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7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in this pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd?Yes No
Subsequent Form Required:
Approved By:Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU 11-41
Extended Perforating
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK
99503
224-017
50-029-23782-00-00
ADL 028325 & 028322
15906
Conductor
Surface
Intermediate
Production
Liner
8585
79
5217
11891
4128
15784
20"
10-3/4"
7"
4-1/2"
8617
48 - 127
48 - 5265
45 - 11936
11774 - 15902
2420
48 - 127
48 - 3855
45 - 8338
8218 - 8585
None
2480
5410
7500
none
5210
7240
8430
None 4-1/2" 12.6# 13Cr80 43 - 11781None
Structural
4-1/2" HES TNT Perm
No SSSV
11650
8127
Date:
Bo York
Operations Manager
Dave Bjork
David.Bjork@hilcorp.com
(907)564-4672
PRUDHOE BAY
6/5/25
Current Pools:
PRUDHOE OIL
Proposed Pools:
PRUDHOE OIL
Suspension Expiration Date:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 4:20 pm, May 01, 2025
Digitally signed by Bo York
(1248)
DN: cn=Bo York (1248)
Date: 2025.05.01 13:03:49 -
08'00'
Bo York
(1248)
325-274
A.Dewhurst 27MAY25
10-404
Perforating gun not to exceed 500'.
Reestablish pressure containment prior to perforating.
Perform and document well control drill on each shift using attached standing orders.
Ensure well is dead before breaking containment
DSR-5/1/25JJL 5/9/25
*&:
5/28/2025
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.05.28 14:43:40
-08'00'
RBDMS JSB 052925
Ext Add Perf
11-41
PTD:224-017
Well Name:11-41 API Number:50-029-23782-00
Current Status:Operable - Producer Rig:CTU
Estimated Start Date:6/05/25 Estimated Duration:2days
Reg.Approval Req’std?10-403 Date Reg. Approval Rec’vd:Check status
Regulatory Contact:Carrie Janowski (907) 564-5179
First Call Engineer:David Bjork (907) 564-4672 (907) 440-0331
Expected Rates Post Work ~27 MMSCFD, 700 BOPD and 100BWPD
Current Bottom Hole Pressure:3,300 psi @ 8,800’ TVD 7.3 PPGE | (Average Ivishak BHP)
Maximum Expected BHP:3,300 psi @ 8,800 TVD 7.3 PPGE | (Average Ivishak BHP)
Max. Anticipated Surface Pressure:2,420psi (Based on 0.1 psi/ft. gas gradient)
Last SI WHP:2,285 psi (Taken on 7/28/24)
Min ID:3.725” 4-1/2” XN @ 11,755’ MD
Max Angle:98 Deg @ 15,499’ MD, 70 Deg at 12,578’ MD
Brief Well Summary:
2024 new drill FURy 1A well. We are proposing to fill in with additional mid lateral and heel perfs.
Objective:Perforate remaining unswept Z1A mid lateral and heel.
Procedure
Coiled Tubing
1. MU drift BHA with GR/CCL in 2.25” carrier, drift to 14,700ft.
2. Correlate with attached log information.
a. Correct flag and send to OE for confirmation.
Coil – Extended Perforating
Notes:
x Remote gas monitoring for H2S and LELs are required for Open Hole Deployment Operations
x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS
coverage is required.
The well will be killed and monitored before making up the initial perf guns. This is generally done during the
drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating
bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by
bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head.
1. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through
the brass upon POOH with guns.
2. Bullhead 1.2x wellbore volume ~240bbls 1% KCL/SW down tubing. Max tubing pressure 2500 psi.
(This step can be performed any time prior to open-hole deployment of the perf guns. Timing of the
well kill is at the discretion of the WSS.)
a. Wellbore volume to top perf = 197bbls
b. 4-1/2” tubing/liner – 12,940’ X .0152 bpf = 197bbls
3. At surface, prepare for deployment of TCP guns.
4. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/KWF, 8.4 ppg 1% KCl or 8.5
ppg as needed. Maintain hole fill taking returns to tank until lubricator connection is re-established.
Ext Add Perf
11-41
PTD:224-017
Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed
and there is no excess flow.
5.*Perform drill by picking up safety joint with TIW valve and space out before MU guns. Review standing
orders with crew prior to breaking lubricator connection and commencing makeup of TCP gun string
(document for each tour). Once the safety joint and TIW valve have been spaced out, keep the safety
joint/TIW valve readily accessible near the working platform for quick deployment if necessary.
c.At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns
one time to confirm the threads are compatible.
6.Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly
monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed
while deploying perf guns to ensure the well remains killed and there is no excess flow.
Perf Schedule
Use 2-7/8” MaxForce guns or similar
Perf Interval (tie-in depths) Lengths
Total Gun
Length Weight of Gun (lbs)
Run #1 14,194’ - 14,383’
14,438’ – 14,580’
54’ of blanks 386’~4,790 lbs (12.41ppf)
Run #2 12,658’ – 12,714’
12,748’ – 12,835’
34’ blanks 177’~2,196 lbs (12.41ppf)
7. RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate interval per Perf Schedule
above.
a. Note any tubing pressure change in WSR.
8. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and
stick the BHA. Confirm well is dead and re-kill if necessary before pulling to surface.
9. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary.
10. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and
commencing breakdown of TCP gun string.
11. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA.
12. RDMO CTU.
13. Turn well over to Operations POP.
Attachments: Wellbore Schematic, Proposed Schematic, Tie-In Log, BOPE and rig-up diagram, Sundry Change
Form
Ext Add Perf
11-41
PTD:224-017
Current Wellbore Schematic
Ext Add Perf
11-41
PTD:224-017
Proposed Wellbore Schematic
12,658’-12,714’
12,748’-12,835’
14,194’-14,384’
14,438’-14,580’
New Perforations
Ext Add Perf
11-41
PTD:224-017
Tie-in Log
Ext Add Perf
11-41
PTD:224-017
Ext Add Perf
11-41
PTD:224-017
BOP Schematic
Ext Add Perf
11-41
PTD:224-017
Ext Add Perf
11-41
PTD:224-017
7. Property Designation (Lease Number):
1. Operations
Performed:
2. Operator Name:
3. Address:
4. Well Class Before Work:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
Susp Well Insp
Install Whipstock
Mod Artificial Lift Perforate New Pool
Perforate
Plug Perforations
Coiled Tubing Ops
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well Other:
Change Approved Program
Operations shutdown
11. Present Well Condition Summary:
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
16. Well Status after work:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
OIL GAS
WINJ WAG GINJ
WDSPL
GSTOR Suspended SPLUG
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
PBU 11-41
Set Polar Choke
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
224-017
50-029-23782-00-00
15906
Conductor
Surface
Intermediate
Production
Liner
8585
79
5217
11891
4128
15784
20"
10-3/4"
7"
4-1/2"
8617
48 - 127
48 - 5265
45 - 11936
11774 - 15902
48 - 127
48 - 3855
45 - 8338
8218 - 8585
None
2480
5410
7500
none
5210
7240
8430
None
4-1/2" 12.6# 13Cr80 43 - 11781
None
Structural
4-1/2" HES TNT Perm
8127
11650
8127
Bo York
Operations Manager
Dave Wages
David.Wages@hilcorp.com
(907) 564-4816
PRUDHOE BAY / PRUDHOE OIL
Total Depth
Effective Depth
measured
true vertical
feet
feet
feet
feet
measured
true vertical
measured
measured
feet
feet
feet
feet
measured
true vertical
Plugs
Junk
Packer
Measured depth
True Vertical depth
feet
feet
Perforation depth
Tubing (size, grade, measured and true vertical depth)
Packers and SSSV
(type, measured and true vertical depth)
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.Representative Daily Average Production or Injection Data
Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure
Prior to well operation:
Subsequent to operation:
15. Well Class after work:
Exploratory Development Service StratigraphicDaily Report of Well Operations
Copies of Logs and Surveys Run
Electronic Fracture Stimulation Data
Sundry Number or N/A if C.O. Exempt:
ADL 028325 & 028322
43 - 8224
552
445
26180
19163
52
85
1933
926
807
720
N/A
13b. Pools active after work:PRUDHOE OIL
No SSSV
11650
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
Sr Pet Eng: Sr Pet Geo:
Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Sr Res Eng:
Due Within 30 days of Operations
By Grace Christianson at 9:29 am, Aug 26, 2024
Digitally signed by Bo York
(1248)
DN: cn=Bo York (1248)
Date: 2024.08.23 19:49:25 -
08'00'
Bo York
(1248)
RBDMS JSB 090324
DSR-8/26/24WCB 10-3-2024
ACTIVITYDATE SUMMARY
7/27/2024
LRS CTU #1 1.75" .156 Blue Coil Job Scope: Drift/Log, Set DH Choke
MIRU CTU. M/U NS MHA
**Continued to WSR on 7/28/24**
7/28/2024
LRS CTU #1 1.75" .156 Blue Coil Job Scope: Drift/Log, Set DH Choke
M/U HES GR/CCL. Load well w/6bbls 50/50, 180bbls safelube, 10bbls diesel. RIH
and tag bttm @ 15817. Log up to 14800'. Stop due to 6K wt consistently increasing
over this interval. Pump 36 bbls Safelube while RBIH. 12K decrease in Up Wt. Log
GR/CCL from TD @ 15817' @ 50 fpm. Paint EOP flag @ 15032'. Continue logging to
11550' per program. POH and download data. +24' correction. RIH w/ NS 2.20" CTC,
2.13" MHA, 4' stinger,2.70" setting tool, 3.57" adapter, and 3.59" Polar Chk w/ .3125"
orifice (OAL 17.45'). Tie in to EOP flag and set Polar Chk @ 15065' MD. PU freely.
Stack 4k down to check set. POH. No FP. Ops to POP immediately. RDMO
**Job Complete**
Daily Report of Well Operations
PBU 11-41
set Polar Chk @ 15065' MD.
Ext Add Perf
11-41
PTD:224-017
Changes to Approved Sundry Procedure
Date:
Subject:
Sundry #:
Any modifications to an approved sundry will be documented and approved below. Changes to an
approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written
approval of the change is required before implementing the change.
Step Page Date Procedure Change
HAK
Prepared
By
(Initials)
HAK
Approved
By
(Initials)
AOGCC
Written
Approval
Received
(Person
and Date)
Approval:
Operations Manager Date
Prepared:
Operations Engineer Date
By Grace Christianson at 10:01 am, May 28, 2024
Complete
5/7/2024
JSB
RBDMS JSB 060524
GDSR-6/18/24MGR19DEC2025
Drilling Manager
05/28/24
Monty M
Myers
Digitally signed by Bo York
(1248)
DN: cn=Bo York (1248)
Date: 2024.05.28 09:32:43 -
08'00'
Bo York
(1248)
Note: Lined spaces provided. Do Not add or delete rows from the tables. If you have more data than spaces provided, don't
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU DS11-41 Date:4/3/2024
Csg Size/Wt/Grade:10.75 45.5# L-80 Supervisor:Barber/Carter
Csg Setting Depth:5265 TMD 3914 TVD
Mud Weight:9.5 ppg LOT / FIT Press =682 psi
LOT / FIT =12.85 ppg Hole Depth =5291 md
Fluid Pumped=3.2 Volume Back =3.0 bbls
Estimated Pump Output:0.093 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->035 ->00
->2135 ->6200
->4208 ->12 560
->6293 ->18 820
->8381 ->24 1100
->10 461 ->30 1370
->12 541 ->36 1660
->14 614 ->42 1945
->16 682 ->48 2215
->18 742 ->54 2500
->20 798 ->60 2780
->22 846 ->66 3065
->24 891 ->70 3190
->26 928 ->
->28 960
->30 984
->32 1008
->34 1008
->36
->38
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->1 1008 ->03190
->2927 ->13185
->3832 ->23181
->4750 ->33176
->5671 ->43172
->6632 ->53171
->7611 ->63169
->8582 ->73167
->9559 ->83166
->10 522 ->93165
->10 3162
->15 3161
->20 3155
->30 3151
use all data points. Record all casing test pressures and volumes even though the higher values will not appear on the gra
0
2
4
6
8
10
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14
16
18
20
22
24 26 28 30 32 34
0
5
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35
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65
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3300
0 10203040506070
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
aph.
