 37.3 111.9
16" Open Hole x 13-3/8" Casing above base Permafrost 128 1416 1288 16.000 13.375 0.0749 96.5 150% 144.7 241.2
Conductor x 13-3/8" Cased Hole 46 128 82 19.250 13.375 0.1862 15.3 0% 0.0 15.3
368.4
Displacement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
13-3/8 68# L-80 BTC/TXP-BTC Surface Casing to Float Colla -4 2847 2851 12.415 0.1497 426.9 0% 426.9
426.9
Previous Casing ID
Casing ID
Casing OD
Hole Size
Verified cement calcs. -bjm
Intermediate #1 Liner Cement
Casing
Size 9-5/8 47# L-80 Hydril 563 Intermediate Liner #1
Basis
Tail Open hole volume + excess + 85 ft shoe track
Tail TOC Stage 1: 1000 MD above the shoe
Stage 2: Top of the 9-5/8 Liner
Total
Cement
Volume
Spacer ~80 bbls of 12.5 ppg Clean Spacer
Tail
Stage 1: 30% Open Hole Excess
15.3ppg Tail: 79 bbls, 442cuft, 357sks VersaCem Type I/II 1.24 cuft/sk
Stage 2: 100% Open Hole Excess
14.5ppg Tail: 341 bbls, 1915cuft, 1378sks SwiftCem Type I/II 1.39 cuft/sk
Temp Stage 1 - BHST ~80° F (2.25°/100 TVD below PermaFrost)
Stage 2 - BHST ~71° F (2.25°/100 TVD below PermaFrost)
Notes Job will be mixed on the fly
Verification Method
- 1st Stage Cement Job will not be logged, assuming job parameters are as
expected (no losses, good lift pressures, FIT / LOT results).
- 2nd Stage Cement Job will not be logged, assuming job parameters are as
expected (no losses, good lift pressures, circulate cement off top of liner).
Justification:
- 1st stage is only designed to provide adequate cement integrity around the
shoe (i.e. Nanushuk will be isolated with 7 shoe)
- Stage tool allows for precise placement of base cement column at base
Tuluvak hydrocarbon.
- Bond log not required for 2nd Stage per Regulation 20 AAC 25.030(d)(5)
- 2nd Stage bond evaluation does not affect 1st Stage bond evaluation and frac
decision.
- 2nd Stage cement job will isolate Tuluvak with cement and a V0-rated LTP
above it as a redundant means of isolation.
- Well design allows for the OA annulus to be freeze protected by circulating in
place (with Tieback) vs. bullheaded into place. With a sufficient initial
LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be
contained by the surface casing shoe and not cross flow into shallower
formations.
- Tuluvak isolation has been achieved on all historical Pikka development
wells.
- Seeking to simplify an already complicated operation, saving time/money.
Verified cement calcs. -bjm
NDB-039 9-5/8in Intermediate #1 Liner - Stage 1 Cement Job
Well Details
Stick Up on Rig Floor -4 ft MD 12.250 " HWDP Length 2176 ft MD
Top of Liner 2762 ft MD 9.625 " DP Length 590 ft MD
Cflex Depth 5889 ft MD 8.681 "HWDP Capacity 0.0155 bbl/ft
Landing Collar Depth N/A ft MD 12.415 " DP Capacity 0.0241 bbl/ft
Float Collar Depth 11415 ft MD
Casing Shoe Depth 11500 ft MD
TD Hole Depth 11500 ft MD
Previous Casing Shoe 2912 ft MD
Tail Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
9-5/8" Shoe Track 11415 11500 85 8.681 0.0732 6.2 0% 0 6.2
12-1/4" Open Hole x 9-5/8" Casing 10500 11500 1000 12.250 9.625 0.0558 55.8 30% 16.7 72.5
78.7
Lead Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
0.0
Displacement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
5-7/8" 23.4# S135 Delta576 DP -4 586 590 0.0241 14.2 14.2
5-7/8" x 4" 130ksi Delta576 HWDP 586 2762 2176 0.0155 33.7 33.7
Liner Running Tools 2762 2807 45 2.5 0.0061 0.3 0.3
9-5/8 47# L-80 Hydril 563 Casing to Float/Landing Collar 2807 11415 8608 8.681 0.0732 630.2 630.2
678.4
Hole Size
Casing OD
Casing ID
Previous Casing ID
NDB-039 9-5/8in Intermediate #1 Liner - Stage 2 Cement Job
Well Details
Stick Up on Rig Floor -4 ft MD 12.250 " HWDP Length 2176 ft MD
Top of Liner 2762 ft MD 9.625 " DP Length 590 ft MD
Cflex Depth 5889 ft MD 8.681 "HWDP Capacity 0.0155 bbl/ft
Landing Collar Depth N/A ft MD 12.415 " DP Capacity 0.0241 bbl/ft
Float Collar Depth 11415 ft MD
Casing Shoe Depth 11500 ft MD
TD Hole Depth 11500 ft MD
Previous Casing Shoe 2912 ft MD
Tail Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