650610589576564556547540534528522
32343233323232303230322932283228322632263224 3221 3220 3218
0
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0 5 10 15 20 25 30
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e
s
s
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r
e
(
p
s
i
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Time (Minutes)
LOT / FIT
DATA
CASING TEST
DATA
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU 11-41 Date:4/17/2024
Csg Size/Wt/Grade:7" 26# L-80 BTC Supervisor:Anderson/Amend
Csg Setting Depth:11,936 TMD 8,338 TVD
Mud Weight:8.55 ppg LOT / FIT Press =805 psi
LOT / FIT =10.41 ppg Hole Depth =11960 md
Fluid Pumped=1.4 Bbls Volume Back =1.4 bbls
Estimated Pump Output:0.093 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->281 ->2 120
->4173 ->7 350
->6253 ->13 794
->8335 ->22 1190
->10 419 ->26 1410
->12 499 ->30 1630
->14 582 ->39 2198
->16 662 ->42 2380
->18 744 ->46 2575
->19 805 ->49 2850
-> ->53 3119
-> ->56 3331
-> ->63 3810
-> ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0805 ->03810
->1783 ->13805
->2777 ->23802
->3775 ->33800
->4772 ->43799
->5769 ->53798
->6767 ->10 3792
->7765 ->15 3786
->8763 ->20 3782
->9761 ->25 3780
->10 759 ->30 3778
-> ->
-> ->
-> ->
2
4
6
8
10
12
14
16
18
19
2
7
13
22
26
30
39
42
46
49
53
56
0
100
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2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 10203040506070
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
805783777775772769767765763761759
380037993798 3792 3786 3782 37803778
0
100
200
300
400
500
600
700
800
900
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3800
0 5 10 15 20 25 30
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Time (Minutes)
LOT / FIT
DATA
CASING TEST
DATA
613
ACTIVITYDATE SUMMARY
5/2/2024
T/I/O=0/0/0. Post Parker 273. Removed 4" dryhole swab and installed 4" CIW
production tree. Torqued flanges to spec. Pressure tested upper tree against MV to
500/5000 psi. Passed. Installed wellhouse floor kit. ***Job Complete***
5/3/2024
***WELL S/I ON ARRIVAL*** (New well post)
PULLED BALL & ROD f/ RHC @ 11755' MD
PULLED BK-DGLV'S IN ST# 1 (11588' MD), ST# 2 (11014' MD), ST# 3 (10108' MD)
ST# 4 (8790' MD) & ST# 5 (7100' MD)
PULLED BEK-SOV IN ST# 6 (4619' MD)
SET BK-LGLV'S IN ST# 6 (4619' MD), ST# 5 (7,100' MD), ST# 4 (8,790' MD), ST# 3
(10,109' MD)
***CONTINUE ON 5/4/24 WSR***
5/4/2024
***CONTINUED FROM 5/3/24 WSR*** (New well post)
SET BK LGLV IN ST# 2 (11,014' MD)
SET BK-OGLV IN ST# 1 (11,588' MD)
PULLED 3.81" RHC PLUG BODY @ 11755' MD
***JOB COMPLETE, WELL LEFT S/I, DSO NOTIFIED***
5/6/2024
LRS CTU #2 - 2" CT, 0.156" WT. Job Objective: Drift/CBL, Ext Adperfs
Mobilize CTU #2. Stand-by for well support to finish R/U. MIRU CTU #2. MU NS
ctc/MHA and pull against the brass. MU HES CCL/GR CBL w/ 3.23" drift. RIH and
drift cleanly to 15800' CTM. Start pumping a bottom up of 2% slick KCL with safelube
to circ the PowerPro out of the liner.
***Job in Progress***
5/7/2024
LRS CTU #2 - 2" CT, 0.156" WT. Job Objective: Drift/CBL, Ext. Adperfs
Circulate 2% slick KCL with safelube from 15800' to surface. Log from 15800' to
11500' at 50 FPM. Painted a yellow tie-in flag at 15000'. POOH and circulate 60/40
from 4500'. Break down HES CBL tool and confirm good data (+8' correction). PT NS
MHA ~ 3500 psi. Deploy 200' of 2-7/8" MaxForce, 6 SPF, 60 degree phase perf guns
and RIH taking returns. 3 hours of LRS NPT to change out injector counter balance
valve. Continue RIH, tie-in to the yellow flag, and perforate 15,075' - 15,275'. POOH
pumping KCL at 0.8 BPM down the CTB. Well control drill for open hole deployment.
Perform no-flow test and un-deploy 200' of 2-7/8" guns (all shots fired in scallop, 5/8"
ball recovered). PT MHA ~ 3500 psi. Start deploying 2-7/8" guns.
***Job in Progress***
5/8/2024
LRS CTU #2 - 2" CT, 0.156" WT. Job Objective: Drift/CBL, Ext. Adperfs.
Continue deploying 425' of 2-7/8" MaxForce, 6 SPF, 60 degree phase perf guns. RIH,
tie-in to the flag at 14550', and perforate 14600' - 15025'. Good indication of shot,
lose returns. POOH pumping KCL down down the CTB. Hole fill while POOH and
laying down guns = ~ 8 BPH. MU & RIH with HES GR/CCL logging toolstring in
2.200" carrier with 3.25" DJN. Log from 14350' to 9500' at 50 FPM. Painted a
yellow/red tie-in flag at 13850'. POOH pumping KCL down the CTB. Confirm good
data (+16' correction). Perform well control drill for open hole deployment. Deploy
275' of 2-7/8" HES MaxForce, 6 SPF 60 degree phase guns and start RIH.
***Job in Progress***
Daily Report of Well Operations
PBU 11-41
Daily Report of Well Operations
PBU 11-41
5/9/2024
LRS CTU #2 - 2" CT, 0.156" CT. Job Objective: Drift/CBL, Ext. Adperf
Continue RIH with 2-7/8" guns and perforate 13900' - 14175'. Paint red flag at ~
13475'. POOH pumping KCL down the CTB. Park at 100' and perform 10 min no-flow
test. Pull to surface, estabish circulation across well, and undeploy guns. Deploy 425'
of 2-7/8" HES MaxForce, 6 SPF, 60 degree phase guns. RIH and perforate 13425' -
13850'. Paint yellow flag at 12900.47' (12888.35' EOP depth). POOH pumping KCL
w/safelube @ 80% to lubricate TBG. Perform no-flow at surface and well control drill
for open hole deployment. Lay down spent guns, and deploy 440' of 2-7/8" HES
MaxForce, 6 SPF, 60 degree phase guns. Start RIH.
***Job in Progress***
5/10/2024
***WELL S/I ON ARRIVAL***
RAN 4-1/2'' BRUSH, DOUBLE KJ, 2.60'' B. GUIDE, GUTTED 1-1/4'' JD TO 12677'
SLM
***WSR CONT. ON 05-11-2024***
5/10/2024
T/I/O = VAC/VAC/160. Temp = SI. T & IA FL (SL). ALP = 0 psi, SI @ CV.
Wellhouse, flowline removed. T & IA FL near surface.
SL in control of valves upon departure. 20:00
5/10/2024
LRS CTU #2 - 2" CT, 0.156" CT. Job Objective: Drift/CBL, Ext. Adperf
Continue RIH with 2-7/8" guns and perforate 12940' - 13380'. Paint new red tie-in flag
at 12500.23' E / 12589' M (EOP at flag = 12491.44'). Stop ~100' from surface and
perform 10 min no-flow. Pull to surface, establish circulation accross top of well, and
lay down spent guns on 4.3 BPH losses. Experienced erratic overpulls when coming
out of hole, and there's communication between TBG & IA (suspected GLV out of
pocket). Freeze protect the well from 3100 MD / 2500 TVD with 60/40. Blow down CT
string and RDMO. CTU #2 released to Santos.
***Job Complete***
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/21/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240521
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
END 3-07A 50029219110100 198147 5/11/2024 HALLIBURTON Coilflag
MPU E-19 50029227460000 197037 3/25/2024 READ CaliperSurvey
MPU F-66A 50029226970100 196162 5/8/2024 READ CaliperSurvey
MPI 1-27 50029216930000 187009 5/7/2024 READ PPROF
MPU L-17 50029225390000 194169 5/8/2024 READ CaliperSurvey
NCI A-12B 50883200320200 223053 5/2/2024 READ MAPP
NCI A-17 50883201880000 223031 5/3/2024 READ MAPP
PBU 11-41 50029237820000 224017 5/11/2024 HALLIBURTON RBT/Coilflag
PBU D-31B 50029226720200 212168 5/12/2024 HALLIBURTON RBT
PBU F-31A 50029216470100 212002 5/8/2024 READ CaliperSurvey
PBU J-19 50029216290000 186135 5/2/2024 HALLIBURTON RBT
PBU L-292 50029237510000 223025 5/6/2024 HALLIBURTON PPROF
Please include current contact information if different from above.
T38831
T38832
T38833
T38834
T38835
T38836
T38837
T38838
T38839
T38840
T38841
T38842
PBU 11-41 50029237820000 224017 5/11/2024 HALLIBURTON RBT/Coilflag
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.22 09:57:50 -08'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 05/14/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: PBU 11-41
PTD: 224-017
API: 50-029-23782-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (03/19/2024 to 04/26/2024)
• ABG-iCruise, AGR, DGR, BaseStar Gamma Ray
• EWR-M5, ADR, StrataStar Resistivity
• LithoStar Density and Porosity
• Horizontal Presentation
• (2” & 5” MD/TVD Color Logs)
• Final Definitive Directional Survey
• Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
Final Geosteering Subfolders:
Please include current contact information if different from above.
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
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
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From:Brooks, Phoebe L (OGC)
To:Steve Carter - (C)
Cc:Regg, James B (OGC)
Subject:RE: Hilcorp PBU 11-41 - Parker 273, 4-1-24 BOP Test Form 10-424
Date:Friday, May 10, 2024 4:23:51 PM
Attachments:Parker 273 04-01-24 Revised.xlsx
Steve,
Attached is a revised report changing the HCR Valves to reflect “FP” based on the remarks. I also
changed the MS Misc. fields to reflect 0 “NA”. Please update your copy or let me know if you
disagree.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the
Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or
disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it
to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Steve Carter - (C) <scarter@hilcorp.com>
Sent: Wednesday, April 3, 2024 8:32 PM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay
<doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Cc: Shane Barber - (C) <sbarber@hilcorp.com>; Brett Anderson - (C) <Brett.Anderson@hilcorp.com>;
Oliver Amend - (C) <oamend@hilcorp.com>
Subject: Hilcorp PBU 11-41 - Parker 273, 4-1-24 BOP Test Form 10-424
Please see the attached BOP Test form from our Initial test on this well.
Steve Carter
Hilcorp Alaska, LLC
Drilling Foreman
Rig: Parker 273
Office: (907) 659-5673
Personal Cell (907) 953-7333
Harmony: 7008
3%8
37'
revised report HCR Valves
MS Misc
Alternate: Oliver Amend (oamend@hilcorp.com)
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 4/1/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2240170 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: X Weekly: Bi-Weekly: Other:
Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:2468
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 1P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP
#1 Rams 1 2-7/8"x5" VBR 5M P Flow Indicator PP
#2 Rams 1 Blind/Shear 5M P Meth Gas Detector PP
#3 Rams 1 2-7/8"x5" VBR 5M P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M FP System Pressure (psi)3000 P
Kill Line Valves 2 2-1/16",3-1/8" 5M P Pressure After Closure (psi)1950 P
Check Valve 0NA200 psi Attained (sec)15 P
BOP Misc 0NAFull Pressure Attained (sec)82 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2235 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 21 P
#1 Rams 6 P
Coiled Tubing Only:#2 Rams 6 P
Inside Reel valves 0NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:6.5 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 3/31/24, 17:20
Waived By
Test Start Date/Time:4/1/2024 11:00
(date) (time)Witness
Test Finish Date/Time:4/1/2024 17:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Josh Hunt
Parker
Tested with 5" Test Joint. F/P on HCR Kill - Greased, Functioned and flushed to attain Pass. Tested with water. Functioned all
BOP Components from remote panels in the LER and Rig Managers Office and Accumulator.
Jon King / Kaleo Enfield
Hilcorp North Slope
Shane Barber / Steve Carter
PBU 11-41
Test Pressure (psi):
rig273mgr@parkerwellbore.com
sbarber@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0401_BOP_Parker273_PBU_11-41
9
9 9
9
9
9 9 9 9
9
9
9
- 5HJJ
FP
F/P on HCR Kill
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:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: 20240509 1059 PTD 224-017 Additional Perforations Request - APPROVED
Date:Thursday, May 9, 2024 10:59:54 AM
Attachments:11-41 Post-Rig Coil Ext-ADP VER2 5-8-24.docx
From: Rixse, Melvin G (OGC)
Sent: Thursday, May 9, 2024 10:57 AM
To: 'Brodie Wages' <David.Wages@hilcorp.com>
Subject: 20240509 1059 PTD 224-017 Additional Perforations Request - APPROVED
Brodie,
Approved to add 93’ perf interval as described.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake
in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Brodie Wages <David.Wages@hilcorp.com>
Sent: Thursday, May 9, 2024 6:14 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Eric Dickerman <Eric.Dickerman@hilcorp.com>
Subject: 11-41 add 6th perf interval
Hello Mel,
As discussed, please see attached program which details the additional perf interval requested. We
are adding 93’ of shots from 12,742’ – 12,835’ in the production liner section. We have currently
shot 3 intervals as of this morning. From a timing perspective, the additional interval we are
requesting will likely be shot on Saturday.
Please advise if you approve the added interval and we will proceed with the work.
David Wages
Hilcorp – OE – FS2
Cell: 713.380.9836
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
New Well Post
Well: 11-41
Current PTD: 224-017
Well Name: 11-41 API Number: 50-029-23782-00-00
Current Status: Producer Rig: SL, WT
Estimated Start Date: May 3, 2024 Estimated Duration: 5 days
New PTD Number: 224-017 Date Approval Rec’vd: 3/01/2024
Regulatory Contact: Carrie Janowski
First Call Engineer: David Wages 713.380.9836 (Cell)
AFE: 241-00049
Current Bottom Hole Pressure:
Max Bottom Hole Pressure:
Min ID:
MAX ANTICIPATED SURFACE
PRESSURE:
2982 psi @ 8010’ TVD
3000 psi @ 8010’ TVD
3.725” X Nip at ~11,755’ MD
2199 psi
(Estimated, offset SBHP, 7.2 ppg)
(Estimated, offset SBHP, 7.2 ppg)
Brief Well Summary:
11-41 is a new Zone 1 FURy producer, similar to offsets 11-23, 11-39 and 11-40.
RIG will set the production packer and MIT-T and MIT-IA to 3500 psi
Objective: Pull B&R/RHC Plug Body. Coil Extended Add Perf 1858’ 1765’. POP well via test unit
Procedure:
Slickline- COMPLETE 5/4
1. Pull BPV if not already done
2. MIRU SL
3. Install LGLV design per GL engineer
a. Final tally upon well completion
b. Initial Expected Rates:
i. 900 bopd
ii. 200 bwpd
iii. 600 mcfd
4. Pull B&R and RHC plug body.
5. Drift to deviation for 2-7/8” guns (3.047” swell)
6. RDMO SL
Coiled Tubing
Notes:
• This work may be completed with 1.75” coil, 1.5” Coil struggles to reach TD, see Cerberus modelling
below.
• Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS
coverage is required.
• The well will be killed and monitored before making up the initial perfs guns. This is generally done
during the drift/logging run. This will provide guidance as to whether the well will be killed by
bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after
perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the
same port that opened to shear the firing head.
7. After MU MHA and pull test the CTC, tag-up on the CT stripper to ensure BHA cannot pull through
the brass upon POOH with guns.
8. MU and RIH with GR/CCL and CBL and long drift nozzle for 3.047” swell guns.
9. Log from PBTD to ~200’ inside the tubing tail
New Well Post
Well: 11-41
Current PTD: 224-017
10. Flag pipe as appropriate per WSS for addperf runs.
11. Ensure well is dead before POOH, and circulate a kill with 8.4ppg 1% KCl as necessary. Max tubing
pressure 3500 psi. (This step can be performed any time prior to open-hole deployment of the perf
guns. Timing of the well kill is at the discretion of the WSS.)
PIPE VOLUMES:
Wellbore volume to estimated PBTD of 15,822’ = 240.8 bbls
a. 4-1/2” Tubing – (11,800’ – surface) X 0.0152bpf = 180.0 bbl
b. 4-1/2” Liner – (15,822’ – 11,800’) x 0.0152 bpf = 60.8 bbl
12. POOH pumping pipe displacement and freeze protect tubing as needed.
13. Confirm good log data.
14. At surface, prepare for deployment of TCP guns.
15. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, 8.4 ppg 1% KCl or 8.5
ppg as needed. Maintain hole fill taking returns to tank until lubricator connection is re-established.
Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed
and there is no excess flow.
16. Perform drill by picking up safety joint with TIW valve and space out before MU guns. Review well
control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun
string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve
readily accessible near the working platform for quick deployment if necessary.
c. At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns
one time to confirm the threads are compatible.
17. Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly
monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed
while deploying perf guns to ensure the well remains killed and there is no excess flow.
Perf Schedule
*Planned for 2-7/8” Halliburton MaxForce charges, max swell 3.047” (in liquid), 12.41#/ft loaded weight.
Perf Interval Perf Length Gun Length Weight of Gun (lbs) Comments
Run 1 15,075’ – 15,275’ 200’ 200’ ~2482# Discuss with OE
need for re-
logging for pipe
stretch
Run 2 14,600’ – 15,025’ 425’ 425’ ~5274#
Run 3 13,900’ – 14,175’ 275’ 275’ ~3412#
Run 4 13,425’ – 13,850’ 425’ 425’ ~5274#
Run 5 12,940’ – 13,380’ 440’ 440’ ~5460#
Run 6 12,742’ – 12,835’ 93’ 93’ ~1154#
Total 1765’ 1765’
18. MU lubricator connection at QTS. RIH with perf gun and tie-in to coil flag correlation. Pick up and
perforate interval per Perf Schedule above.
d. Note any tubing pressure change in WSR.
19. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and
stick the BHA. Confirm well is dead and re-kill if necessary before pulling to surface.
20. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary.
21. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and
commencing breakdown of TCP gun string.
22. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA.
23. Repeat steps 15 through 22 for subsequent runs to complete the desired perforated footage.
New Well Post
Well: 11-41
Current PTD: 224-017
24. RDMO CTU.
25. RTP or FP well.
Well Testing- New Well POP
1. MIRU Well Test Unit
a. Work with pad op to determine flowline to use if the tie in is not complete
2. POP well per SLBU program below
3. Once well is on stable production, obtain a 12 hour piggyback well test
a. Retest as needed to confirm pad separator rates
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Diagram
3. Coil Tubing BOPE Schematic
4. Standing Orders for Open Hole Well Control during Perf Gun Deployment
5. Equipment Layout Diagram
6. Sundry Change Form
7. Tie in Log and screenshots
8. SLBU Procedure
9. Cross-section
10. Cerberus
New Well Post
Well: 11-41
Current PTD: 224-017
Current WBD:
New Well Post
Well: 11-41
Current PTD: 224-017
Proposed WBD:
5/7-8:
Complete
New Well Post
Well: 11-41
Current PTD: 224-017
Coil Tubing BOPE Schematic:
New Well Post
Well: 11-41
Current PTD: 224-017
Standing Orders for Open Hole Well Control during Perf Gun Deployment
New Well Post
Well: 11-41
Current PTD: 224-017
Equipment Layout Diagram
New Well Post
Well: 11-41
Current PTD: 224-017
Sundry Change Form
Changes to Approved Sundry Procedure
Date:
Subject:
Sundry #:
Any modifications to an approved sundry will be documented and approved below. Changes to an approved
sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change
is required before implementing the change.
Step Page Date Procedure Change
HAK
Prepared
By
(Initials)
HAK
Approved
By
(Initials)
AOGCC Written
Approval
Received
(Person and
Date)
17 2 5/8 Add 6th perf interval DW DW
Approval:
Operations Manager Date
Prepared: David Wages
Operations Engineer Date
New Well Post
Well: 11-41
Current PTD: 224-017
Tie in Log:
New Well Post
Well: 11-41
Current PTD: 224-017
Perf Run #1 Tie-In (15,075’ – 15,275’) COMPLETE 5/7:
New Well Post
Well: 11-41
Current PTD: 224-017
Perf Run #2 Tie-In (14,600’ – 15,025’) COMPLETE 5/7:
New Well Post
Well: 11-41
Current PTD: 224-017
Perf Run #3 Tie-In (13,900’ – 14,175’) COMPLETE 5/8:
New Well Post
Well: 11-41
Current PTD: 224-017
Perf Run #4 Tie-In (13,425’ – 13,850’):
New Well Post
Well: 11-41
Current PTD: 224-017
Perf Run #5 Tie-In (12,940’ – 13,380’):
New Well Post
Well: 11-41
Current PTD: 224-017
Perf Run #6 Tie-In (12,742’ – 12,835’):
New Well Post
Well: 11-41
Current PTD: 224-017
Slow Bean-Up (SLBU) Procedure for Wells that received ~500’+ of new perforations
Notes:
- The objective of this procedure is to outline rough guidelines for making choke & drawdown
changes to extended add-perf (ExtADP) wells to limit the rate of drawdown, which
minimizes shock to the reservoir and minimizes sand-face failure (sand production) and
completion damage. This should be considered general and not rigid rules.
- This procedure should be followed any time an existing or new well receives an Ext ADP
intervention or post drill where more than 500’ of perfs have been added.
- Each well has different flow characteristics and as such may result in varying times to reach
FOC and/or optimal choke setting.
- GL should be shut-off anytime a well is shut-in. This prevents from displacing gas into the
formation and thus can lead to applying a large amount of drawdown over a short time
interval when re-POP’ing that can result in high amounts of sand production.
1. Open the choke to minimum choke position. Start GL at 1 MMSCFD and maintain this
setting for 6 hours after the well is kicked off. Consider adjusting the choke if the WHT
is <50F and/or WHP is >500 psi for a prolonged period (mitigate hydrate formation).
• Expect WHP to initially drop when opening the choke until GL has time to build pressure
and KO well.
• If well is setup with continuous AF / EB / Meth injection at the wellhead, add as
necessary to help reduce slugging until well stabilizes out.
• If well is setup for continuous methanol injection, add methanol into the GL stream as
necessary until well is warm and stable.
• After the well kicks off, adjust gas lift rate at this time to get stable flow. Flow should be
as stable as possible before opening up the choke.
2. After the 6 hour hold period, open choke 10 steps
• Increase GL to target rate at the end of the 6 hour hold period. Adjust GL as necessary
to achieve stable flow and limited slugging. Target 1500 TGLR.
3. Hold at this choke setting for 2 hours
• If the stages are lengthened due to operational constraints that is fine. Bean-up should
take a minimum of 10 hours to get to target.
• After a bottoms up is seen, take a solids sample. If the shakeout sample shows a solid
content >1% contact OE.
o Will likely want to hold at choke setting for an additional bottoms up .
o At the end of the hold period, grab another shakeout to confirm solids production
has reduced to a manageable level before proceeding with any additional
drawdown changes.
• If solids sample <0.2%, open choke up 10 more steps
• If possible, obtain a water salinity every choke adjustment.
4. Repeat the choke opening steps as described above to fully open well to flow. Discuss with
OE if there are any flowing BHP limitations.
New Well Post
Well: 11-41
Current PTD: 224-017
Cross Section
New Well Post
Well: 11-41
Current PTD: 224-017
Cerberus:
Case: 1.5” HS-80 coil, 500’ of 2-7/8” guns
Case: 1.75” DC-110 coil, 500’ of 2-7/8” guns
7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in this pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
Subsequent Form Required:
Approved By: Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU 11-41
Extended Perforating
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK
99503
224-017
50-029-23782-00-00
341J
ADL 028325 & 028322
5271
Conductor
Surface
Intermediate
Production
Liner
3918
79
5217
11891
4128
5181
20"
10-3/4"
7"
4-1/2"
3855
48 - 127
48 - 5265
45 - 11936
11774 - 15902
2468
48 - 127
48 - 3855
45 - 8338
8218 - 8585
None
2480
5410
7500
None
5210
7240
8430
None 4-1/2" 12.6# 13Cr80 ~42 - 11764None
Structural
4-1/2" HES TNT Perm
No SSSV
~11632
~8114
Date:
Bo York
Operations Manager
David Wages
David.Wages@hilcorp.com
(907) 564-4816
PRUDHOE BAY
5/3/2024
Current Pools:
PRUDHOE OIL
Proposed Pools:
PRUDHOE OIL
Suspension Expiration Date:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 12:46 pm, Apr 30, 2024
Digitally signed by Eric
Dickerman (4002)
DN: cn=Eric Dickerman (4002)
Date: 2024.04.30 11:49:44 -
08'00'
Eric Dickerman
(4002)
10-407
Perf gun length not to exceed 500' in length.
DSR-4/30/24
Perforate
SFD 4/30/2024MGR30APR24JLC 5/1/2024
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:Shane Barber - (C)
To:Regg, James B (OGC); Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay
Cc:Brett Anderson - (C); Steve Carter - (C); Oliver Amend - (C); Frank Roach
Subject:BOP test report
Date:Monday, April 29, 2024 4:29:52 PM
Attachments:Hilcorp PBU 11-41 10-424 BOP Test 4-27-24.xlsx
All,
Please see attached BOP test form. Thank you.
Shane G. Barber | Drilling Foreman
Hilcorp Alaska, LLC
Rig “Parker 273”
Office: 907-659-5673
Mobile: 907-841-5208
Harmony: 7008
sbarber@hilcorp.com
Alternate: Brett Anderson
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Sub mit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 4/27/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name: PTD #2240170 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: Bi-Weekly: X Other:
Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:2468
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1 P
Permit On Location P Hazard Sec.P Lower Kelly 1 P
Standing Order Posted P Misc.NA Ball Type 1 P
Test Fluid Water Inside BOP 1 P
FSV Misc 0 NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0 NA Trip Tank P P
Annular Preventer 1 13-5/8 5M P Pit Level Indicators P P
#1 Rams 1 2-7/8"x5" VBR 5M P Flow Indicator P P
#2 Rams 1 Blind/Shear 5M P Meth Gas Detector P P
#3 Rams 1 2-7/8"x5" VBR 5M P H2S Gas Detector P P
#4 Rams 0 NA MS Misc P NA
#5 Rams 0 NA
#6 Rams 0 NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M P System Pressure (psi)3000 P
Kill Line Valves 2 2-1/16",3-1/8" 5M P Pressure After Closure (psi)1950 P
Check Valve 0 NA 200 psi Attained (sec)14 P
BOP Misc 0 NA Full Pressure Attained (sec)72 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2335 P
No. Valves 15 P ACC Misc 0 NA
Manual Chokes 1 P
Hydraulic Chokes 1 P Control System Response Time:Time (sec) Test Result
CH Misc 0 NA Annular Preventer 25 P
#1 Rams 6 P
Coiled Tubing Only:#2 Rams 6 P
Inside Reel valves 0 NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:6.5 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 4/26/24, 07:50
Waived By
Test Start Date/Time:4/27/2024 10:30
(date) (time)Witness
Test Finish Date/Time:4/27/2024 17:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Austin McLeod
Parker
Tested with 4.5" and 4" test joints. Function BOP's from LER in Ops Cab and Remote Panel In Pushers Office.
Jon King / K. Enfield-Ayonayon
Hilcorp North Slope
Shane Barber / Steve Carter
PBU 11-41
Test Pressure (psi):
rig273mgr@parkerwellbore.com
sbarber@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0427_BOP_Parker273_PBU_11-41
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UNIT 11-41
JBR 06/07/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Tested with 2 7/8" and 4" test joints, CMV #1 grease fitting was replaced and passed restest, LEL in Wellhouse Bay failed on
audio was fixed and passed retest. Precharge Bottles = 24 Each, 4 @ 1150psi, 9 @ 1200psi and 11 @1250psi
Test Results
TEST DATA
Rig Rep:Brett AndersonOperator:Hilcorp North Slope, LLC Operator Rep:Brandon Davis
Rig Owner/Rig No.:Parker 273 PTD#:2240170 DATE:4/15/2024
Type Operation:DRILL Annular:
250/3500Type Test:BIWKLY
Valves:
250/3500
Rams:
250/3500
Test Pressures:Inspection No:bopBDB240415163620
Inspector Brian Bixby
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5.5
MASP:
2468
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
15 FPNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8"P
#1 Rams 1 2 7/8"x5"P
#2 Rams 1 Blind/Shear P
#3 Rams 1 2 7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8"P
HCR Valves 2 3 1/8"P
Kill Line Valves 2 2 1/16,3 1/8 P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P2000
200 PSI Attained P18
Full Pressure Attained P70
Blind Switch Covers:PYES
Bottle precharge P
Nitgn Btls# &psi (avg)P14@2520
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P FPMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P28
#1 Rams P7
#2 Rams P6
#3 Rams P6
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9999
9
9
9
9
99
CMV #1 LEL in Wellhouse Bay
Drilling Manager
04/01/24
Monty M
Myers
324-190
By Grace Christianson at 11:54 am, Apr 01, 2024
SFD 4/3/2024MGR03MAR24
10-407
DSR-4/12/24JLC 4/12/2024
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2024.04.12 14:17:43
-08'00'04/12/24
RBDMS JSB 041624
1
Joseph Lastufka
From:Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent:Saturday, March 30, 2024 7:29 PM
To:Frank Roach
Cc:Joseph Lastufka; Regg, James B (OGC); doa.aogcc.prudhoebay@alaska.gov
Subject:[EXTERNAL] RE: PBU 11-41 10-3/4" Surface Cement Job Evaluation and Plan for Top
Job (PTD 224-117)
Attachments:Industry Guidance Bulletin 13-01.pdf
Frank,
,ŝůĐŽƌƉŝƐĂƉƉƌŽǀĞĚƚŽƉƌŽĐĞĞĚǁŝƚŚĂƐƵƌĨĂĐĞĐĂƐŝŶŐĐĞŵĞŶƟŶŐƚŽƉũŽďǁŝƚŚK'/ŶƐƉĞĐƚŽƌŶŽƟĮĐĂƟŽŶĂŶĚǁŝƚŚ
their opportunity to witness.
A 10-ϰϬϯĐĂŶďĞƐƵďŵŝƩĞĚDŽŶĚĂLJƉƌŝůϭ͕ϮϬϮϰĨŽƌĂƌĞĐŽƌĚƚŚĂƚK'ŚĂƐĂƉƉƌŽǀĞĚǁŚĂƚŚĂƐďĞĞŶĂŐƌĞĞĚ
ďĞƚǁĞĞŶŵLJƐĞůĨĂŶĚ,ŝůĐŽƌƉƚŚĂƚĂƐŵĂůů͚ƐƉĂŐŚĞƫƐƚƌŝŶŐ͛ŽĨƉŝƉĞǁŝůůďĞƌƵŶĚŽǁŶƚŚĞƐƵƌĨĂĐĞĐĂƐŝŶŐdžĐŽŶĚƵĐƚŽƌ
annulus to as deep as possible to assure good quality cement at the surface for surface casing support.
WůĞĂƐĞŶŽƟĨLJK'/ŶƐƉĞĐƚŽƌƐŝĨ,ŝůĐŽƌƉĐĂŶŶŽƚŝĚĞŶƟĨLJƚŚĞdK͘
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),
State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information . The unauthorized review, use or
disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please dele te it, without first saving or forwarding it,
and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
ĐĐ͘:ŝŵZĞŐŐ͕:ŽĞ>ĂƐƚƵŅĂ͕K'/ŶƐƉĞĐƚŽƌƐ
From: Frank Roach <Frank.Roach@hilcorp.com>
Sent: Saturday, March 30, 2024 4:47 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: PBU 11-41 10-3/4" Surface Cement Job Evaluation and Plan for Top Job (PTD 224-117)
Mel,
dŚĂŶŬLJŽƵĨŽƌƚŚĞƉŚŽŶĞĐŽŶǀĞƌƐĂƟŽŶĞĂƌůŝĞƌƚŽĚĂLJ͘ƐǁĞĚŝƐĐƵƐƐĞĚ͕ƚŚĞϭϯ-1/2” surface hole proved to be a challenge
ĂƐǁĞƌĂŶŝŶƚŽĂŚŝŐŚĐŽŶĐĞŶƚƌĂƟŽŶŽĨǁŽŽĚǁŚŝůĞĚƌŝůůŝŶŐƚŚƌŽƵ ŐŚƚŚĞƉĞƌŵĂĨƌŽƐƚ͘dŚĞƌĞƐƵůƟŶŐŚŽůĞƐƚĂďŝůŝƚLJĐŚĂůůĞŶŐĞƐ
resulted in puůůŝŶŐĐĂƐŝŶŐĂŌĞƌŶŽƚƉƌŽŐƌĞƐƐŝŶŐƉĂƐƚϭ͕ϯϲϱ͛ĂŶĚŵĂŬŝŶŐĂĐůĞĂŶŽƵƚƌƵŶďĞĨŽƌĞĂƩĞŵƉƟŶŐƚŚĞĐĂƐŝŶŐƌƵŶ
again. The second casing run was a Įght, but were able to make it to TD. As such, lead excess in the permafrost was
increased from 350% to 500% to acĐŽƵŶƚĨŽƌƚŚĞŝŶĐƌĞĂƐĞĚĐŝƌĐƵůĂƟŽŶƟŵĞĂŶĚƌĞƚƵƌŶƐŽďƐĞƌǀĞĚĂƚƚŚĞƐŚĂŬĞƌƐ͘
CAUTION:External sender. DO NOT open links or attachments from UNKNOWN senders.
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attachments unless you recognize the sender and know the content is safe.
2
During the cement job, we had good returns with, at most, ~30 bbls lost over the total job. Unfortunately, we only saw
ŝŶĚŝĐĂƟŽŶƐŽĨƐƉĂĐĞƌƚŽƐƵƌĨĂĐĞĂƚƉůƵŐďƵŵƉ͘WƌĞƐƐƵƌĞďĞĨŽƌĞƉůƵŐďƵŵƉǁĂƐϳϳϲƉƐŝĂƚϮ͘ϱďƉŵƐŽŝŶĚŝĐĂƟŽŶƐĂƌĞƚŚĂƚ
cement is close to surface.
Plan forward is to run a temperature log to determine TOC. Following the log, pipe will be run between the casing
ŚĂŶŐĞƌŇƵƚĞƐƚŽƌĞĨƵƐĂůĨŽƌĂƚŽƉũŽď͘dŚĞ^DƐǁŝůůŶŽƟĨLJƚŚĞŝŶƐƉĞĐƚŽƌƐŽŶƚŚĞ^ůŽƉĞĨŽƌŽƉƉŽƌƚƵŶŝƚLJƚŽǁŝƚŶĞƐƐƚŚĞƚŽƉ
job. Note, the casing does not have centralizers from surface to ~300’ (Įrst 5 joints below casing the hanger) to facilitate
said top job.
>ĞƚŵĞŬŶŽǁŝĨLJŽƵŶĞĞĚĂŶLJƚŚŝŶŐĂĚĚŝƟŽŶĂů͘
Regards,
Frank V Roach
Drilling Engineer
Hilcorp Alaska, LLC
907.854.2321 mobile
907.777.8413 office
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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the recipient should carry out such virus and other checks as it considers appropriate.
_____________________________________________________________________________________
Created By: JNL 3/30/2024
SCHEMATIC
Prudhoe Bay Unit
Well: 11-41
Last Completed: TBD
PTD: 224-017
GENERAL WELL INFO
API: 50-029-23782-00-00
Completed: TBD
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 127’ N/A
10-3/4” Surface 45.5 / L-80 / BTC 9.950” Surface 5,265’ 0.0962
TUBING DETAIL
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
TD =5,271’(MD) / TD =3,918’(TVD)
10-3/4”
KB Elev: = 74.40’ / GL Elev: = 26.9’
PBTD = 5,181’(MD) / PBTD =3,855’(TVD)
OPEN HOLE / CEMENT DETAIL
Driven
13-1/2” 40% Excess Tail & Lead to BPRF, 500% Excess BPRF to surface. Top Job:
JEWELRY DETAIL
No Depth ID Item
WELL INCLINATION DETAIL
KOP @ 242’
Max Angle 110deg @ ~15,900’
TREE & WELLHEAD
Tree
Wellhead
_____________________________________________________________________________________
Created By: JNL 3/30/2024
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: 11-41
Last Completed: TBD
PTD: 224-017
GENERAL WELL INFO
API: 50-029-23782-00-00
Completed: TBD
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 127’ N/A
10-3/4” Surface 45.5 / L-80 / BTC 9.950” Surface 5,265’ 0.0962
7” Intermediate 26 / L-80 / BTC 6.276” Surface 11,950’ 0.0383
4-1/2” Liner 12.6 / 13Cr-80 / VamTop 3.958” ~11,800’ 15,900 0.0152
TUBING DETAIL
4-1/2" Tubing 12.6 / 13Cr-80 / VamTop 3.958” Surface ~11,800’ 0.0152
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
TD =15,900’(MD) / TD =8,595’(TVD)
10-3/4”
KB Elev: = 74.40’ / GL Elev: = 26.9’
4-1/2”
5
3
4
4-1/2”
6
7
7”
1
2
PBTD =15,820’(MD) / PBTD =8,620’(TVD)
8
OPEN HOLE / CEMENT DETAIL
Driven
13-1/2” 40% Excess Tail & Lead to BPRF, 500% Excess BPRF to surface. Top Job:
9-7/8” 40% Excess Planed TOC: 2,000’ MD above 7” casing shoe
6-1/8” 40% Excess Planned TOC: TOL
JEWELRY DETAIL
No Depth ID Item
1 ~11,800’ 4.320” Liner Hanger/LTP
2 ~11,800’ 3.958” WLEG
3 ~11,783’ 3.813” X Nipple
4 ~11,715’ 3.813” X-Nipple
5 ~11,681’ 3.873” Production Packer
6 ~11,653’ 3.813” X- Nipple
7 TBD 3.864” GLM x 6 (Depths TBD). Shear valve in top-most GLM)
8 ~2,200’ 3.813” X-Nipple
WELL INCLINATION DETAIL
KOP @ 242’
Max Angle 110deg @ 15,900’
TREE & WELLHEAD
Tree
Wellhead
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:Steve Carter - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:Frank Roach; Brett Anderson - (C); PB Wells Integrity
Subject:PBU EOA 11-41 - Parker 273 MIT
Date:Friday, May 3, 2024 12:22:22 AM
Attachments:PBU 11-41 10-426 MIT Test Form - Parker 273 4-30-24.xlsx
All – Please see the attached 10-426 MIT test form, from Parker 273 on 11-41.
Steve Carter
Hilcorp Alaska, LLC
Drilling Foreman
Rig: Parker 273
Office: (907) 659-5673
Personal Cell (907) 953-7333
Harmony: 7008
Alternate: Oliver Amend (oamend@hilcorp.com)
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
3%8
37'
Submit to:
OOPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240170 Type Inj N Tubing 0 3615 3579 3569 Type Test P
Packer TVD 8133 BBL Pump 2.1 IA 0 3740 3705 3695 Interval I
Test psi 3500 BBL Return 2.1 OA 150 150 150 150 Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240170 Type Inj N Tubing 2240 2240 2240 2240 Type Test P
Packer TVD 8133 BBL Pump 3.9 IA 0 3740 3705 3695 Interval I
Test psi 3500 BBL Return 3.8 OA 150 150 150 150 Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
MMechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Hilcorp North Slope
PBU DS11
Witness Waived by Kam St.John
Steve Carter
04/30/24
Notes:
Notes:
Notes:
Notes:
11-41
11-41
Form 10-426 (Revised 01/2017)2024-0430_MITP_PBU_11-41_2tests
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2024-0331_Surface_Csg_topjob_PBU_11-41_jh
Page 1 of 3
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg DATE: 4/1/2024
P. I. Supervisor
FROM: Josh Hunt SUBJECT: Surface Casing Cement Top Job
Petroleum Inspector PBU 11-41
Hilcorp North Slope LLC
PTD 2240170
3-31-2024: I traveled to Parker 273 on PBU 11-41 to witness a surface casing cement
top job. The cement stinger was ¾-inch ID conduit in 10-ft sticks. A 45-degree mule
shoe was run on-bottom to help rotate the top job string off anything on the way down.
Multiple holes were also drilled above the mule shoe to help with washing down and to
be able to continue pumping should the end of the pipe plug up. The well’s 20-inch
conductor was set at 80 feet MD from ground level, or 127.5 ft MD RKB. The 10 ¾-inch
surface casing was set at 5265 ft MD RKB. The crew washed down a total of 94 ft of
conduit from ground level or 141.5 ft MD RKB on the first attempt and stacked out on
something very hard. They circulated as much clay and debris out as possible and
decided to make another mule shoe like the first one and try again on the other side of
the flutes. The second attempt made it approximately 2 ft deeper (96 ft MD from ground
level or 143.5 ft MD RKB). The decision was made to use the deeper one for the top job
and they proceeded to pump cement.
Halliburton used their charge pump for this job as to not over pressure the conduit which
made it hard to establish a pump rate. The initial circulating pressure was 39 psi, final
circulation pressure was 50 psi. During the job there was a lot of clay packing off the
casing hanger flutes – the crew did an awesome job with a water hose and spare
conduit keeping the flutes opened to keep the job going. They were pumping 11 ppg
Arctic Sim cement. There was a mud engineer present to weigh the cement returns to
ensure we got good cement all the way to surface. A total of 39 bbls cement was
pumped with 10.9+ ppg on the cement returns at surface.
Attachments: Photos (4)
2024-0331_Surface_Csg_topjob_PBU_11-41_jh
Page 2 of 3
Surface Casing Cement Top Job – PBU 11-41 (PTD 2240170)
Photos by AOGCC Inspector J. Hunt
3/31/2024
Hilcorp Company Man Shane Barber with the first
mule shoe; showing holes drilled to mitigate plugging.