12-1/4" Open Hole x 9-5/8" Casing 2912 5889 2977 12.250 9.625 0.0558 166.1 100% 166.1 332.1
13-3/8" Cased Hole x 9-5/8" Casing 2762 2912 150 12.415 9.625 0.0597 9.0 0% 0.0 9.0
341.1
Lead Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
0.0
Displacement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
5-7/8" 23.4# S135 Delta576 DP -4 586 590 0.0241 14.2 14.2
5-7/8" x 4" 130ksi Delta576 HWDP 586 2762 2176 0.0155 33.7 33.7
5-7/8" 23.4# S135 Delta576 DP 2762 5889 3127 0.0241 75.4 75.4
123.3
Hole Size
Casing OD
Casing ID
Previous Casing ID
Intermediate #2 Liner Cement
Casing
Size 7 26# L-80 Hydril 563 Intermediate Liner #2
Basis
Lead No Lead planned
Lead TOC No Lead Planned
Tail Open hole volume + 30% excess + 125 ft shoe track
Tail TOC 200 TVD above the top Nanushuk
Total
Cement
Volume
Spacer ~80 bbls of 12.5 ppg Clean Spacer
Lead No Lead Planned
Tail 15.3ppg Tail: 156 bbls, 874cuft, 704sks VersaCem Type I/II 1.24 cuft/sk
Temp BHST ~99° F (2.25°/100 TVD below PermaFrost)
Notes Job will be mixed on the fly
Verification Method
- LWD Sonic will be used to log the cement job.
Justification:
- Future hydraulic fracture operations will only be done in the Nanushuk
formation. Log verification of the cement job will verify proper
isolation has been achieved for frac operations.
NDB-039 7in Intermediate #2 Liner Cement Job
Well Details
Stick Up on Rig Floor -4 ft MD 9.875 " HWDP Length 758 ft MD
Top of Liner 11350 ft MD 7.000 " DP Length 10596 ft MD
Landing Collar Depth 15616 ft MD 6.276 "HWDP Capacity 0.0087 bbl/ft
Float Collar Depth n/a ft MD 8.681 " DP Capacity 0.0171 bbl/ft
Casing Shoe Depth 15741 ft MD
TD Hole Depth 15741 ft MD
Previous Casing Shoe 11500 ft MD
Tail Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
7" Shoe Track 15616 15741 125 6.276 0.0383 4.8 0% 0 4.8
9-7/8" Open Hole x 7" Casing 13280 15741 2461 9.875 7.000 0.0471 116.0 30% 34.8 150.8
155.6
Lead Cement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
0.0
Displacement Calculations
Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess
ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl
5" 19.5# S135 Delta544 DP -4 10592 10596 0.0171 181.2 181.2
5" x 3" Delta544 HWDP 10592 11350 758 0.0087 6.6 6.6
Liner Running Tools 11350 11395 45 2.5 0.0061 0.3 0.3
7 26# L-80 Hydril 563 Casing to Float/Landing Collar 11395 15616 4221 6.276 0.0383 161.5 161.5
349.6
Hole Size
Casing OD
Casing ID
Previous Casing ID
Verified cement calcs. -bjm
Attachment 7: Prognosed Formation Tops
NDB-039 Prognosed Tops
Formation MD
(ft)
TVD KB
(ft)
TVDss
(ft)
Pore Pressure
(ppg)
Upper Schrader Bluff 1043 1033 963 7.2
Base Permafrost Transition 1416 1385 1315 7.3
Middle Schrader Bluff 1839 1750 1680 7.6
MCU 2413 2155 2085 7.8
Tuluvak Shale 3017 2446 2376 7.9
Tuluvak Sand 3214 2508 2438 10.2
TS_790 5839 2813 2743 9.4
Seabee 11015 3364 3294 9.1
Nanushuk 14719 3805 3735 8.9
NT8 MFS 14946 3856 3786 8.9
NT7 MFS 15146 3905 3835 8.9
NT6 MFS 15289 3942 3872 8.9
NT5 MFS 15442 3983 3913 8.8
NT4 MFS 15611 4030 3960 8.8
NT3 MFS 15739 4066 3996 8.8
NT3.2 Top Reservoir 15799 4082 4012 8.8
Attachment 8: Well Schematic
Attachment 9: Formation Evaluation Program
16 Surface Hole
LWD Gamma Ray
Resistivity
12-1/4 Intermediate Hole #1
LWD Gamma Ray
Resistivity
8-1/2 x 9-7/8 Intermediate Hole #2
LWD Gamma Ray
Resistivity
8-1/2 Production Hole
LWD
Gamma Ray
Resistivity
Density Neutron
Sonic (7 Liner Cement Evaluation Only)
Mudlogging
No mudlogging is planned for NDB-039
Attachment 10: Wellhead & Tree Diagram
Attachment 11: Diverter Variance Request NDB Surface Hole Map View
Attachment 12: Oil Search Alaska 21-day BOPE Test Schedule Waiver Approval Letter
Attachment 13: Managed Pressure Drilling
Managed Pressure Drilling (MPD) will be implemented on NDB-039 in both the Intermediate #2 and
Production sections of the well. The MPD system will be provided by Beyond Energy Services and
Technology with an integrated piping and choke manifold on the Nabors 272 rig. The only MPD
equipment located outside of the rig will be the nitrogen rack.