Cleaning clay out of the
casing hanger flutes. 1-inch cementing string
in casing annulus.
2024-0331_Surface_Csg_topjob_PBU_11-41_jh
Page 3 of 3
Cement returns after cleaning clay
from casing hanger flutes.
Good cement to surface in casing annulus.
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click links or open attachments unless you recognize the sender and know the content
is safe.
From:Brett Anderson - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Frank Roach; Shane Barber - (C); Oliver Amend - (C); Steve Carter - (C)
Subject:Diverter Test Report - Parker 273 11-41
Date:Wednesday, March 20, 2024 11:14:20 AM
Attachments:11-41 Diverter Test Parker 273 - 03-19-2024.xlsx
Please see attached diverter test report for Parker 273 on PBU 11-41.
Thank you,
Brett Anderson
Hilcorp DSM, Parker 273
Office: 907-659-5673
Mobile: 907-240-6258
brett.anderson@hilcorp.com
Alternate: Shane Barber
sbarber@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
3%8
37'
Date: 3/19/2024 Development: X Exploratory:
Drlg Contractor: Rig No. 273 AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.: 2240170 Rig Phone:
Rig Email:
MMISCELLANEOUS:DIVERTER SYSTEM:
Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P
Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P
Warning Sign P Misc: NA No Threaded Connections? P
24 hr Notice: P Vent line Below Diverter? P
AACCUMULATOR SYSTEM:Diverter Size: 21 1/4 in.
Systems Pressure: 3000 psig P Hole Size: 13 1/2 in.
Pressure After Closure: 2225 psig P Vent Line(s) Size: 16 in. P
200 psi Recharge Time: 15 Seconds P Vent Line(s) Length: 36 ft. P
Full Recharge Time:54 Seconds P Closest Ignition Source: 100 ft. P
Nitrogen Bottles (Number of): 14 Outlet from Rig Substructure: 50 ft. P
Avg. Pressure: 2251 psig P
Accumulator Misc: NA
Vent Line(s) Anchored: P
MMUD SYSTEM:Visual Alarm Turns Targeted / Long Radius: P
Trip Tank: P P Divert Valve(s) Full Opening: P
Mud Pits: P P Valve(s) Auto & Simultaneous:
Flow Monitor: P P Annular Closed Time: 32 sec P
Mud System Misc: 0 NA Knife Valve Open Time: 24 sec P
Diverter Misc: NA
GGAS DETECTORS:Visual Alarm
Methane: P P
Hydrogen Sulfide: P P
Gas Detectors Misc: 0 NA
Total Test Time: 1.5 hrs Non-Compliance Items: 0
Remarks:
Submit to:
brett.anderson@hilcorp.com
TTEST DATA
Jon King
phoebe.brooks@alaska.gov
Hilcorp
Test with 5 inch test jt
24 @ 1100 psi pre charge
Notice given 3/16/24 @ 09:27
AOGCC REP Adam Earl Waived witness on 03-16-2024, 10:26 am
0
Brett Anderson
0
(907) 659-5673
TTEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
PBU 11-41
SSTATE OF ALASK A
AALASK A OIL AND GAS CONSERVATION COMMISSION
DDi verter Sys t ems In sp ectio n Report
GGENERAL INFORMATION
WaivedParker
**All Diverter repo rts are du e to t he agency w i th in 5 days of test in g*
Form 10-425 (Revised 05/2021)2024-0319_Diverter_Parker273_PBU_11-41
+LOFRUS1RUWK6ORSH//&MEU
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Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, 3UXGKRH%D\ Oil Pool,PBU 11-41
Hilcorp Alaska, LLC
Permit to Drill Number: 224-117
Surface Location: 4686' FSL, 4651' FEL, Sec 34, T11N, R15E, UM, AK
Bottomhole Location: 60' FSL, 1909' FEL, Sec16, T11N, R15E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this day of March 2024.
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.03.01 13:44:49
-09'00'
1
Drilling Manager
02/23/24
Monty M
Myers
By Grace Christianson at 12:52 pm, Feb 23, 2024
MGR29FEB2024
224-017
< >
SFD
SFD 2/26/2024 DSR-2/26/24
*BOPE test to 3500 psi. Annular to 2500 psi.
* FIT/LOT and casing test digital data to AOGCC immediately upon
completion of FIT/LOT.
50-029-23782-00-00
*&:
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2024.03.01 13:45:32 -09'00'
03/01/24
03/01/24
Prudhoe Bay East
(PBU) 11-41
Drilling Program
Version 0
02/20/2024
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12
11.0 Drill 13-1/2” Hole Section ........................................................................................................ 14
12.0 Run 10-3/4” Surface Casing .................................................................................................... 17
13.0 Cement 10-3/4” Surface Casing ............................................................................................... 20
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 23
15.0 Drill 9-7/8” Intermediate Hole Section .................................................................................... 24
16.0 Run 7” Intermediate Casing .................................................................................................... 30
17.0 Cement 7” Intermediate Casing .............................................................................................. 33
18.0 Drill 6-1/8” Production Hole Section ....................................................................................... 36
19.0 Run 4-1/2” Production Liner ................................................................................................... 40
20.0 Cement 4-1/2” Production Liner ............................................................................................. 43
21.0 Perforate 4-1/2” Liner ............................................................................................................. 46
22.0 Run Upper Completion/ Post Rig Work ................................................................................. 47
23.0 Parker 273 Rig Diverter Schematic ......................................................................................... 51
24.0 Parker 273 Rig BOP Schematic ............................................................................................... 52
25.0 Wellhead Schematic ................................................................................................................. 53
26.0 Days Vs Depth .......................................................................................................................... 54
27.0 Formation Tops & Information............................................................................................... 55
28.0 Anticipated Drilling Hazards .................................................................................................. 58
29.0 Parker 273 Rig Layout............................................................................................................. 64
30.0 FIT Procedure .......................................................................................................................... 65
31.0 Parker 273 Rig Choke Manifold Schematic ............................................................................ 66
32.0 Casing Design ........................................................................................................................... 67
33.0 9-7/8” Hole Section MASP ....................................................................................................... 68
34.0 6-1/8” Hole Section MASP ....................................................................................................... 69
35.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 70
36.0 Surface Plat (As Staked) (NAD 27) ......................................................................................... 71
Page 2
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
1.0 Well Summary
Well PBU 11-41
Pad Prudhoe Bay DS-11
Planned Completion Type 4-1/2” Production Tubing
Target Reservoir(s) Ivishak Sands
Planned Well TD, MD / TVD 15,900’ MD / 8,595’ TVD
PBTD, MD / TVD 15,820’ MD / 8,620’ TVD
Surface Location (Governmental) 4,686' FSL, 4,651' FEL, Sec 34, T11N, R15E, UM, AK
Surface Location (NAD 27) X= 708,198.83, Y= 5,951,148.59
Top of Productive Horizon
(Governmental)1,723' FSL, 2,145' FEL, Sec 21, T11N, R15E, UM, AK
TPH Location (NAD 27) X= 705,200.93, Y= 5,958,665.98
BHL (Governmental) 60' FSL, 1909' FWL, Sec 16, T11N, R15E, UM, AK
BHL (NAD 27) X= 703,868.34, Y= 5,962,246.91
AFE Number
AFE Drilling Days 35
AFE Completion Days 8
Maximum Anticipated Pressure
(Surface) 2468 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 3346 psig
Work String 5” 19.5# S-135 XT-50 and 4” 14.0# S-135 XT-39
Parker 273 KB Elevation above MSL: 26.9 ft + 46.95 ft = 73.85 ft
GL Elevation above MSL: 26.9 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25 - - - X-52 Weld
13-1/2” 10-3/4” 9.950 9.875 11.750 45.5 L-80 BTC 5,210 2,470 1,040
9-7/8” 7” 6.276 6.151 7.656 26.0 L-80 BTC 7,240 5,410 604
6-1/8” 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288
Tubing 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surf, Int,
& Prod
5”4.276”3.500”6.500”19.5 S-135 XT50 44,000 52,800 712klb
4”3.340”2.688” 4.875”14.0 S-135 XT39 17,700 21,200 513klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
Report covers operations from 6am to 6am
Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
Ensure time entry adds up to 24 hours total.
Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
Submit a short operations update each work day to mmyers@hilcorp.com,
frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
Health and Safety: Notify EHS field coordinator.
Environmental: Drilling Environmental Coordinator
Notify Drilling Manager & Drilling Engineer on all incidents
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final “As-Run” Casing tally to mmyers@hilcorp,com, frank.roach@hilcorp.com,
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
Send casing and cement report for each string of casing to mmyers@hilcorp.com,
frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Brodie Wages 907.564.4672 david.wages@hilcorp.com
Geologist Corey Ramstad 907.777.8316 cramstad@hilcorp.com
Reservoir Engineer Lea Peters 907.564.4696 lpeters@hilcorp.com
Drilling Env. Coordinator Chris Keil 303.681.8844 chris.keil@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
7.0 Drilling / Completion Summary
11-41 is a grassroots producer planned to be drilled in the Ivishak sands.
The directional plan is 13-1/2” surface hole and 10-3/4” surface casing set in the base of the SV3. A 9-7/8”
section will be drilled and 7” intermediate casing set at TSAD. A 6-1/8” horizontal section will be drilled to
Ivishak Zone 1. A 4-1/2” production liner will be run in the open hole section and cemented in place. After
testing, the liner will be perforated using DPC perf guns. The well will be completed with 4-1/2” production
tubing.
Parker 273 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately March 15, 2024, pending rig schedule.
Surface casing will be run to 5,260’ MD / ~3,905’ TVD and cemented to surface via a single stage primary
cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not
observed, necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Parker 273 Rig to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 13-1/2” hole to TD of surface hole section. Run and cement 10-3/4” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 9-7/8” to TD of intermediate hole section. Run and cement 7” intermediate casing
6. Drill 6-1/8” hole to TD
7. Run and cement 4-1/2” production liner
8. Perforate 4-1/2” production liner
9. Run Upper Completion
10. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface Hole: No mud logging. Remote Ops geologist. LWD: GR + Res
2. Intermediate Hole: No mud logging. Field Ops geologist for casing pick. LWD: GR + Res
3. Production Hole: No mud logging. Field Ops geologist. LWD: Triple-Combo (For geo-
steering)
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Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
BOPs shall be tested at (2) week intervals during the drilling and completion of PBU 11-41. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
The initial test of BOP equipment will be to 250/3,500 psi & subsequent tests of the BOP equipment
will be to 250/3,500 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
AOGCC Regulation Variance Requests:
Summary of Parker 273 BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
13-1/2”21-1/4” 2M Annular BOP w/ 16” diverter line Function Test Only
9-7/8”
13-5/8” x 5M Annular BOP
13-5/8” x Double Gate
o Blind/Shear ram in btm cavity
Mud cross w/ 3-1/8” x 5M side outlets
13-5/8” x Single ram
3” x 5M Choke Line
2” x 5M Kill line
3” x 5M Choke manifold
Standpipe, floor valves, etc
Initial Test: 250/3,500
Annular: 250/2,500
Subsequent Tests:
250/3,500
Annular 250/2,500
6-1/8”
13-5/8” x 5M Annular BOP
13-5/8” x Double Gate
o Blind/Shear ram in btm cavity
Mud cross w/ 3-1/8” x 5M side outlets
13-5/8” x Single ram
3” x 5M Choke Line
2” x 5M Kill line
3” x 5M Choke manifold
Standpipe, floor valves, etc
Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven
pump and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Blind/Shear ram
Blind/Shear ram
Page 10
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
Required AOGCC Notifications:
Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
24 hours notice prior to spud.
24 hours notice prior to testing BOPs.
24 hours notice prior to casing running & cement operations.
Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11
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11-41 Ivishak Producer
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 11-41 will utilize an existing 20” conductor on DS-11. Ensure to review attached surface plat
and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 Ensure any necessary wellhead equipment is staged prior to MIRU. A slip-loc starting head
should also be staged in the cellar in the event that surface casing must be set using emergency
slips.
9.8 MIRU Parker 273 Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.9 Mix spud mud for 13-1/2” surface hole section. Ensure mud temperatures are cool (<80 F).
9.10 Ensure 5-3/4” liners in mud pumps.
NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96%
volumetric efficiency.
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11-41 Ivishak Producer
Drilling Procedure
10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” diverter (Diverter Schematic attached to program).
N/U 20” riser to BOP Deck
N/U 20”, 5M diverter “T”.
NU Knife gate & 16” diverter line.
Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
Diverter line must be 75 ft from nearest ignition source
10.2 Notify AOGCC. Function test diverter.
Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
A prohibition on vehicle parking
A prohibition on ignition sources or running equipment
A prohibition on staged equipment or materials
Restriction of traffic to essential foot or vehicle traffic only.
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Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
10.4 Rig & Diverter Orientation:
May change on location
Page 14
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
11.0 Drill 13-1/2” Hole Section
11.1 P/U 13-1/2” directional drilling assembly:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
Drill string will be 5” 19.5# S-135.
Run a solid float in the surface hole section.
11.2 Begin drilling out from conductor at reduced flow rates to avoid broaching the conductor.
Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 13-1/2” hole section to section TD in the SV3 (projected ~5,260’ MD). Confirm this setting
depth with the Geologist and Drilling Engineer while drilling the well, targeting the shale
package in the base of the SV3, ~60’ TVD above the SV2.
Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
Hold a safety meeting with rig crews to discuss:
Conductor broaching ops and mitigation procedures.
Well control procedures and rig evacuation
Flow rates, hole cleaning, mud cooling, etc.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Keep mud as cool as possible to keep from washing out permafrost.
Pump at 400-500 gpm while drilling through permafrost. Monitor shakers closely to ensure
shaker screens and return lines can handle the flow rate.
Avoid sliding when drilling across the prognosed base of permafrost, top SV6, and the
EOCU to prevent high dogleg severity.
Once below base permafrost, perform wiper trip top BHA and run back to bottom.
Slowly increase pump rate between 550 and 650 gpm while drilling to surface TD.
Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
Slow in/out of slips and while tripping to keep swab and surge pressures low
Ensure shakers are functioning properly. Check for holes in screens on connections.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
Adjust MW and viscosity as necessary to maintain hole stability.
Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
Page 15
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
In PBE hydrates are not present. However, continue to drill using hydrate mitigation
measures:
Keep mud temperature as cool as possible, Target 60-70*F
Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
Drill through hydrate sands and quickly as possible, do not backream.
Monitor returns for hydrates, checking pressurized & non-pressurized scales
Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
Surface Hole AC:
There are no wells with a clearance factor of <1.0
11.4 13-1/2” hole mud program summary:
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density PV YP API FL HPHT Drill Solids MBT Hardness
Surface –BPRF 8.8 –9.0 10-20 20-45 NC NA <9 <35 <200
BPRF - TD 9.0 –9.5 10-30 20-45 <10 NA <9 <35 <200
System Formulation: Gel + FW spud mud
Product Quantity
Water 0. 967 Bbls
Soda Ash 0.125 ppb
M-I GEL 35.0 ppb
Primary Products
Weight Material M-I WATE
Viscosifiers M-I GEL
Fluid Loss Additives M-I Pac UL (only if needed for fluid loss near TD)
Alkalinity Control Soda Ash
Bit & BHA Balling SCREENKLEEN (only if needed for balling in surface)
Contingency Products
Thinner CF Desco II, TANNATHIN & SAPP
Cement Contamination Sodium Bicarbonate & SAPP
Screen Blinding SCREENKLEEN
Lost Circulation Material NUT PLUG FINE & MEDIUM, M-I-X II FINE & Medium
Foaming/Aeration SCREENKLEEN / DEFOAM EXTRA
PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
Page 16
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
Casing Running:Reduce system YP as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures.
Reduce the system rheology once the casing is landed (check with the cementers to see what
YP value they have targeted).
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and a 2nd BU. Rack back one stand every 30 minutes to avoid washing out the hole. Drop
mud temp as low as possible as well.
Pump at full drill rate (600-650 gpm) and maximize rotation.
Monitor well for any signs of packing off or losses.
Once hole is cleaned up, obtain PU/SO/ROT weights for baseline prior to wiper trip.
11.6 Perform a wiper trip to BPRF on elevators. If tight hole is encountered attempt to wipe clean
before pumping/backreaming.
11.7 TIH to TD, cleaning any tight spots encountered on the way. Note any trouble spots for final trip
out and casing run.
11.8 At TD, CBU to ensure hole clean
Pump at full drill rate (600-650 gpm) and maximize rotation.
Monitor well for any signs of packing off or losses.
Once hole is cleaned up, obtain PU/SO/ROT weights prior to POOH.
11.9 POOH for casing run. Final trip should be on elevators. Wipe any tight spots along the way and
note for casing run.
11.10 LD BHA
11.11 No open hole logging program planned.
Page 17
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
12.0 Run 10-3/4” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Parker 10-3/4” casing running equipment (CRT & Tongs)
Ensure 10-3/4” BTC x XT50 XO on rig floor and M/U to FOSV.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
R/U of CRT if hole conditions require.
R/U a fill up tool to fill casing while running if the CRT is not used.
Ensure all casing has been drifted to 9.875” on the location prior to running.
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 80’ shoe track assembly consisting of:
10-3/4” Float Shoe
1 joint –10-3/4”, 2 Centralizers 10’ from each end w/ stop rings
1 joint – 10-3/4”, 1 Centralizer mid joint w/ stop ring
10-3/4” Float Collar
1 joint – 10-3/4”, 1 Centralizer mid joint with stop ring
Ensure proper operation of float equipment while picking up.
Ensure to record S/N’s of all float equipment components.
10-3/4” 45.5/# L-80 BTC MUT – Make up to Mark 10 jts Take Average
Casing OD Minimum Optimum Maximum
10-3/4” 9,800 ft-lbs Mark 24,890 ft-lbs
Page 18
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
Page 19
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
12.5 Continue running 10-3/4” surface casing
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
1 centralizer every joint to ~ 1000’ MD from shoe
1 centralizer every 2 joints from ~1,000’ above shoe to ~200’ from surface
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Continue running 10-3/4” surface casing
12.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.8 Slow in and out of slips.
12.9 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.10 Lower casing to setting depth. Confirm measurements.
12.11 While the primary method to land surface casing is with a mandrel hanger, have slips staged in
cellar, along with necessary equipment for setting casing with slips as a contingency.
12.12 Circulate and condition mud through CRT. Reduce YP to help ensure success of cement job.
Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate
casing string while conditioning mud.
Page 20
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
13.0 Cement 10-3/4” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
Review test reports and ensure pump times are acceptable.
Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 120 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug – HEC rep to witness. Mix and pump cement per below calculations for the
job, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 40% open hole excess from TD to base permafrost
and annular volume + 350% from base permafrost to surface. Job will consist of lead & tail,
with TOC brought to surface.
Estimated Total Cement Volume:
Page 21
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
Cement Slurry Design:
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud out of mud pits.
Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement.
13.11 Displacement calculation:
= (5,260-80)*.0962
=499 bbls
13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Decide ahead
of time what will be done with cement returns once they are at surface. Wellhead side outlet
valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid
from cellar. Have black water available to retard setting of cement.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±3.8 bbls before consulting with Drilling
Engineer.
13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
Lead Slurry Tail Slurry
Density 11.0 lb/gal 15.8 lb/gal
Yield 2.54 ft3/sk 1.16 ft3/sk
Mix Water 12.2 gal/sk 4.97 gal/sk
Page 22
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
Ensure to report the following on wellez:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to frank.roach@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
Page 23
Prudhoe Bay East
11-41 Ivishak Producer
Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” 5M casing spool and 11” x 13-5/8”
adapter.
14.2 NU 13-5/8” x 5M BOP as follows:
BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
Double gate ram should be dressed with 2-7/8” x 5” VBRs or 5” solid body rams in top
cavity,blind/shear ram in bottom cavity.
Single ram can be dressed with 2-7/8” x 5” VBRs or 5” solid body rams
NU bell nipple, install flowline.
Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,500 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
Test with 2-7/8” and 5” test joints. This covers the smallest and largest diameters used for the
well.
Confirm test pressures with PTD
Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 9.5 ppg (or match density to mud weight at surface TD, whichever is higher) LSND fluid
for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5-3/4” liners in mud pumps.
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Drilling Procedure
15.0 Drill 9-7/8” Intermediate Hole Section
15.1 MU 9-7/8” directional BHA
RSS and Gr/Res
Ensure BHA components have been inspected previously.
Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Ensure MWD is RU and operational.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
Drill string will be 5” 19.5# S-135 XT50.
Run a solid float in this hole section.
15.2 TIH w/ 9-7/8” BHA to 2 stands above float collar.
15.3 RU and test casing to 3,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on LOT graph. AOGCC reg is 50% of burst = 5,210 / 2 = ~2,605 psi. Document
incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are
used to test casing as per AOGCC Industry Guidance Bulletin 17-001.
15.4 Wash down and tag plugs. Note depth tagged on AM report. Drill out shoe track to within 10’ of
the float shoe. Displace well over to 9.5 ppg (or equal to surface mud weight at TD, whichever is
higher) LSND for upcoming hole section
15.5 Continue to drill out remaining shoetrack and 20’ of new formation.
15.6 CBU and condition mud for LOT.
15.7 Conduct LOT. Chart Test. Ensure test is recorded on same chart as casing test. Document
incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test
and LOT digital data to AOGCC.
12.7 ppg EMW provides >>25bbls based on 10.7 ppg MW +0.5ppg intensity, 10.0 ppg PP
- Notify AOGCC (Melvin Rixse 907-223-3605) if LOT < 12.7 ppg EMW.
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Drilling Procedure
15.8 9-7/8” hole section mud program summary:
System Type:9.5 – 10.7 ppg LSND drilling fluid
Properties:
Interval Density PV YP API FL HPHT Drill Solids MBT Hardness
~5,260’ – ~9,696’
Shoe –CM3
9.5 – 9.8 5 – 20 15 – 30 < 8 N/A <6% <12 <200
~9,696’ – ~11,097’
CM3 –CM1
9.8 – 10.4 5 – 20 15 – 30 < 8 N/A <6% <20 <200
~11,097’ – ~11,663’
CM1 –THRZ
10.4 – 10.7 5 – 20 15 – 30 < 6 N/A <6% <20 <200
~11,663’ – TD
THRZ –TD
10.4 – 10.7 5 – 20 15 – 30 < 6 <10 <6% <20 <200
Product Quantity
Water 0.916 bbls/bbl
Soda Ash 0.17 ppb
DUO-VIS 1.0 –1.5 ppb (as needed)
DUAL-FLO/ FLO-TROL 3.0 ppb
SCREENKLEEN 0.25% v/v
M-I Wate 55 ppb (as needed for wt.)
Busan 1060 2.1 gals/100 bbls
Sodium Metabisulfite 0.25 ppb (added at rig only)
Primary Products
Viscosifiers DUO-VIS/ XCD
Fluid Loss Additives FLO-TROL / DUAL-FLO
Bit & BHA Balling SCREENKLEEN (only if needed for balling/Ugnu/WS)
Bridging Agent SAFE-CARB 20 & 40
Alkalinity Control Soda Ash
Inhibition Potassium Chloride
Lubricants LUBE 776 & LOTORQ
Corrosion Control Sodium Metabisulfite (added at rig only)
Bacteria Control Busan 1060
Contingency Products
Cement Contamination Sodium Bicarbonate & SAPP
Weight Material Sodium Chloride
Foaming/Aeration SCREENKLEEN, DEFOAM EXTRA
Lost Circulation Material NUT PLUG FINE & MEDIUM, SAFE-CARB 40, 250 & 750
Density: Weighting material to be used for the hole section will be Barite. Additional
barite will be on location to weight up the active system (1) ppg above highest anticipated
MW.
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11-41 Ivishak Producer
Drilling Procedure
Solids Concentration: Solids concentration should be kept low while drilling the
intermediate hole section. Keep the shaker screen size optimized and utilize centrifuge as
needed.
Rheology: Keep viscosifier additions reasonably low (DUO-VIS / XCD). Utilize sweeps
(weighted, high vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 10
(hole diameter) for sufficient hole cleaning
Dump and dilute as necessary to keep drilled solids low.
MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
15.9 Install MPD RCD
15.12 Obtain initial ECD benchmark readings prior to drilling ahead.
15.13 Drill 9-7/8” hole section from 10-3/4” shoe to ~9,500’ MD (~200’ MD above CM3) per
Geologist and Drilling Engineer Utilizing the following parameters:
Flow Rate: 500-750 GPM
RPM: Maximize RPM when rotating Take the first couple stands to understand BHA
tendency. Maintenance slides may be necessary to keep sail angle
Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the
UG4-UG1
Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to
limit drilling ECD to 1.0 ppg over calculated cleanhole ECD.
Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across any sands for any extended period of time.
Limit maximum instantaneous ROP to < 200 FPH. The SV sands and Ugnu will drill faster
than this, but good hole cleaning practices now reduces time needed to cleanup prior to
running casing.
Target ROP is as fast as we can clean the hole without having to backream connections and
staying below 200 FPH
9-7/8” Hole Section A/C:
There are no wells with a CF < 1.0
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Drilling Procedure
15.14 Toward the end of the above interval and if not already there, begin to weight up to 9.8 ppg.
Ensure mud is a consistent 9.8 ppg ~200’ before entering the CM3.
While overpressure is not expected in the UG4 through UG1 from GNI disposal, maintain
vigilance while drilling through the Ugnu.
15.15 Drill 9-7/8” hole section from ~9,500’ MD to ~10,900’ MD (~200’ MD above CM1) per
Geologist and Drilling Engineer Utilizing the following parameters:
Flow Rate: 500-750 GPM
RPM: Maximize RPM when rotating
Limit WOB to 20k max to maintain bit stability
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to
limit drilling ECD to 1.0 ppg over calculated cleanhole ECD.
Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across any sands for any extended period of time.
Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now
reduces time needed to cleanup prior to running casing.
Target ROP is as fast as we can clean the hole without having to backream connections and
staying below 200 FPH
During this interval, before entering the CM2, ensure the mud weight is at 10.1 ppg or
higher.
9-7/8” Hole Section A/C:
There are no wells with a CF < 1.0
15.16 Toward the end of the above interval, begin to weight up to 10.4 ppg. Ensure mud is a consistent
10.4 ppg ~200’ before entering the CM1.
If using a spike fluid to weight up, ensure the fluid is heated to avoid shocking the formation
and inducing losses/breathing
15.17 Drill 9-7/8” hole section from ~10,900’ MD to ~11,400’ MD (~200’ MD above HRZ) per
Geologist and Drilling Engineer Utilizing the following parameters:
Flow Rate: 500 – 750 GPM
RPM: Maximize RPM when rotating
Limit WOB to 20k max to maintain bit stability
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Page 28
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11-41 Ivishak Producer
Drilling Procedure
Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to
limit drilling ECD to 1.0 ppg over calculated cleanhole ECD.
Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across any sands for any extended period of time.
Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now
reduces time needed to cleanup prior to running casing.