The plan in the 8-1/2 x 9-7/8 Intermediate hole will be to drill with a reduced 9.5 - 11.0ppg mud weight
and utilize MPD to trap back-pressure in order to manage ECD for losses as well as providing adequate
pressures to maintain wellbore stability through the Seabee and Nanushuk formations. Weighted trip
fluids will be utilized to maintain downhole pressures for the final trip out and running of the 7 liner.
The plan in the 6-1/8 Production hole will be to drill with a reduced 7.5 8.0ppg mud weight with MPD
utilized to trap back-pressure in order to maintain adequate overbalance for pore pressure and wellbore
stability and manage ECD for losses through the Nanushuk formations. Weighted trip fluids will be utilized
to maintain downhole pressures for the final trip out and running of the 4-1/2 liner.
The production hole will remain statically and dynamically overbalanced at all times using MPD.
See below for a schematic of the BOP/MPD stack with the choke flow diagram.
Attachment 14: As Staked Survey NDB Well 39 Conductor Final
1
McLellan, Bryan J (OGC)
From:Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>
Sent:Tuesday, January 6, 2026 3:25 PM
To:McLellan, Bryan J (OGC); Conwell, Russell (Russell)
Subject:RE: NDB-039 PTD question
Bryan,
That is a heel to toe close approach, as the NDB-039 heel section will be landing in front of the NDB-051 toe. We
plan to use lithological separation as the primary means of mitigating the collision risk between the NDB-039 and
NDB-051. During the close approach interval, we will be in the INT2 section of NDB-039 in the Upper Nanushuk
formations (currently projected to be in the NT7 or NT8), whereas the NDB-051 toe is in the NT3.2 reservoir.
As the INT2 section is set above the top of the NT3.2, there will be no anti-collision issues while drilling the
production hole of NDB-039.
Let me know if you have any questions.
Thanks,
Mark
Mark Staudinger
Senior Drilling Engineer
m: +1 520 273 6643 | e: mark.staudinger@santos.com
Santos.com | Follow us on LinkedIn, Facebook and Twitter
Santos acknowledges the Traditional Owners and Custodians of the lands on which we operate. We pay our respects
to their Elders past, present and emerging.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, January 6, 2026 3:07 PM
To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>; Conwell, Russell (Russell) <Russell.Conwell@santos.com>
Subject: ![EXT]: NDB-039 PTD question
Mark, Russell,
Looks like a potential close approach issue with NDB-051. What mitigations will be in place in case of
collision?
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
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
Santos Ltd A.B.N. 80 007 550 923
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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.
Pikka NDB-039
NANUSHUK OILPIKKA
225-144
WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDB-039Initial Class/TypeDEV / PENDGeoArea890Unit11580On/Off ShoreOnProgram DEVWell bore segAnnular DisposalPTD#:2251440Field & Pool:PIKKA, NANUSHUK OIL - 600100NA1 Permit fee attachedYesADL0392991, ADL0392970, and ADL03929682 Lease number appropriateYes3 Unique well name and numberYes PIKKA, NANUSHUK OIL - 600100 - governed by CO 8074 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes Variance to allow gap in coverage between stages.21 CMT vol adequate to tie-in long string to surf csgYes There are 3 cementing variances, but all productive horizons are covered22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes Close approach email discusses anti-collision scan warning26 Adequate wellbore separation proposedNA Diverter waiver granted.27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes BOP test frequency variance granted29 BOPEs, do they meet regulationYes MPSP = 1479 psi, BOP rated to 5000 psi (BOP test to 3600 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S measures not required: None anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Tuluvak (with shallow gas) pressures anticipated to be 10.2 ppg EMW. Nanushuk reservoir at 8.8 ppg EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate06-Jan-26ApprBJMDate06-Jan-26ApprADDDate06-Jan-26AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 1/7/2026