Target ROP is as fast as we can clean the hole without having to backream connections and
staying below 200 FPH
MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation
9-7/8” Hole Section A/C:
There are no wells with a CF < 1.0
15.18 Toward the end of the above interval, ensure mud weight is consistent and at least a 10.4 ppg.
Add black product to the mud system for HRZ stability. Ensure mud is a consistent 10.4 ppg
~200’ before entering the HRZ.
15.19 Prior to entering the HRZ, CBU and perform a wiper trip back to the shoe. Note any tight spots
and wipe clean as needed.
15.20 Drill 9-7/8” hole section from ~11,400’ MD to section TD (projected at ~11,950’ MD) per
Geologist and Drilling Engineer Utilizing the following parameters:
Flow Rate: 500 – 650 GPM
RPM: Maximize RPM when rotating
Keep pumps on and pumps of slow and smooth to minimize the cycling effects on the HRZ
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Monitor ECD, pump pressure & hookload trends for hole cleaning indication
Limit maximum instantaneous ROP to < 120 FPH. Over the final interval, control drill with
WOB, RPM, and flow rate to indicate when transitioning across the LCU and into the TSAD.
NOTE: LCU truncates out all of the Kingak, Sag River, and Shublik formations. Most
recent offset wells (11-39 and 11-40) went from HRZ to Zone 4.
MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation
9-7/8” Hole Section A/C:
There are no wells with a CF < 1.0
15.21 Reference:Intermediate Casing Pick procedure
Control drilling is key! With the LCU around DS-11, the HRZ sits on top of TSAD (Kingak,
Sag River, and Shublik are truncated). As such, the traditional Sag casing pick procedure
can’t be followed. Recognizing when to stop drilling to call TD is key before getting too
deep into the Ivishak formation and going on losses.
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11-41 Ivishak Producer
Drilling Procedure
Drill through HRZ. Once THRZ is identified, use prognosed thickness to establish first stop
point.
Stop drilling and CBU if one of the three occur:
Drilling break observed (drill additional 5’ MD before CBU)
Ivishak sand or fluvial shale identified in return samples
Near-bit GR shoes a baseline shift
Reach above established stop point
If Ivishak sand is not confirmed in samples, drill additional 5’ and CBU.
Repeat above steps until Ivishak sand is confirmed in samples.
15.22 At TD, CBU at least 3 times at 600 gpm and max RPM. Pump tandem sweeps if needed
Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
Obtain BHCT from MWD tools and provide to Halliburton cementers.
15.23 Wiper trip to the 10-3/4” casing shoe
Pump and pull until above HRZ to limit swab effect on the HRZ shales.
Once above the HRZ, pull on elevators to the casing shoe.
If tight hole is encountered, RIH 2-3 stands and CBU. If tight spot is at the same depth,
begin backreaming.
If backreaming operations are commenced, continue backreaming to the shoe.
Monitor pressure, ECD, torque, and return flow to indicate potential packing off.
If backreaming is initiated, utilize MPD to close on connections while BROOH.
CBU minimum two times at trip point.
15.24 RIH to TD on elevators and circulate hole clean.
15.25 POOH and LD BHA.
Pump and pull until above HRZ to limit swab effect on the HRZ shales
15.26 Change out VBRs in the upper ram cavity to 7” fixed rams. Test with 7” test joint for upcoming
intermediate casing run.
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Drilling Procedure
16.0 Run 7” Intermediate Casing
16.1 Well control preparedness: In the event of an influx of formation fluids while running the
intermediate casing, the following well control response procedure will be followed:
P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open
position on top, 5” handling joint above TIW). This joint shall be fully M/U and available
prior to running the first joint of 7” casing.
Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
Proceed with well kill operations.
16.2 R/U 7” casing running equipment.
Ensure 7” 26# BTC x XT50 crossover is on rig floor and M/U to FOSV.
Ensure all casing has been drifted on the deck prior to running.
Be sure to count the total # of joints on the deck before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 7” intermediate casing
Use BOL 2000 or equivalent thread compound. Dope pin end only w/ paint brush. Wipe off
excess.
Centralization:
1 centralizer every joint to ~ 2000’ MD from shoe
1 centralizer every 2 joints from ~2,000’ above shoe to 1 jt below 10-3/4” surface casing
shoe (~5,000’ MD)
Utilize a collar clamp until weight is sufficient to keep slips set properly.
If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
Obtain up and down weights of the casing before entering open hole.
See data sheets on the next page for MU torque for the 7” casing connection.
12.13 Continue M/U & thread locking 80’ shoe track assembly consisting of:
7” Float Shoe
1 joint –7”, 2 Centralizers 10’ from each end w/ stop rings
1 joint – 7”, 1 Centralizer mid joint w/ stop ring
7” Float Collar
1 joint –7”, 1 Centralizer free floating
7” 26/# L-80 BTC MUT – Make up to Mark 10 jts Take Average
Casing OD Minimum Optimum Maximum
7” 8,280 ft-lbs Mark 16,230 ft-lbs
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Drilling Procedure
16.4 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
16.5 Slow in and out of slips.
16.6 RIH with 7” intermediate casing to 10-3/4” shoe at ~ 4,953’ MD. CBU and extablish PU and SO
weights prior to exiting shoe.
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Drilling Procedure
16.7 Continue to RIH with 7” intermediate casing using the following circulation strategy (Note: Take
special care when staging pumps up and down to avoid packing off and breaking down
formation):
10-3/4” shoe to THRZ: Every 5th joint, staging up to planned cementing rate. Circulate for 5
minutes.
Toward the end of this interval, circulate down consecutive joints to achieve a full
bottoms-up by THRZ
THRZ to TD: Do not circulate. Fill pipe only
16.8 P/U hanger and landing joint and M/U to casing string. Casing shoe +/- 5’ from TD.
16.9 Break circulation at 1 bpm to avoid breaking down formation. Slowly stage up to full circulating
rate (planned cementing rates). Allow circulating pressures to stabilize before increasing
circulating rate to the next stage. Circulate 2 BU or more if needed to condition hole for
cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop
until casing is on bottom and cementers are ready.
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Drilling Procedure
17.0 Cement 7” Intermediate Casing
17.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
Review test reports and ensure pump times are acceptable.
Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
17.2 Document efficiency of all possible displacement pumps prior to cement job.
17.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
17.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
17.5 Fill surface cement lines with water and pressure test.
17.6 Pump remaining 80 bbls 12.5 ppg tuned spacer.
17.7 Drop bottom plug – HEC rep to witness. Mix and pump cement per below calculations and
confirm actual cement volumes with cementer after TD is reached.
17.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of a tail
slurry, TOC brought to 2,000’ above 7” casing shoe.
Estimated Total Cement Volume:
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11-41 Ivishak Producer
Drilling Procedure
Cement Slurry Design:
17.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
17.10 After pumping cement, drop top plug and displace with the rig pumps and LSND mud out of
mud pits.
Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
17.11 Displacement calculation:
= (11,950-80)*.0383
= 455 bbls
17.12 Monitor returns closely while displacing cement. Adjust pump rate if losses or packing off are
seen at any point during the job.
17.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±1.5 bbls before consulting with Drilling
Engineer.
17.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set.
17.15 Set packoff and test per wellhead tech.
17.16 Freeze protect 10-3/4” x 7” casing annulus to ~2,400’ MD with dead crude or diesel after cement
tests indicate cement has reached 500 psi compressive strength.
Freeze protect with ~120 bbls of dead crude/diesel
Establish breakdown pressure and inject 5 bbls past breakdown to confirm annulus is clear
Ensure total injection volume injected down the annulus (including mud used to keep
annulus open) doesn’t exceed 110% of the 10-3/4” x 7” annular volume.
17.17 LD 5” drillpipe and prepare to PU 4” drillpipe for next hole section.
Tail Slurry
Density 15.3 lb/gal
Yield 1.23 ft3/sk
Mix Water 5.57 gal/sk
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Drilling Procedure
17.18 Change upper rams from 7” casing rams to 2-7/8” x 5” VBRs and test to 250 psi low, 3,500 psi
high for 5/5 minutes with 4” and 2-7/8” test joints.
Ensure to report the following on wellez:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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Drilling Procedure
18.0 Drill 6-1/8” Production Hole Section
18.1 PU and rack back as much 4” drillpipe need to TD hole section.
18.2 MU 6-1/8” directional BHA
RSS and Triple Combo
Ensure BHA components have been inspected previously.
Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
Ensure MWD is RU and operational.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 4” 14.0# S-135 XT39.
Run a solid float in the production hole section.
18.3 TIH w/ 6-1/8” BHA to float collar. Note depth TOC tagged on AM report. Drill out shoe track
to 10’ above float shoe.
18.4 RU and test casing to 3,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and
volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin
17-001.
18.5 Displace well to 8.5 ppg PowerPro drilling fluid.
18.6 Drill out remaining shoe track and 20’ of new formation.
18.7 CBU and condition mud for FIT.
18.8 Conduct FIT to 10.4 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
9.7 ppg EMW provides >>25bbls based on 9.1 ppg MW, 7.33 ppg EMW PP (swabbed kick at
9.1 ppg EMW BHP)
18.9 6-1/8” hole section mud program summary:
System Type:8.5 – 9.1 ppg PowerPro drilling fluid
Properties:
Interval Density PV YP API FL Drill Solids pH MBT Hardness
Production 8.5-9.1 <8 10 –20 <10 <6 9.0 –10.0 <10.0 <200
Page 37
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11-41 Ivishak Producer
Drilling Procedure
Product Quantity
Water 0.916 bbls/bbl
Soda Ash 0.17 ppb
POWERVIS 0.75 –1.25 ppb (as needed)
DUAL-FLO/ FLO-TROL 4.0 ppb
SCREENKLEEN 0.125% v/v
KLC 21.8 ppb (6% by wt.)
SAFE-CARB 20 22 ppb
SAFE-CARB 40 22 ppb
Salt 14.4 ppb (as needed for density)
LUBE 776 1.0% v/v
LOTORQ 1.0% v/v
Busan 1060 2.1 gals/100 bbls
Sodium Metabisulfite 0.25 ppb (added at rig only)
Primary Products
Viscosifiers POWERVIS
Fluid Loss Additives FLO-TROL/ DUAL-FLO
Bridging Agent SAFE-CARB 20 & 40
Alkalinity Control Soda Ash
Inhibition Potassium Chloride
Lubricants LUBE 776 & LOTORQ
Corrosion Control Sodium Metabisulfite (added at rig only)
Bacteria Control Busan 1060
Bridging/Density SAFE-CARB 20 & 40, Salt
Contingency Products
Cement Contamination Sodium Bicarbonate & SAPP
Weight Material Sodium Chloride / SAFE-CARB 20 & 40, Salt
Foaming/Aeration SCREENKLEEN, DEFOAM EXTRA
Lost Circulation Material NUT PLUG FINE & MEDIUM, SAFE-CARB 40, 250 & 750
Density: Weighting material to be used for the hole section will be sodium chloride.
Additional NaCl will be on location to weight up the active system (1) ppg above highest
anticipated MW.
Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
Rheology: Keep viscosifier additions to an absolute minimum (POWERVIS/FLO-VIS).
Data suggests excessive viscosifier concentrations can decrease return permeability. Do
not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 6.5 (hole
diameter) for sufficient hole cleaning
Page 38
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Drilling Procedure
Run the centrifuge as needed while drilling the production hole, this will help with solids
removal.
Dump and dilute as necessary to keep drilled solids to an absolute minimum.
MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
18.10 Install MPD RCD
18.11 Begin drilling 6-1/8” hole section, on-bottom staging technique:
Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
18.12 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer.
Flow Rate: 250-350 GPM, target min. AV’s 200 ft/min, 175 GPM
RPM: 120+
Start off with light WOB (5-7K) in the build section. Once landed, WOB can be slowly
increased to 5-10K, based on bit performance.
Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every joint, until landed in Zone 1. Once landed, surveys can be taken
every stand to TD. Survey frequency can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Monitor ECD, pump pressure & hookload trends for hole cleaning indication
Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping BHA for
any extended period of time.
Reservoir plan is to land in the Ivishak Zone 1 and geosteer, staying in the lower Zone 1
sands before toeing up at TD.
Limit maximum instantaneous ROP to < 120 FPH. The sands will drill faster than this, but
With geosteering close to BSAD, data density and low ROP is key to react and stay in zone.
MWD data quality is key for well placement. If any issues arise with data quality or data
detection, stop drilling and troubleshoot.
6-1/8” Hole Section A/C:
11-23 has a 0.491 CF. This well has been reservoir P&A’d.
11-23A has a 0.519 CF. This well has also been reservoir P&A’d.
Page 39
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Drilling Procedure
18.13 At TD, CBU at drilling rate and max rotation. Pump sweeps if needed
Monitor BU for increase in cuttings
18.14 Perform wiper trip to the 7” casing shoe
Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
If pulling tight, trip back to TD and begin backreaming operations.
If backreaming operations are commenced, continue backreaming to the shoe
18.15 CBU minimum two times at 7” shoe and clean casing with high vis sweeps.
18.16 Trip back to TD and CBU 2x or until well cleans up, whichever comes later.
18.17 POOH and LD BHA. Rabbit DP that will be used to run liner.
Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be
any additional logging runs conducted.
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Drilling Procedure
19.0 Run 4-1/2” Production Liner
19.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner, the following well control response procedure will be followed:
P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4” handling joint above TIW). This joint shall be fully M/U and available
prior to running the first joint of 4-1/2” liner.
Slack off and with 4” DP across the BOP, shut in ram or annular on 4” DP. Close TIW.
Proceed with well kill operations.
19.2 R/U 4-1/2” liner running equipment.
Ensure 4-1/2” 12.6# VT x XT39 crossover is on rig floor and M/U to FOSV.
Ensure all casing has been drifted on the deck prior to running.
Be sure to count the total # of joints on the deck before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
19.3 Run 4-1/2” production liner
Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess.
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Use lift nubbins and stabbing guides for the liner run.
If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
Obtain up and down weights of the liner before entering open hole.
See data sheet on the next page for MU torque for the 4-1/2” liner connections.
Centralization:
1 centralizer every joint to ~ 50’ MD from 7” shoe
19.4 Run 4-1/2” injection liner as follows:
4-1/2” Float Shoe
1 joint – 4-1/2”, 2 Centralizers 10’ from each end w/ stop rings
4-1/2” Float Collar
1 joint – 4-1/2”, 1 Centralizer free floating
4-1/2” landing collar for liner wiper plug
1 joint –4-1/2”, 1 Centralizer mid joint w/ stop ring
4-1/2” 12.6/# L-80 VT – Make up Torque
Casing OD Minimum Optimum Maximum
4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs
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19.5 Ensure hanger/pkr will not be set in a 7” connection.
AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place
liner hanger/packer across 7” connection.
19.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
19.8 M/U Baker SLZXP liner top packer to 4-1/2” liner. Circulate 2 liner volumes to clear string and
allow for PAL mix to set
19.9 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
19.10 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the
hole. Slow down running speed if necessary.
Ensure 4” DP has been drifted
Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging.
19.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
19.12 CBU at the 7” shoe. Obtain up and down weights of the liner before entering open hole.
19.13 RIH to TD, filling pipe along the way. Utilize the same parameters used in step 19.10. Tag
bottom and PU to position float shoe ~2’ off bottom.
19.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Do not
exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses.
Confirm all pressures with Baker.
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Drilling Procedure
20.0 Cement 4-1/2” Production Liner
20.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
Review test reports and ensure pump times are acceptable.
Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
20.2 Document efficiency of all possible displacement pumps prior to cement job.
20.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
20.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
20.5 Fill surface cement lines with water and pressure test.
20.6 Pump remaining 60 bbls 12.5 ppg tuned spacer.
20.7 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail slurry,
TOC brought to top of liner.
Estimated Total Cement Volume:
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Drilling Procedure
Cement Slurry Design:
20.8 Wash up lines back to the cement unit. This will help reduce risk of cement stringers in the liner.
Drop drillpipe dart and displace with perf pill before swapping to drilling mud. If hole conditions
allow – continue rotating and reciprocating liner throughout displacement. This will ensure a
high quality cement job with 100% coverage around the pipe.
20.9 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
20.10 If elevated displacement pressures are encountered, position casing at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
20.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
20.12 Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool Slack off total liner weight plus 30k to confirm hanger is set.
20.13 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down
50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating
at 10-20 RPM and set down 50K again.
20.14 PU to neutral weight, close BOP and test annulus to 1,500 psi for 5 minutes to confirm liner top
packer is set.
20.15 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, repeat setting process in 20.13. If running tool cannot be hydraulically
released, apply LH torque to mechanically release the setting.
20.16 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top)
20.17 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
Tail Slurry
Density 15.8 lb/gal
Yield 1.16 ft3/sk
Mix Water 4.98 gal/sk
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20.18 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
20.19 RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
20.20 If not done already, test upper and lower VBRs with both 4-1/2” and 2-7/8” test joints to cover
maximum and minimum pipe diameters for upcoming operations..
20.21 Pressure test casing and liner to 250 psi low / 3,500 psi high for 30 minutes. Do not test until
cement has reached minimum 1,000 psi compressive strength.
Note: Once running tool is LD, swap to the completion AFE.
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Drilling Procedure
21.0 Perforate 4-1/2” Liner
21.1 If not completed in the previous BOPE test, test annular, upper and lower VBRs with 2-7/8” test
joint to 250psi low 3,500psi high for 5/5 minutes.
21.2 RU to run 2-7/8” perforating assembly per vendor procedure.
Initial plan is ~2,000’ of 2-7/8” MaxFire (or equivalent) perforation guns will be needed.
Exact perforated intervals to be determined by as-drilled logs data. Depths to be determined
and confirmed by Geo/OE/DE.
Include a contingency hydraulic ball-drop disconnect in assembly
Limit personnel on rig floor to those required to make up DPC guns.
21.3 RIH with the perforating assembly. Stop to take PU/SO weights at the top of the 4-1/2” liner.
21.4 Space out DPC assembly by tagging the landing collar and spacing out on the upstroke.
21.5 Perforate the well per vendor procedure
Ball-drop firing head will be used. Review and follow vendor procedures for arming and
firing the DPC guns.
21.6 Immediately after confirming guns have fired, POOH while keeping the hole full to get guns
above the top shot.
This is to minimize sticking issues from possible sanding
Flow check well and establish loss rate prior to POOH
21.7 POOH, keeping the hole filled with KWF.
Record loss rate
Flow check at the 4-1/2” liner top and before pulling BHA through the BOPE
21.8 POOH and LD perf gun assembly. Verify all shots have fired.
Hydraulic tongs may be used with no backup tongs to spin out guns during rig down to
minimize trapped pressure issues.
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Drilling Procedure
22.0 Run Upper Completion/ Post Rig Work
22.1 RU to run 4-1/2” 12.6#, 13Cr-80 Vam Top tubing.
Ensure wear bushing is pulled.
Ensure 4-1/2”, 12.6#, Vam Top x 4” XT39 crossover is on rig floor and M/U to FOSV.
Ensure all tubing has been drifted in the pipe shed prior to running.
Be sure to count the total # of joints in the pipe shed before running.
Keep hole covered while RU casing tools.
Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
Monitor displacement from wellbore while RIH.
22.2 PU, MU and RH with the following 4-1/2” completion jewelry (tally to be provided by
Operations Engineer):
a. Torque Turn All Connections
b. Tubing Jewelry to include (top to bottom):
c. 1x ‘X’ Nipple
d. 6x GLMs (size and depths to be determined by OE. Ensure GLM with shear valve is deep
enough to accommodate freeze protect volume in step 22.15)
e. 1x ‘X’ Nipple
f. 1x Production Packer
g. 1x ‘X’ Nipple
h. 1x ‘X’ Nipple with RHC profile installed
i. 1x WLEG or half-muleshoe
j. Tubing is 4-1/2”, 12.6#, 13Cr-80, Vam Top
4-1/2” 12.6/# 13Cr-80 Vam Top – Make up Torque
Casing OD Minimum Optimum Maximum
4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs
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22.3 Space out the completion to land such that the 4-1/2” WLEG is inserted half-way into the PBR
on the 4-1/2” production liner. Record PU and SO weights prior to picking up tubing hanger.
22.4 MU the tubing hanger and land same. Run in the lock-down screws and torque to spec.
22.5 Reverse circulate heated kill-weight brine. Circulate surface-to-surface at a maximum of 4 BPM
with brine and inhibited brine as follows:
Clean brine within the tubing from WLEG to surface
Inhibited brine on the annular side from the shear valve depth to the WLEG
Clean brine on the annular side from surface down to the shear valve.
At the end of the above displacement, reverse circulate an additional 5 bbls clean brine
With the 5 bbls over displacement complete, spot the fluids back in place by pumping 5 bbls
clean brine down the tubing. This is to clean the RHC-M plug face before dropping the ball
& rod.
22.6 Drop the ball & rod to the RHC-M (confirm whether roller stem is required due to the sail angle
of the well).
22.7 Once ball & rod has landed, pressure up and set the packer.
22.8 Pressure test the tubing to 250 psi low, 3,500 psi high for 30 minutes.
22.9 Slowly bleed tubing pressure to 2,000 psi (confirm shear valve pressure) and test the IA to 250
psi low, 3,500 psi high for 30 minutes.
22.10 Hold pressure on the IA and bleed off the tubing pressure to shear the GLM valve. Confirm 2-
way communication through the shear valve.
22.11 Install and pressure test TWC from above.
22.12 ND BOPE. NU the tubing head adapter and tree.
22.13 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
22.14 RU lubricator and pull TWC.
22.15 Freeze protect the wellbore.
Rig up to pump heated diesel down the IA, taking returns up the tubing up the tubing.
Reverse 82 bbls heated diesel into the IA. Do not exceed 3bpm while circulating.
Shut in the IA.
Line up to U-tube from the IA to the tubing.
U-tube the diesel and freeze protect the tubing and IA to ~2,400’ MD.
22.16 After u-tube is complete, RU lubricator and install BPV.
22.17 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
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Drilling Procedure
22.18 RDMO Parker 273
i. POST RIG WELL WORK (sundry to follow)
1. Slickline/Fullbore
a. Pull BPV.
b. Change out GLV per GL ENGR
c. Pull B&R and RHC
2. Well Tie-In
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23.0 Parker 273 Rig Diverter Schematic
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Drilling Procedure
24.0 Parker 273 Rig BOP Schematic
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Drilling Procedure
25.0 Wellhead Schematic
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Drilling Procedure
26.0 Days Vs Depth
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27.0 Formation Tops & Information
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28.0 Anticipated Drilling Hazards
13-1/2” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have NOT been seen on DS-11.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
There are no wells with a clearance factor of <1.0
Wellbore stability (Faults):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
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Drilling Procedure
H2S:
DS-11 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-11
has a history of H2S in their wells. Below are the most recent H2S values of monitored wells in the
Ivishak Pool.
Well Name H2S Level Date of Reading
#1 Closest SHL Well H2S Level 11-23 20 ppm 05/17/2023
#2 Closest SHL Well H2S Level 11-09A 14 ppm 10/30/2021
#1 Closest BHL Well H2S Level 11-39 14 ppm 08/22/2023
#2 Closest BHL Well H2S Level 11-40 16 ppm 10/27/2023
Max. Recorded H2S on nearest Pad/Facility 11-22 2000 ppm 11/10/1993
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
DS-11 is an H2S location.
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Drilling Procedure
9-7/8” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning
(weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole
angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run
centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time
is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at
maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the
wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean
the hole. Maintain circulation rate of > 600 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
DS-11 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-11
has a history of H2S in their wells. Below are the most recent H2S values of monitored wells in the
Ivishak Pool.
Well Name H2S Level Date of Reading
#1 Closest SHL Well H2S Level 11-23 20 ppm 05/17/2023
#2 Closest SHL Well H2S Level 11-09A 14 ppm 10/30/2021
#1 Closest BHL Well H2S Level 11-39 14 ppm 08/22/2023
#2 Closest BHL Well H2S Level 11-40 16 ppm 10/27/2023
Max. Recorded H2S on nearest Pad/Facility 11-22 2000 ppm 11/10/1993
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
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Drilling Procedure
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Closest active disposal wells to DS-11 are GNI (1.97 miles away) and LPC-02 (2.7 miles away).
Expected pore pressure when drilling through the Ungu sands is 9.0 ppg. Ensure mud is at least 9.5 ppg
prior to drilling through.
Ugnu/West Sak Hardstreaks:
Hard formations (which are not necessarily predictable) can be encountered resulting in damage to PDC
cutters. Damage occurs due to high impact loading of the bit cutting structure when hard streaks are hit
at high ROP. Follow the appropriate mitigation strategy of reducing rotary speed while maintaining
WOB.
Formation Breakout (HRZ instability):
This is related to the fissile (finely laminated) nature of the formation in conjunction with higher pore
pressure, which requires higher mud weight to maintain wellbore stability. If splintering cuttings are
observed at surface, additional circulations and mud weight may be required.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
9-7/8” Hole Section Specific AC:
There are no wells with a CF < 1.0
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Drilling Procedure
6-1/8” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning
(weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole
angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run
centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time
is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at
maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the
wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean
the hole. Maintain circulation rate of > 200 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
DS-11 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-11
has a history of H2S in their wells. Below are the most recent H2S values of monitored wells in the
Ivishak Pool.
Well Name H2S Level Date of Reading
#1 Closest SHL Well H2S Level 11-23 20 ppm 05/17/2023
#2 Closest SHL Well H2S Level 11-09A 14 ppm 10/30/2021
#1 Closest BHL Well H2S Level 11-39 14 ppm 08/22/2023
#2 Closest BHL Well H2S Level 11-40 16 ppm 10/27/2023
Max. Recorded H2S on nearest Pad/Facility 11-22 2000 ppm 11/10/1993
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
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3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
6-1/8” Hole Section Specific AC:
11-23 has a 0.491 CF. This well has been reservoir P&A’d.
11-23A has a 0.519 CF. This well has also been reservoir P&A’d.
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29.0 Parker 273 Rig Layout
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Drilling Procedure
30.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
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31.0 Parker 273 Rig Choke Manifold Schematic
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32.0 Casing Design
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33.0 9-7/8” Hole Section MASP
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34.0 6-1/8” Hole Section MASP
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35.0 Spider Plot (NAD 27) (Governmental Sections)
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36.0 Surface Plat (As Staked) (NAD 27)
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.
PRUDHOE OILPRUDHOE BAY
224-017
PBU 11-41
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14
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15
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16
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24
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25
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26
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27
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28
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29
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30
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31
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32
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34
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35
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37
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c
t
e
d
p
r
e
s
s
u
r
e
a
n
d
m
a
i
n
t
a
i
n
w
e
l
l
b
o
r
e
s
t
a
b
i
l
i
t
y
.
38
S
e
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
No
39
C
o
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
SF
D
Da
t
e
2/
2
6
/
2
0
2
4
Ap
p
r
MG
R
Da
t
e
2/
2
8
/
2
0
2
4
Ap
p
r
SF
D
Da
t
e
2/
2
6
/
2
0
2
4
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
i
n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
*&
:
