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Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
06/01/2023
Mr. Mel Rixse
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor
through 6/1/2023.
Dear Mr. Rixse,
Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off
with cement, corrosion inhibitor in the surface casing by conductor annulus through 6/1/2023.
Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement
fallback during the primary surface casing by conductor cement job. The remaining void space
between the top of the cement and the top of the conductor is filled with a heavier than water
corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached
spreadsheets include the well names, API and PTD numbers, treatment dates and volumes.
As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that
the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations.
If you have any additional questions, please contact me at 564-4891 or
oliver.sternicki@hilcorp.com.
Sincerely,
Oliver Sternicki
Well Integrity Supervisor
Hilcorp North Slope, LLC
Hilcorp North Slope LLC.Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-offReport of Sundry Operations (10-404)06/01/2023Well NamePTD #API #Initial top of cement (ft)Vol. of cement pumped (gal)Final top of cement (ft)Cement top off date Corrosion inhibitor (gal)Corrosion inhibitor/ sealant dateL-2072210815002923702003.371.31/23/2023123/1/2023L-2312230105002923746003.003.0-393/27/2023M-111810575002920589002.602.6-105/29/2023M-311920325002922256001.501.5-165/29/2023M-331941165002922504001.301.3-145/29/2023N-171830095002920898001.201.2-115/30/2023N-18A2081755002920906010.500.5-65/30/2023N-21A1961965002921342011.001.0-85/30/2023N-272071045002923365000.500.5-45/30/2023N-292141105002923521002.302.3-245/30/2023N-31215175500292356000-0--205/30/2023V-2342220045002923707006.3210.91/23/2023243/1/2023W-2412221545002923741002.502.5-263/1/2023Z-121891025002921977000.700.7-45/23/2023Z-34212061500292346900-0--155/27/2023Z-402111735002923462000.700.7-65/27/2023Z-46A2052035002923280010.500.5-35/23/2023Z-502120015002923463000.500.5-35/27/2023Z-662121955002923482000.700.7-85/27/2023Z-116211124500292345500-0--175/27/2023Z-210204181500292322600-0--125/27/2023Z-2292221045002923726003.8361.23/5/2023363/27/20230W-2412221545002923741002.52.5-263/1/2023
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Wednesday, April 5, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Guy Cook
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
W-241
PRUDHOE BAY UN ORIN W-241
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 04/05/2023
W-241
50-029-23741-00-00
222-154-0
G
SPT
4763
2221540 1500
1723 1724 1711 1708
104 294 261 245
INITAL P
Guy Cook
2/25/2023
Testing was completed with a Little Red Services pump truck and calibrated gauges.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PRUDHOE BAY UN ORIN W-241
Inspection Date:
Tubing
OA
Packer Depth
587 2409 2343 2321IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitGDC230224155516
BBL Pumped:1.3 BBL Returned:1.2
Wednesday, April 5, 2023 Page 1 of 1
1
Regg, James B (OGC)
From:Brooks, Phoebe L (OGC)
Sent:Wednesday, March 15, 2023 12:29 PM
To:PB Wells Integrity
Cc:Regg, James B (OGC)
Subject:RE: Hilcorp (PBU) February 2023 MIT Forms
Attachments:MIT PBU 03-12A 02-12-23 Revised.xlsx; MIT PBU 09-17 02-12-23 Revised.xlsx; MIT PBU Z-14B Z-33A
02-04-23 Revised.xlsx; MIT PBU S-101 S-05 S-114 S-124 S-31 02-04-23 Revised.xlsx; MIT PBU W-241
02-06-23.xlsx
Ryan,
Attached are revised reports as follows:
MIT PBU 03‐12A 02‐12‐23 – changed the packer tvd to reflect 8490’ and first MITIA test result to “F”
MIT PBU 09‐17 02‐12‐23 – changed the packer tv d to reflect 8809’
MIT PBU Z‐14B 02‐04‐23 – changed the test psi to 3500 and 15 Min IA for Z‐14B on the MITIA to 3639 based on
the inspector’s report
MIT S‐101 S‐05…02‐04‐23 – changed the packer tvd to 6194’ for S‐101 and changed the Pretest OA to 157 for S‐
114A
MIT PBU W‐241 02‐06‐23 – removed the waived by verbiage from the AOGCC Rep (and put in the Notes)
Please update your copies 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: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent: Wednesday, March 1, 2023 12:03 PM
To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Cc: Regg, James B (OGC) <jim.regg@alaska.gov>
Subject: Hilcorp (PBU) February 2023 MIT Forms
Ms. Brooks,
Attached are the completed AOGCC MIT forms for the tests completed by Hilcorp in February 2023.
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.
PBU W-241PTD 2221540
2
Well: PTD: Notes:
03‐12A 2181530 4‐year MIT‐IA
07‐20C 2180360 2‐year MIT‐T & CMIT‐TxIA per CO 736
09‐17 1770380 2‐year MIT‐IA per AA AIO 4E.018
A‐05A 2061280 4‐year MIT‐IA
L2‐07B 2181390 2‐year CMIT‐TxIA per CO 736
R‐15A 1990360 4‐year MIT‐IA
S‐101 2001150 4‐year MIT‐IA
S‐05A 1951890 4‐year MIT‐IA
S‐114 2021980 4‐year MIT‐IA
S‐124 2061360 4‐year MIT‐IA
S‐31A 1982200 4‐year MIT‐IA
W‐241 2221540 Rig MIT‐T / MIT‐IA Initial MIT‐IA
Z‐14B 2060990 MIT‐T / MIT‐IA per Sundry 322‐610
Z‐33A 1890050 4‐year MIT‐IA
Z‐61 2121130 CMIT‐TxIA per Sundry 323‐001
Please reply with questions or concerns.
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659‐5102
M: (907) 232‐1005
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.
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2221540 Type Inj N Tubing 0 3620 3526 3519 Type Test P
Packer TVD 4762 BBL Pump 3.8 IA 0000 IntervalI
Test psi 3500 BBL Return 3.7 OA 0000 Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2221540 Type Inj N Tubing 500 945 945 945 Type Test P
Packer TVD 4762 BBL Pump IA 0 3717 3698 3693 Interval I
Test psi 3500 BBL Return OA 0000 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
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Pumped a total of 3.8 bbls for both tests, bled back 3.7 bbls. Waived by Guy Cook.
Notes:
Notes:
Hilcorp North Slope LLC
Prudhoe Bay / PBU / W-Pad
Brett Anderson
02/06/23
Notes:Pumped a total of 3.8 bbls for both tests, bled back 3.7 bbls. Waived by Guy Cook.
Notes:
Notes:
Notes:
W-241
W-241
Form 10-426 (Revised 01/2017)MIT PBU W-241 02-06-23
J. Regg; 5/4/2023
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:Brooks, Phoebe L (OGC)
To:Shane Barber - (C)
Cc:Regg, James B (OGC)
Subject:RE: BOP Test reoprt
Date:Wednesday, March 1, 2023 11:29:05 AM
Attachments:Hilcorp Innovation 01-30-23.xlsx
Shane,
I added the test time of 9 hours to the report. Please update your copy.
Thanks,
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: Shane Barber - (C) <sbarber@hilcorp.com>
Sent: Tuesday, January 31, 2023 9:21 AM
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: Joseph Engel <jengel@hilcorp.com>; Brett Anderson - (C) <Brett.Anderson@hilcorp.com>; Clint
Montague - (C) <cmontague@hilcorp.com>; Justin Gruenberg - (C)
<Justin.Gruenberg@hilcorp.com>; James Lott - (C) <jlott@hilcorp.com>
Subject: BOP Test reoprt
All,
Please see attached BOP test report. Thank you.
Shane G. Barber | Drilling Foreman
Hilcorp Alaska, LLC
Rig “Innovation”
Office: 907-670-3094
PBU W-241
PTD 2221540
Mobile: 907-841-5208
Harmony: 1006
sbarber@hilcorp.com
Alternate: James Lott
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner:Rig No.:Innovation DATE:1/30/23
Rig Rep.:Rig Email:
Operator:
Operator Rep.:Op. Rep Email:
Well Name:PTD #2221540 Sundry #
Operation:Drilling:x Workover:Explor.:
Test:Initial:Weekly:Bi-Weekly:x Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1572
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 2 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", 5K P Pit Level Indicators P P
#1 Rams 1 2-7/8"x5-1/2"FP Flow Indicator P P
#2 Rams 1 Blinds P Meth Gas Detector P FP
#3 Rams 1 2-7/8"x5-1/2"P H2S Gas Detector P P
#4 Rams 0 NA MS Misc 0 NA
#5 Rams 0 NA
#6 Rams 0 NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8", 5K P Time/Pressure Test Result
HCR Valves 1 3-1/8", 5K P System Pressure (psi)3000 P
Kill Line Valves 1 3-1/8", 5K P Pressure After Closure (psi)1500 P
Check Valve 0 NA 200 psi Attained (sec)32 P
BOP Misc 0 NA Full Pressure Attained (sec)101 P
Blind Switch Covers:All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 @ 2287 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 10 P
#1 Rams 9 P
Coiled Tubing Only:#2 Rams 9 P
Inside Reel valves 0 NA #3 Rams 5 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:2 Test Time:9.0 HCR Choke 2 P
Repair or replacement of equipment will be made within days. HCR Kill 2 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1/28/23, 16:55
Waived By
Test Start Date/Time:1/29/2023 20:00
(date)(time)Witness
Test Finish Date/Time:1/30/2023 5:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Brian Bixby
Hilcorp
Test with 4" and 4.5" test joints. Failed upper VBR's. Replace upper seals on rams and retest with passing results. Fail on LEL
light. Light was showing inconsistent strobe. Inspect and clean inside of LEL light housing. Rebuild housing and retest (test
good).
Matt Vanhoose
Hilcorp
Shane Barber
PBU W-241
Test Pressure (psi):
nnovationtoolpusher@hilcorp.com
sbarber@hilcorp.com
Form 10-424 (Revised 08/2022)2023-0130_BOP_Hilcorp_Innovation_PBU_W-241
Hilcorp North Slope LLCjbr
J. Regg; 5/31/2023
PRUDHOE BAY FIELD /
SCHRADER BLUFF OIL POOL, ORION DEV AREA
382' FEL
Received on 2/22/2023
Completed
2/7/2023
JSB
RBDMS JSB 030323
GMGR02AUG2023DSR-3/3/23
2.23.2023Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.22 15:32:22 -09'00'
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW W-241 Date:1/16/2023
Csg Size/Wt/Grade:9 5/8 47 & 40 #L-80 Supervisor:James Lott
Csg Setting Depth:3361 TMD 2639 TVD
Mud Weight:9.5 ppg LOT / FIT Press =329 psi
LOT / FIT =11.90 ppg Hole Depth =3391 md
Fluid Pumped=0.4 Bbls Volume Back =0.2 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->020 ->014
->255 ->230
->4111 ->455
->6185 ->688
->8258 ->8135
->10 329 ->10 185
->12 ->12 240
->14 ->14 305
->16 ->20 510
->18 ->40 1270
->20 ->50 1680
-> ->70 2550
-> ->73 2700
-> ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0329 ->02700
->1310 ->52686
->2297 ->10 2683
->3290 ->15 2680
->4283 ->20 2680
->5278 ->25 2678
->6274 ->30 2676
->7268 ->
->8265 ->
->9261 ->
->10 257 ->
-> ->
-> ->
-> ->
0
2
4
6
8
10
0 2 4
6
8
10
12
14
20
40
50
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 1020304050607080
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
329310297290283278274268265261257
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW W-241 Date:1/23/2023
Csg Size/Wt/Grade:7" 26/29# L-80 Supervisor:Lott/ Amend
Csg Setting Depth:7817 TMD 5002 TVD
Mud Weight:9.2 ppg LOT / FIT Press =769 psi
LOT / FIT =12.16 ppg Hole Depth =7848 md
Fluid Pumped=0.5 Bbls Volume Back =0.4 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->2114 ->276
->4272 ->4172
->6436 ->6273
->8528 ->8370
->10 648 ->10 455
->12 769 ->16 722
->14 ->26 1152
->16 ->36 1655
->18 ->46 2157
->20 ->56 2650
->22 ->
->24 ->
->26 ->
-> ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->1729 ->02650
->2699 ->12637
->3671 ->22634
->4652 ->32633
->5631 ->42632
->6615 ->52630
->7598 ->10 2626
->8584 ->15 2622
->9569 ->20 2620
->10 556 ->25 2617
->11 543 ->30 2615
->12 531 ->
-> ->
-> ->
2
4
6
8
10
12
2
4
6
8
10
16
26
36
46
56
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 102030405060
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
729699671652631615598584569556543531
265026372634263326322630 2626 2622 2620 2617 2615
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
1/9/2023 Moved to W-241, Supply rig with steam, Pin Stabilizer beams in cellar. Apply 500 psi on all sub stompers. Walk through rig and verify all landings, stairs, roof caps
and chain barriers are in place. Warm up Drawworks, Scope up derrick and extend pins. SLK off and remove bridle sheave pins. Plug in upper/crown lights. Secure
block hanging line. Bridle down and secure lines. Set and berm cuttings box, supply rig with water. R/U tongs. Work on putting MP #1 back together. Prep pits for
fluid. Install rebuilt link tilt cylinder and elevators. Cont. working on rig acceptance check list
1/10/2023 N/U Diverter system. R/D MPD starting head, and install bell nipple flang on top of stack. Set stack on diverter 'T'. Set trip nipple, install knife valve. Rig up diverter
vent line. Sim Ops: inespecat TD and complet TD EAM. Install hydraulic elevators. Prime mud pumps. Take on spud mud. Cont. N/U diverter system. Finish
tightening flanges on diverter. Hook up accumulator lines. Install 4" conductor valves. Hook up drain hoses for drip pan, air up boots. Record RKB's. Rig accepted at
17:00. Install mousehole. P/U and rack back 110 joints 5" drill pipe, 17 joints HWDP and Jars. L/D mousehole. Test diverter system: Knife open in 6 seconds,
annular close in 10. Accumulator drawdown starting pressure 2950 psi, after functioning 1950 psi, first 200 psi recharge 18 seconds, full recharge 53 seconds. (6)
N2 bottles at 2425 psi average. Test PVT, flow paddle, gas alarms. AOGCC right to witness waived by Brian Bixby. Mobilize BHA components to rig floor: Bit,
breaker, bottel neck XO. Rig up tongs and load cell. Service rig, inspect TD and saver sub. Grease top drive, IBOP, roughneck and blocks. Pre-spud meeting. M/U
BHA, Kymera Bit, motor, crossover, 1 stand HWDP. Flood lines and stack. PT surface lines to 3000 psi - goood. Tag ice plug at 33'. Wash/ream to base conductor
at 110' at 350 gpm, 40 rpms. Cont. drilling 12-1/4" hole from 110' to 220' at 350 gpm, 320 psi, 40 rpms, 1000ft-lbs, WOB 1-3K. P/U 44K, S/O 44K, ROTW 44K.
Continually jetting flowline and pumping through bleeder as needed. Dynamic loss rate 60-80 bph. CBU x 3 while BROOH with 1 stand HWDP at 350 gpm, 320
psi, 40 rpms, 1000ft-lbs. Cont. POOH and inspect bit - good. Blow down top drive. Clean rig floor. Bring GWD, DM and TM collars to rig floor. Daily disposal to PB
G&I 0 bbls, total 0 bbls. Daily H2O from Lake 2 590 bbls, total 670 bbls. Daily downhole losses 182 bbls, total 182 bbls.
1/11/2023 M/U BHA: RIH with Bit, motor, M/U GWD collar, DM collar, EWR collar, TM collar, (2) NM flex collars, XO and HWDP. Wash down to 220' at 350 gpm,. Drill 12.25"
surface hole from 220' to 313' (total 93', AROP 37 fph) at 350 gpm, 495 psi, 40 rpms, 1.5Kft-lbs, ECD 9.55, P/U 55K, S/O 55K, ROT 55K. Pump through bleeder
and jet flowline as needed. Slide as needed for 2/100' build. KOP 220'. Dynamic loss rate 45-50 bph. Drill 12.25" surface hole from 313' to 717' (total 404', AROP
67 fph) at 400 gpm, 890 psi, 40 rpms, 1.5Kft-lbs, ECD 9.98, P/U 70K, S/O 70K, ROT 70K. Pump through bleeder and jet flowline as needed. Slide as needed for
2/100' build, start 3/100' build at 500'. Dynamic loss rate 10 bph. Drill 12.25" surface hole from 717' to 1130' (total 413', AROP 69 fph) at 400 gpm, 1150 psi, 40
rpms, 2-4Kft-lbs, ECD 10.25, P/U 77K, S/O 71K, ROT 72K. Pump through bleeder and jet flowline as needed. Slide as needed for 3/100' build. no losses. Drill
12.25" surface hole from 1130' to 1603' (total 473', AROP 79 fph) at 450 gpm, 1350 psi, 40 rpms, 2-4Kft-lbs, ECD 10.1, P/U 83K, S/O 78K, ROT 79K. Pump
through bleeder and jet flowline as needed. Slide as needed for 3/100' build. no losses. Distance to WP5: 7.68', 6.32' Low, 4.35' Left. Daily disposal to PB G&I 570
bbls, total 570 bbls. Daily disposal to MP G&I 57 bbls, total 57 bbls. Daily H2O from Lake 2 660 bbls, total 1330 bbls. Daily metal recovered 0 lbs, total 0 lbs. Daily
downhole losses 441 bbls, total 623 bbls.
1/12/2023 Drill 12.25" surface hole from 1603' to 2047' (total 444', AROP 74 fph) at 450 gpm, 1500 psi, 40 rpms, 5-6Kft-lbs, ECD 10.1, P/U 90K, S/O 77K, ROT 84K. Pump
through bleeder and jet flowline as needed. Slide as needed for 3/100' build. No losses. Increase MW to 9.5 ppg prior to base of permafrost. Logged base of
permafrost at 2238'MD. Drill 12.25" surface hole from 2047' to 2533' (total 486', AROP 81 fph) at 425-475 gpm, 1500 psi, 60 rpms, 7Kft-lbs, ECD 10.36, P/U 101K,
S/O 71K, ROT 85K. Pump through bleeder and jet flowline as needed. Start of tangent at 2100', maintenance slides as needed. Drill 12.25" surface hole from 2533'
to 3129' (total 596', AROP 99 fph) at 450 gpm, 1330 psi, 60 rpms, 6.5Kft-lbs, ECD 10.75, P/U 105K, S/O 77K, ROT 89K. Pump through bleeder and jet flowline as
needed. Maintenance slides as needed. Drill 12.25" surface hole from 3129' to 3371' (total 242', AROP 97 fph) at 450 gpm, 1405 psi, 60 rpms, 7.5Kft-lbs, ECD
10.5, max gas 197u, P/U 109K, S/O 78K, ROT 95K. Pump through bleeder and jet flowline as needed. Maintenance slides as needed. Obtain final survey. Circulate
hole clean 3x BU, racking back stand every bottoms up at 450 gpm, 1175 psi, 80 rpms, 6.5Kft-lbs, ECD 10.1 ppg, P/U 110K, S/O 80K, ROTW 93K. Monitor well,
static. RIH to 3371', washing/reaming last stand at 4 bpm, 40 rpms. No fill. BROOH from 3371' to 2812' at 500 gpm, 1350 psi, 80 rpms, 6Kft-lbs, ECD 9.9 ppg, max
gas 55u, P/U 109K, S/O 78K, ROTW 88K. Pull 25 fpm as hole dictates. Daily disposal to PB G&I 570 bbls, total 570 bbls. Daily disposal to MP G&I 57 bbls, total 57
bbls. Daily H2O from Lake 2 660 bbls, total 1330 bbls. Daily H2O from Duck Lake 140 bbls, total 140 bbls. Daily H2O from HWP 380 bbls, total 380 bbls. Daily
metal recovered 0 lbs, total 0 lbs. Daily downhole losses 83 bbls, total 706 bbls. Distance to WP 18.05', 18.05' high, 0.14' Left
1/13/2023 Cont. to BROOH from 2812' to 346' at 500 gpm, 1210 psi, 80 rpms, 5-6Kft-lbs, ECD 9.9 ppg, max gas 48u.P/U 63K, S/O 63K, ROTW 63K. Pull 25 fpm as hole
dictates. Slow pulling speed to obtain bottoms up prior to base of permafrost. Observe hole unload at 1320',. reduce pull speed (5-10fpm) to allow shaker to clean
up. Attempt to POOH at HWDP with 15K overpull. POOH on elevators from 346' to surface laying down BHA. Download MWD. Roller Bit grade 1-1-CT-A-X-I-WT-
TD, PDC grade: 1-1-WT-A-E-I-NO-TD. Rig up Parker casing, M/U volant tool. Install bale extensions, side door elevators. Rig up power tongs. Monitor well on trip
tank - static. M/U and Bakerlok 9-5/8" shoe track, check floats - good. RIH with 40#, TXP, L-80 casing Tq to 21Kft-lbs to 948', M/U ES cementer. RIH with 9-5/8",
47#, Vam21, L-80 casing to 1185' Tq to 31,500 ft-lbs. Set down at 1185', attempt to work through, unable to. Establish circulate staging pumps up to 5.5 bpm 200
psi, attempting to pump casing down. Observe significant sand and wood coming over shakers, increase FV to 75 seconds.
Establish rotary at 2 rpms, 2Kft-lbs free torque. Work pipe with varying parameters from 1185' to 1398'. 0-10 rpms, 2-15Kft-lbs, 4-5.5 bpm, 80-200 psi. 75 bbls
drilling fluid lost while working tight hole. Cont. to wash and ream 9-5/8", 47#, L-80, Vam21 casing from 1398' to 2000' at 5.5 bpm, 108 psi, 10 rpms 6-8Kft-lbs. RIH
with 9-5/8" casing from 2000' to 2297'. Circulate bottoms up staging pumps up to 7 bpm, 135 psi, 10 rpms 7500 ft-lbs reciprocating pipe. Cont. to RIH with 9-5/8",
47#, L-80, Vam21 casing from 2297' to 3122'. P/U 148K, S/O 87K. L/D joints #65,74 due to bad boxes. Calc disp 35 bbls, actu 20 bbls. Daily disposal to PB G&I
575 bbls, total 1772 bbls. Daily disposal to MP G&I 285 bbls, total 741bbls. Daily H2O from Lake 2 0 bbls, total 1610 bbls. Daily H2O from Duck Lake 0 bbls, total
140 bbls. Daily H2O from HWP 550 bbls, total 930 bbls. Daily metal recovered 0 lbs, total 0 lbs. Daily fluid lost to formation 75 bbls, total 781 bbls.
50-029-23741-00-00API #:
Well Name:
Field:
County/State:
PBW W-241
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
1/10/2023Spud Date:
1/14/2023 Cont. to RIH with 9-5/8", 47#, L-80, Vam21 casing from 3122' to 3361' washing last joint to bottom. P/U 148K, S/O 87K. Circulate, Reciprocate from 3361' to 3295',
conditioning mud for cement job, staging pumps from 2-7 bpm, 90-235 psi, 1-2 rpm, 15K Tq. Obtain 18-19 YP on mud. Dynamic Loss Rate = 3 bph. P/U 128K, SO
88K, Rot 92K. Pump Primary Cement Job:HES pump 5 bbls H2O. PT low kick out 1,713 psi, high 4,200 psi, good. Pump 62 bbls 10 ppg 4# red dye & Poly E Flak
4.7 bpm 397 PSI. 467 bbls 12.0 ppg Lead Cement ( ArctiCem) 2.883 YP (909 sx) 4.5 bpm 495 psi. 157 bbls (753 sx) 15.8 ppg HalCem Type I II Tail cmt, 1.17 yld,
4 bpm, 610 PSI. Release F/ Volant, drop shutoff plug. Displace w/ 20 bbls H2O f/CMT Unit 5 bpm, 250 psi. Rig disp w/ 35 bbls 9.5 ppg spud mud, 7 bpm, ICP
250 psi, FCP 300 psi @ 7 BPM. HES pump 80 bbls 9.4 ppg spacer, 4 bpm, 250 ICP, 620 FCP, 22% flow. Rig displace w/ 105 bbls 4.5 bpm, 520 ICP, Maintain 3
BPM to Bump with FCP 897. Bumped @ 245 bbls, 6 bbls over Calc 239 bbls. Hold 1430 psi (3 min). Bleed off psi, Check floats (good). Drop Stage Tool
Cancelation Plug. Flush Stack with Black Water while W/O Plug to fall. Attempt to seat plug. Rock pumps @ 8 bpm x 6 , see tool shift @ 3300 psi. Pushed 15 bbls
away with no returns while attempt to seat plug. CIP @ 14:30 hrs. Parked in tension 168k up. Lost 24 bbls during displacement. 111 bbls green cmt to surface.
Dump 169 bbls excess mud. R/D cement lines and Volant tool. Clean and clear rig floor. Disconnect knife valve. Flush stack with black water. Raise stack and set
'E' slips with 55K in slips. Cut casing and L/D cut joint (29.52'). M/U johnny whacker and flush stack. BD top drive. N/D diverter system. Pull master bushing and
riser. Set stack on pedestal. Remove bell nipple and install RCD head. Prep and dress casing cut. Install wellhead, Tq slip lock connection. Test seals 500/3800 psi
- good. Install test plug. N/U BOPE. Install DSA. Set stack and Tq. Install trip nipple. Connect accumulator lines. Install choke and kill lines. Install MPD lines on
stack. C/O LPR's from 5" solid body to 2-7/8" x 5.5" VBRs. Pressure up accumulator. P/U and M/U 4" and 5" test joints. Pump up test bladders. Line up BOP and
surface equipment. Re-Tq BOP flange. Daily disposal to PB G&I 1007 bbls, total 2779 bbls. Daily disposal to MP G&I 199 bbls, total 940 bbls. Daily H2O from Lake
2 720 bbls, total 2330 bbls. Daily H2O from Duck Lake 0 bbls, total 140 bbls. Daily H2O from HWP 100 bbls, total 1030 bbls. Daily metal recovered 0 lbs, total 0
lbs. Daily fluid lost to formation 135 bbls, total 916 bbls.
1/15/2023 M/U 4" test joint. Flush choke lines. Line up choke, kill and TD to test. Flood lines and purge air, working valves. Attempt to shell test BOPE, UIBOP leaking. Start
changing out upper IBOP. Check pit alarms, PVT sensors, pit and trip G/L, flow paddle. Test gas alarms. Test BOPE 250/3000 psi with 4", 5", 7" test joints.
Witnessed by AOGCC Guy Cook. F/P on Upper IBOP (change out). blind rams (replace rubbers). Choke manifold valves: 1, 2, 3, 8 (serviced). Fail on UPR's 4-1/2"
x 7" on 7" test joint. Replace rubbers and attempt to test again. Could not fill test joint due to VBR's not holding. C/O UPR's to 5" solid body and test - good.
Accumulator draw down: starting pressure 3000 psi, after functioning 1700 psi, 1st 200 psi recharge in 11 seconds, full recharge 62 seconds. (6) N2 bottles at 2283
psi average. R/D and L/D test joint. Clean and clear rig floor. Blow down choke and kill lines. Pull test plug, install wear bushing. Bring BHA components to rig floor.
Rig up tongs to Tq gauge. M/U BHA: tri-cone bit to motor, RIH with 9 stands of HWDP/Jars to 588'. P/U 57K, S/O 56K. Pick up, drift and single in the hole from 588'
to 2337'. Wash down from 2337' and tag ES cementer on depth 2391' at 4 bpm. Establish parameters 350 gpm, 455 psi, 30 rpms, 5Kft-lbs. P/U 90K, S/O 71K,
ROTW 78K. Daily disposal to PB G&I 190 bbls, total 2969 bbls. Daily disposal to MP G&I 0 bbls, total 940 bbls. Daily H2O from Lake 2 280 bbls, total 2610 bbls.
Daily H2O from Duck Lake 0 bbls, total 140 bbls. Daily H2O from HWP 100 bbls, total 1030 bbls. Daily metal recovered 0 lbs, total 0 lbs. Daily fluid lost to formation
0 bbls, total 916 bbls.
1/16/2023 Drill out ES cementer cancellation plug from 2391' to 2400' at 350 gpm, 455 psi, 30 rpms, 5Kft-lbs. Ream and trip through with no issues. P/U 90K, S/O 71K,
ROTW 78K. Cont. to pick up, drift and single in the hole with 5" drill pipe from 2400' to 3196'. Fill pipe and wash down at 3 bpm tagging cement at 3200'. P/U 107K,
S/O 77K. Circulate bottoms up at 475 gpm, 760 psi, 10 rpms, 5-6K ft-lbs reciprocating pipe. Rig up and pressure test casing to 2500 psi for 30 minutes - good.
Pumped 2.8 bbls, bled back 2.8 bbls. Rig down and blow down lines. Drill cement, FE and 20' of new hole from 3200' to 3391'. At 450 gpm, 920 psi, 40 rpms, 7Kft-
lbs. Tag float equipment on depth. Ream through shoe track and trip through to ensure clean. Displace well to clean 9.5 ppg spud mud at 450 gpm, 920 psi. Obtain
SPR's. Rig up and perform FIT with 9.5 ppg mud at 2639'TVD applying 329 psi for 11.9 ppg EMW FIT. Rig down test equipment. Blow down lines. Monitor well,
static. Pump dry job and POOH from 3323' to 588'. Calculated hole fill observed. POOH and rack back HWDP. Pick up and drain motor. Break bit. Bit grade 1-1-
WT-A-E-I-NO-BHA. M/U 8.5" drilling assembly. PDC bit, mud motor, DM collar, ILS, EWR, ILS, HOC collar. Measure RFO = 73.49. Upload MWD. P/U and M/U (2)
flex collars, and (6) HWDP, Jars, (11) HWDP to 698'. Pick up, drift and single in the hole with 5" drill pipe from 698' to 2541'. Calculated displacement observed. Fill
pipe and shallow pulse test at 1652'. Cont. to RIH with stands from 2541' to 3304'. P/U 112K, S/O 69K. Service rig: grease and inspect crown sheaves, top drive
and blocks. Grease washpipe. Fill pipe and establish parameters at 450 gpm, 1080 psi, 40 rpms, 6-7Kft-lbs. P/U 114K, S/O 72K, ROTW 88K. Obtain SPR's. Wash
down to 3391'. Cont. drilling 8-1/2" hole from 3391' to 4130' (Total = 739', AROP 123 fph) at 525 gpm, 2115 psi, 70 rpms, 8Kft-lbs, WOB 2-6K, ECD 10.6 ppg. max
gas 2159u. P/U 121K, S/O 84K, ROTW 99K. Backream full stands. Daily disposal to PB G&I 510 bbls, total 3479 bbls. Daily disposal to MP G&I 0 bbls, total 940
bbls. Daily H2O from Lake 2 140 bbls, total 2750 bbls. Daily H2O from Duck Lake 0 bbls, total 140 bbls. Daily H2O from HWP 0 bbls, total 1030 bbls. Daily metal
recovered 0 lbs, total 0 lbs. Daily fluid lost to Int formation 0 bbls, total 0. Surface hole losses 916 bbls. Distance to WP5: 7.28', 4.75' high, 5.52' left.
1/17/2023 Cont. drilling 8-1/2" hole from 4130' to 4891' (Total = 761', AROP 126.8 fph) at 550 gpm, 2465 psi, 70 rpms, 10-11Kft-lbs Tq, WOB 4-8K, ECD 11.0 ppg. max gas
380u. MW 9.4+, P/U 133K, S/O 83K, ROT 107K. Backream full stands. Cont. drilling 8-1/2" hole from 4891' to 5322' MD, 3903' TVD, (Total = 431', AROP 72 fph)
at 525 gpm, 2400 psi, 70 rpms, 10-12Kft-lbs Tq, WOB 5-12K, ECD 10.7 ppg. max gas 124u. MW 9.4+, P/U 159K, S/O 87K, ROT 112K. Backream full stands. Drill
8.5" Hole F/ 5,322' to 5,829' MD (4,226' TVD) total 507' (AROP 84.5') 525 GPM, on 2,370 PSI, off 2,370 psi, 70 RPM, TRQ 12-14k, TRQ off 13-16k WOB 6-10K.
ECD 10.84, F/O 53%, MW in/out 9.5 ppg. Max Gas 127u. P/U 175K, SLK 89K, ROT 118K. Saw oil at shakers at 5,530' MD. Cont tangent 50.64 inc 303.26 Azi
perform slides as needed. Back ream 60'. Running H2O 15 bph. Both Centrifuges. Drill 8.5" Hole F/ 5,829' to 6,416' MD (4,578' TVD) total 587' (AROP 97.8') 525
GPM, on 2,455 PSI, off 2,340 psi, 70 RPM, TRQ 14-16k, TRQ off 14-15k WOB 6-8K. ECD 10.8, F/O 52%, MW in/out 9.5 ppg. Max Gas 132u. P/U 188K, SLK 88K,
ROT 120K. Start 3/100 build turn at 6,163' MD. Back ream 60'. Distance to WP05: 5.48', 4.55' high, 3.04' right. ROT Hrs:12.33. SLD Hrs: 2.10. 20 concretions
drilled so far, total footage 111 (3.7% of the intermediate section). Daily disp to PB G&I 510 bbls, total 3479 bbls. Daily disp to MP G&I 0 bbls, total 940 bbls. Daily
H2O Lake 2 140 bbls, total 2750 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP 0 bbls, total 1030 bbls. Daily metal 0 lbs, total 0 lbs. Daily fluid
lost 0 bbls. Surface hole loss 916 bbls.
1/18/2023 Drill 8.5" Hole F/ 6,416' to 6,860' MD (4,795' TVD) total 444' (AROP 74') 525 GPM, on 2,505 PSI, off 2,370 psi, 70 RPM, TRQ 14-16k, TRQ off 15k WOB 10-12K.
ECD 10.7, F/O 52%, MW in/out 9.5 ppg. Max Gas 228u. P/U 188K, SLK 88K, ROT 120K. Cont 3/100 build turn. Back ream 60'. Drill 8.5" Hole F/ 6,860' to 7,305'
MD (4,923' TVD) total 445' (AROP 74') 525 GPM, on 2,430 PSI, off 2,320 psi, 70 RPM, TRQ 16-20k, TRQ off 15-17k WOB 6-10K. ECD 10.55, F/O 53%, MW
in/out 9.5/9.55 ppg. Max Gas 366u. P/U 197K, SLK 89K, ROT 126K. Cont 3/100 build turn. Back ream 60'. Drill 8.5" Hole F/ 7,305' to 7,720' MD (4,999' TVD) total
415' (AROP 69') 525 GPM, on 2,600 PSI, off 2,340 psi, 70 RPM, TRQ 17k, TRQ off 16-18k WOB 10-14K. ECD 10.76, F/O 54%, MW in/out 9.5/9.55 ppg. Max Gas
697u. P/U 175K, SLK 91K, ROT 123K. Cont 3/100 build turn. Back ream 60'. Drill 8.5" Hole F/ 7,720' to TD 7,828' MD (5,002' TVD) total 108' (AROP 54') 525
GPM, on 2,555 PSI, off 2,315 psi, 70 RPM, TRQ 17k, TRQ off 17k WOB 4-6K. ECD 10.8, F/O 54%, MW in/out 9.5/9.6 ppg. Max Gas 576u. P/U 165K, SLK 88K,
ROT 117K. End 3/100 build turn at 7,804' as per Geo. Back ream 60'. TD as per Geo to casing set depth. Shut down and shot final survey 7,790.03' MD 5002.53'
TVD 89.54 Inc 332.47 Azi. .Monitor well 10 min, static. PJSM BROOH F/ 7,828' to 7,688' MD Circ 0.5 bu per stand for 2 stands. Pump 24 bbl low 39 vis 9.3ppg and
49 bbls 300+ vis 9.5 ppg sweeps. On time no increase. Circ total 2 BU. 525 gpm 2,345 psi 70 rpm Trq 16k ECD 10.5 Max Gas 645u P/U 165k SLK 88k ROT 121k.
RIH F/ 7,688' to 7,828' MD wash down tag W/ no fill. 450 gpm 1,610 psi. L/D working single. P/U 165 SLK 88k. BROOH F/ 7,828' to 7,065' MD. 525 gpm 2,225 psi
70 rpm Trq 16-17k ECD 10.5 Max Gas 160u P/U 175k SLK 92k ROT 123k. Pull speed 35-45 ft/min. Distance to WP05: 9.23', 6.32' low, 6.72' right. ROT Hrs:8.44.
SLD Hrs: 4.89. 20 concretions drilled so far, total footage 111 (3.7% of the intermediate section). Daily disp to PB G&I 637 bbls, total 4582 bbls. Daily disp to MP
G&I 57 bbls, total 997 bbls. Daily H2O Lake 2 700 bbls, total 4150 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP 0 bbls, total 1030 bbls. Daily
metal 0 lbs, total 0 lbs. Daily fluid lost 0 bbls. Surface hole loss 916 bbls.
test casing to 2500 psi for 30 minutes - good
11.9 ppg EMW FIT.
1/19/2023 BROOH F/ 7,065' to 3,628' MD. 525 gpm 2,025 psi 70 rpm Trq 9-10k ECD 10.7 Max Gas 132u P/U 126k SLK 87k ROT 97k. Pull speed 35-45 ft/min. BROOH F/
3,628' to 3,304' MD. 525 gpm 1,50 psi 70 rpm Trq 6-8k ECD 10.17 Max Gas 32u P/U 100k SLK 80k ROT 90k. Pull speed 10-20 fpm. No Losses. CBU prior to
entering the shoe @ 3361'. No issues pulling into shoe. Pump 40 bbls 9.5 ppg, 240 Vis sweep while rotate reciprocate from 3304' to 3241' circulate casing clean.
Rot/Rec 3304' to 3241' MD. 535 gpm 1750 psi20 rpm Trq 6k ECD 10.2 Max Gas 28u. Sweep back on tine 10% increase. P/U 106 SLK 82k Rot 92k. PJSM Slip
Cut Drilling Line. 11 wraps (69'). Crrtent ton miles 955. ACCUMTM 34,452. 1325' left on spool. Check brakes and calibrate blocks. Trq Deadman 80 ft/lb. PJSM
Pump 30 bbl slug. B/D TD. POOH L/D 5" D.P. F/ 3,304' to 698' MD. Cull pipe per CATV and hard band inspection. P/U 75k SLK 68k. Lost 5 bbls. PJSM POOH L/D
5" HWDP. L/D NM FC, Upload MWD tools as per Sperry MWD. L/D TM, EWR, DM collars. Drain mud motor and break off 8.5" PDC bit. Bit Grade 2-3-WT-A-X-I-
CT-TD. PJSM P/U 5" D.P. M/U wear ring running tool. BOLDS RIH and pull wear ring. L/D running Equip. PJSM Dummy run landing joint and hanger as per Vault
rep onsite. L/D landing joint. R/U 7" Csh Equip. P/U CRT and M/U to TD. Install 8' bale ext. P/U power tongs and hook up hydraulics. Test Trq turn Equip. PJSM
P/U 7" test jnt and test plug. Set test plug. Bleed down Koomey. Break bolts and C/O UPR's to 7" Solid Body. Button up ram door. Energize Koomey. PJSM Flood
stack and 7" test jnt. Purge air. Test 7" Solid Body Rams 5/5 min 250/ 3000 psi on chart. Bleed off and open UPR. PJSM Pull test plug and L/D. Blow down surface
Equip. R/D rig tongs. Test Gas trap in possum belly. PJSM R/U 250T side door elevators, air slips, hand slips, 7" Vam Swedge X NC50. R/U Trq turn W/ as per
Parker Wellbore. Stage 35 7" Hydra Form Centralizers. PJSM P/U M/U 7" 26# BTC Shoe jnt and blank jnt (BakerLoc). Attempted to RIH having issues getting
down. Pulled bushings, drained stack and adjusted stack. Appears buoyancy and friction for bow spring centralizer is the issue. Attempted to make up CRT and
found RLA turning W/ rotary. Inspected RLA and grabber box, no issue. Attempted to make up again and same. Appears swivel on CRT is not working. Worked
down 7" csg. Work on CRT swivel. Found the chain had extended giving the secondary strap to much slack to hold the swivel on the CRT in position. When turning
the CRT the strap would wrap itself around the swivel causing it to turn the RLA and grabber box. Removed chain and replaced with shorter strap. CRT functioning
properly. P/U M/U 3 rd jnt continue having resistance getting jnt down W/ 1-2k. Removed collar and BakerLoc due to none being present. M/U FC Jnt and
BakerLoc. Filled shoe track and checked floats, good. Cont RIH 7" X/O Jnt BTC P X Vam Box to 207' MD. Daily disp to PB G&I 404 bbls, total 4986 bbls. Daily disp
to MP G&I 57 bbls, total 1054 bbls. Daily H2O Lake 2 420 bbls, total 4570 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP 0 bbls, total 1030
bbls. Daily metal 0 lbs, total 0 lbs. Daily fluid lost 5 bbls. Surface hole loss 916 bbls.
1/20/2023 After making up X/O jnt had to L/D Jnts 6 & 7 bad box and pin. In the process lost joystick control for link tilt. C/O joystick at driller console. Service Top Drive,
Grease upper IBOP, Blocks, Inspect top drive and all surface Equipment. Change out link Tilt/Fram Extend Joystick at Drillers console. Circulate @ 1 bpm while
changing out Joy Stick. Continue to RIH w/7", 29#, L-90, VAMTOP Casing from 207' to 1629'. Torque Turn connections to 9,400 ft/lbs Optimum. Run Centralizers
as per Tally. Continue to RIH w/7", 29#, L-90, VAMTOP Casing from 1,629' to 4,119'. Torque Turn connections to 9,400 ft/lbs Optimum. Run Centralizers as per
Tally. Fill pipe every 5 jts, break circulation to Pits every 10 jts. Pumped Casing volume @ 3,346' prior to exiting the shoe @ 3361'.PU 108K, SO 88K. L/D Bad Jnts
66,67,68,. Continue to RIH w/7", 29#, L-90, VAM Csg F/ 4,119' to 5,779' MD. Fill pipe every 5 jts, break circ to pits every 10 jts. CBU every 1,000' at 5,300' MD
stage up to 6 bpm 320 psi. Max Gas 195u. .PU 195K, SO 105K Disp Calc 56 bbl actual 34 bbl lost 22 bbls. Torque Turn to 9,400 ft/lbs Opt. L/D Bad Jnts
120,161,162,163. Continue to RIH w/7", 29#, L-90, VAM Csg F/ 5,779' to 7,828' MD. P/U extra Jnt 182 and wash down 6 bpm 534 psi tag on depth. CBU every
1,000' at 6,300' & 7,300' MD stage up to 6 bpm 490 psi. Max Gas 92u. .PU 243K, SO 102K Disp Calc 17.5 bbl actual 12. bbl lost 5 bbls. Fill pipe every 5 jts, break
circ to pits every 10 jts.. Torque Turn to 9,400 ft/lbs Opt. Daily disp to PB G&I 0 bbls, total 4986 bbls. Daily disp to MP G&I 0 bbls, total 1054 bbls. Daily H2O Lake 2
80 bbls, total 4650 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP total 1030 bbls. Daily metal 0 lbs, total 0 lbs. Daily fluid lost 27 bbls total 27
bbls. Surface loss 916 bbls.
1/21/2023 POOH L/D extra jnt 182. L/D Tag Joint. P/U Landing Joint and 7" Fluted Casing TQ turn connections to 9,400 ft/lbs.. P/U 234K, S/O 102K. Land Hanger on Depth
@ 7817' with 24K on Csg Hgr. Circulate and condition mud for cement job, staging pumps to 7 bpm, 385 psi. SIMOPS: Clean and clear rig floor. Send out Parker
casing equipment. PJSM, R/U Cement equipment, Test lines 1000/4000. Pump Cement job with 30 bbls 10 ppg Spacer, 47 bbls 15.8, 230 sx Class G, 1.155 yld
Primary cement. Displace Cement with 294 bbls ( 8.4 bbls over calculated). Bump plug @ 3 bpm 985 FCP. Hold 1500 psi 3 min. Check Floats, good. CIP @ 12:15.
No losses during job. (Note: Pumped 30 bbls spacer, shut down and blow down lines. Change out Seal cup on Volant Tool prior to pumping Primary Cement). Blow
down and R/D cementers. R/D Volant/Cmt Swivel.Send out all Casing tools.Open lower IBOP and blow down Top Drive. P/U 7" Test Joint and break off test plug,
L/D Joint. M/U Packoff running tool to 5: DP. Land and test Packoff to 3500 psi. L/D Running Tool and Jt DP.Pull mouse Hole & remove cellar grating.Install long
mouse hole and prep to L/D 5" DP. PJSM L/D 5" D.P. in derrick via mouse hole. Cull D.P. as per CATV and hard band inspection. PJSM Break lock ring and
remove back up wrench alignment pin. P/U Grabber bax and clamp saver sub. Break out and remove NC50 saver sub. Install XT39 saver sub. Install lock ring. C/I
Die blocks and bell guide. SIMOPS C/O UPR F/ 7" to VBR's (2.875" X 5.5") Load 4" D.P. in pipe shed. Clean pits. PJSM Send down 5" X/O's, pups & 5" TIW from
rig floor. P/U 4" handling Equip, wear ring, test plug and running tool. P/U 4" test jnt, M/U test plug & set. M/U X/O, side entry sub and 4" TIW to test jnt. SIMOPS
Cont loading and process 4" D.P. and cleaning pits. PJSM Install HP hoses and fill purge air from stack. SIMOPS process 4" D.P. Clean Pits,. PJSM Test 4" TIW &
UPR's (2.875" X 5.5") W/ 4" & 4.5" test jnt. 250/3000 psi 5/5 min on chart. Witnessed waived by Austin McLeod. SIMOPS Process 4" D.P. Clean Pits. PJSM Pull
test plug. Break down X/O, pump in sub and TIW. SIMOPS Process 4" D.P. Bring on 9.2 ppg BaraDril N to pits,. PJSM Service top drive and perform derrick
inspection. C/O Hydraulic elevator inserts to 4". Service PH8 & pipe skate. SIMOPS Process 4" D.P. PJSM Cont process 4" D.P. P/U jnt set wear ring. RILDS. L/D
jnt. SIMOPS C/O faulty B Phase RTD W/ spare. Open J box on TD and tighten wires. Function TD, good. PJSM P/U 4.75 TerraForce and 6.175" Smith XR+PS
(0.5177 TFA) Tricone as per DD. Daily disp to PB G&I 939 bbls, total 5925 bbls. Daily disp to MP G&I 0 bbls, total 1054 bbls. Daily H2O Lake 2 280 bbls, total
4930 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP total 1030 bbls. Daily metal 0 lbs, total 0 lbs. Daily fluid lost 5 bbls total 32 bbls. Surface
loss 916 bbls.
1/22/2023 Continue to P/U BHA, 3.5" IF x XT39 XO, 7 joints 4" HWDP and 4 3/4" Hydra Jar to 280'. P/U 42K, S/O 42K. Single in hole picking up 4", 14#, S-135 Drill pipe from
280' to 2,553'. Drift on skate with 2.3 OD Drift, P/U 94 joints. P/U 58K, S/O 55K, Fill pipe @ 2,553'. Continue to RIH with Clean Out Assy picking up 4", 14#, S-135
Drill pipe from 2,553' to 7,666'. Fill pipe @ 5,000'. P/U 125K, S/O 66K. Circulate hole volume Rotate/Reciprocate from 7,606 to 7,666'. 250 gpm, 1360 psi, 20 rpm,
6-8 Tq. MW In/Out 9.1+, P/U 115K, S/O 70K, Rot 88K. Dump 30 bls cmt contaminated mud at surface. Blow down Top Drive and Prep for casing test. PJSM R/U 4"
TIW, 1502 head pin, HP lines and testing Equip. Line up on choke and kill lines. PJSM Break Circ and pump through kill, chole and manifold. Close UPR's and
purge air F/ system. Test 7" Csg to 2,650 psi for 30 min on chart, good. Pumped 2.4 bbls bled 2.4 bbls. R/D testing Equip. PJSM Wash down F/ 7,666' MD to plug
at 7,691' MD. Drill plug and FC (7,692' MD) on depth, ream through multiple times with and without ROT, no issue. Cont drill shoe track W/ 3-6k WOB, good
cement. Drill Shoe on depth 7.817' MD work string, no issue. Drill 20' new hole to 7,848' MD. 250 gpm, 1350 psi 50 rpm Trq 8k. PJSM Started displacement drilling
last 20' of new hole. Rot/ Rec F/ 7,848' to 7,795' MD Pumped 40 bbl 115 Vis sweep, displace W/ 9.2 ppg BaraDril N 250 gpm 1540 psi 30 rpm Trq 7k. P/U 111k
SLK 89k ROT 89k. Obtain SPR. Shut down monitor well 10 min, static. B/D. PJSM M/U 4" TIW, 1502 head pin and HP testing lines. Break Circ and purge air F/
System. Shut in UPR's. Perform FIT to 12.15 EMW Initial pressure 769 psi 10 min final 556 psi pumped 0.5 bbl bled 0.4 bbls. PJSM Pump 25 bbl 10.3 ppg dry job.
R/D test Equip. Blow down surface Equip. PJSM POOH rack back 4" 14# S-135 D.P. F/7,795' to 280' MD. P/U 49k SLK 49k.No losses. Daily disp to PB G&I 285
bbls, total 6210 bbls. Daily disp to MP G&I 257 bbls, total 1311 bbls. Daily H2O Lake 2 280 bbls, total 5210 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily
H2O HWP total 1030 bbls. Daily metal 0 lbs, total 0 lbs. Intermediate lost total 32 bbls.
1/23/2023 L/D BHA F/280' - T/Surface. Rack back HWDP and Jar. Drain Motor and Grade Bit (1-1-WT-A-E-I-NO-BHA). Clean and Clear Rig Floor. R/U rig tongs for BHA and
inspect Dog Collars and slips. Adjust TQ on Roughneck for Slim hole tools. Rig Service: Inspect and service Iron Roughneck, Grease Blocks and Drawworks,
Inspect Rig tongs, Sensator and M/U Gauge. SIMOPS. Bring BHA to floor. P/U RSS 6.125" Drilling Assembly. P/U BHA: NOV SK613M (TFA = (0.5177), GEO-Pilot,
ADR Collar, ILS, DM Collar, GM Collar, PWD, TM Collar, NM Flex Collars (2), HWDP (7) and HydraJar. Data uploaded to MWD. BHA = 406.42'. P/U 4" XT-39 S-
135 14# DP singling in the hole F/407' - T/3504' MD, 2.32" Drift. P/U 74K, S/O 69K. POOH F/3504" - T/407' MD racking back stands in Derrick. P/U 66k, S/O 60K.
Calculated hole fill observed. Continue P/U 4" XT-39 S-135 14# DP singling in the hole F/407' - T/ 7,424' MD, 2.32" Drift. P/U 120K, S/O 72K. Calculated hole fill
observed. Break in Geo Pilot at 2,500' MD 10-20-30 rpm 3 min ea and shallow pulse test MWD 200 gpm 820 psi. Fill pipe at 5,000' MD. PJSM Pull mouse hole.
Remove hole fill line. Install drip pan below RCD. Install hole fill line. Drain stack. Break loose RCD grey clamp and pull riser. M/U RCD bearing with RCD stand to
4" D.P. Set RCD bearing and M/U grey clamp. Install boot saver and set bushings. Adjust stack and secure. Install short mouse hole. PJSM PT MPD lines. Test
250/1250 psi good. Clean and clear rig floor of MPD Equip. Wash down F/ 7,740' to 7,848' MD 205 gpm/ mpd 220 1,335 psi on, 1311 off, 50 rpm Trq on 6.5k Trq
off 6.5k, WOB 3.-5k, ECD 10.31, MW in/out 9.2/9.25 ppf Max Gas 33u. P/U 131 SLK 72 ROT 89k. Drill 6.125 Hole F/7,848' to 8,000' MD (5,006' TVD) Total 152
(AROP 38) 208 GPM/ MPD 202, 1,375 psi on, 1,298 off 100-120 RPM, TRQ on 7-8k, TRQ off 6.5k, WOB 5-7k. ECD 10.85 Max Gas 83u. P/U 132k, SLK 71k,
ROT 85k. MPD 100% open. Distance to WP05: 5.8, 2.66 low 5.15 left. Daily disp to PB G&I 57 bbls, total 6267 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls.
Daily H2O Lake 2 0 bbls, total 5210 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP total 1030 bbls.
1/24/2023 Drill 6.125 Hole F/ 8,000' to 8,462' MD (5,010' TVD) Total 462' (AROP 77') 230 GPM/ MPD 226, 1,725 psi on, 1,351 off 100-120 RPM, TRQ on 7-9k, TRQ off 7-8k,
WOB 6-10k. ECD 10.78 Max Gas 494u. P/U 131k, SLK 70k, ROT 87k. MPD 100% open. Back ream 30'. Drill 6.125 Hole F/ 8,462' to 8,902' MD (5,014' TVD) Total
440' (AROP 73') 230 GPM/ MPD 226, 1,700 psi on, 1,580 off 120 RPM, TRQ on 8-9k, TRQ off 8k, WOB 6-9k. ECD 11.06 Max Gas 252u. P/U 130k, SLK 63k,
ROT 88k. MPD 100% open. Back ream 30'. Drill 6.125 Hole F/ 8,902' to 9,445' MD (5,014' TVD) Total 543' (AROP 90.5') 230 GPM/ MPD 225, 1,800 psi on, 1,670
off 120 RPM, TRQ on 8-10k, TRQ off 7k, WOB 10-12k. ECD 11.26 Max Gas 252u. P/U 136k, SLK 60k, ROT 87k. MPD 100% open. Back ream 30'. Drill 6.125
Hole F/ 9,445' to 9,976' MD (5,006' TVD) Total 531' (AROP 88.5') 230 GPM/ MPD 225, 1,904 psi on, 1,812 off 120 RPM, TRQ on 8-10k, TRQ off 9k, WOB 10-12k.
ECD 11.7 Max Gas 228u. P/U 131k, SLK 65k, ROT 85k. MPD 100% open. Back ream 30'. Distance to WP05: 10.81',10.58' low 2.22' right. 32 concretions drilled,
for a total footage of 198 (9.5%). Footage in OBd sand: 2,083'. Daily disp to PB G&I 228 bbls, total 6495 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily
H2O Lake 2 420 bbls, total 5630 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP total 1030 bbls.
1/25/2023 Drill 6.125 Hole F/ 9,976' to 10,352' MD (4,998' TVD) Total 376' (AROP 62.6') 230 GPM/ MPD 225, 1,959psi on, 1,841 off 120 RPM, TRQ on 8-10k, TRQ off 9k,
WOB 10-12k. ECD 11.7 Max Gas 420u. P/U 128k, SLK 62k, ROT 84k. MPD 100% open. Back ream 60'. Drill 6.125 Hole F/ 10,352' to 10,884' MD (4,997' TVD)
Total 532' (AROP 88.6') 230 GPM/ MPD 224, 1,960psi on, 1,890 off 120 RPM, TRQ on 10k, TRQ off 7-k, WOB 10-12k. ECD 11.78 Max Gas 487u. P/U 126k, SLK
58k, ROT 84k. MPD 100% open. Back ream 30'. Drill 6.125 Hole F/ 10,884' to 11,372' MD (4,998' TVD) Total 520' (AROP 86.6') 230 GPM/ MPD 224, 1,980psi on,
1,900psi off 120 RPM, TRQ on 9k, TRQ off 8-9k, WOB 5-8k. ECD 11.71 Max Gas 453u. P/U 121k, SLK 62k, ROT 84k. MPD 100% open. Back ream 60'. Drill
6.125 Hole F/ 11,372' to 11780' MD (4,999' TVD) Total 408' (AROP 68') 230 GPM/ MPD 224, 1,980psi on, 1,900psi off 120 RPM, TRQ on 9k, TRQ off 8-9k, WOB
5-8k. ECD 11.71 Max Gas 453u. P/U 121k, SLK 62k, ROT 84k. MPD 100% open. Back ream 60'. At 11,740 drill out the top of the OBd sand into the base of the
OBc clay. Distance to WP05: 0.47',0.46' low 0.06' right. 62 concretions drilled, for a total footage of 323 (8.2%). Footage in OBd sand: 3,923'. Out of Zone 24'. Total
drilled 3,947. Daily disp to PB G&I 342 bbls, total 6837 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily H2O Lake 2 570 bbls, total 6200 bbls. Daily H2O
Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP total 1030 bbls.
1/26/2023 Drill 6.125 Hole F/ 11,780' to 12,033' MD (5,011' TVD) Total 253' (AROP 42') 230 GPM/ MPD 225, 2,157psi on, 2,035psi off 120 RPM, TRQ on 8-10k, TRQ off 7-
8k, WOB 8-11k. ECD 11.76 Max Gas 329u. P/U 120k, SLK 63k, ROT 84k. MPD 100% open. Back ream 60'. Drill 6.125 Hole F/ 12,033' to 12,410' MD (5,019'
TVD) Total 377' (AROP 63') 230 GPM/ MPD 225, 2,043psi on, 2,020psi off 120 RPM, TRQ on 6-9k, TRQ off 5-8k, WOB 8-11k. ECD 11.71 Max Gas 157u. P/U
121k, SLK 64k, ROT 85k. MPD 100% open. Back ream 60'. Drill 6.125 Hole F/ 12,410' to 12,855' MD (5,020' TVD) Total 445' (AROP 74') 215 GPM/ MPD 203,
1895psi on, 1875psi off 120 RPM, TRQ on 6-7k, TRQ off 5-6k, WOB 4-11k. ECD 11.86 Max Gas 157u. P/U 121k, SLK 64k, ROT 85k. MPD 100% open. Back
ream 60'. Drill 6.125 Hole F/ 12,855' to 13,042' MD (' TVD) Total 187' (AROP 31') 215 GPM/ MPD 203, 2050psi on, 1958psi off 120 RPM, TRQ on 6-7k, TRQ off 5-
6k, WOB 4-11k. ECD 11.76 Max Gas 137u. P/U 121k, SLK 64k, ROT 85k. MPD 100% open. Back ream 60'. At bit depth of 13042' survey depth of 12987' Sperry
survey tool showed an azimuth change of 8.15 for a dogleg of 13.45. Decision made to rack back two stands above and back ream to 12,300' to perform a open
hole sidetrack. Distance to WP05: 24.41',23.83' low 5.3' right. 100 concretions drilled, for a total footage of 534 (10.2%). Footage in OBd sand: 5,171'. Out of Zone
58'. Total drilled 5,229. Daily disp to PB G&I 513 bbls, total 7350 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily H2O Lake 2 790 bbls, total 6990 bbls.
Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP total 1030 bbls.
1/27/2023 Brack ream f/13,042' t/12,399' 215 GPM/ MPD 205, 1982psi off 120 RPM, TRQ 4-6k, ECD 11.26 Max Gas 23u. P/U 116k, SLK 70k, ROT 86k. MPD 100% open.
Back ream 60'. Trough for sidetrack f/12,399' t/12,430' x2 at 100'/hr x1 at 50'/hr, 205GPM/MPD 195,1750PSI, 120 RPM, ECD 11.26, P/U 114k, SLK 70k, ROT
84K. Took a survey and started. Drill 6.125 Hole F/ 12,460 to 12,604' MD (5,021' TVD) Total 144' (AROP 24') 205 GPM/ MPD 195, 1777psi on, 1710psi off 120
RPM, TRQ on 6-7k, TRQ off 5-6k, WOB 2-5k. ECD 11.55 Max Gas 47u. P/U 116k, SLK 64k, ROT 85k. MPD 100% open. Back ream 60'. Drill 6.125 Hole F/
12,604 to 13,003' MD (5,016' TVD) Total 399' (AROP 66') 208 GPM/ MPD 195, 1741psi on, 1715psi off 120 RPM, TRQ on 6-7k, TRQ off 5-6k, WOB 2-5k. ECD
11.85 Max Gas 152u. P/U 114k, SLK 61k, ROT 83k. MPD 100% open. Back ream 60'. Drill 6.125 Hole F/ 13,003 to 13,265' MD (5,020' TVD) Total 262' (AROP
43') 218 GPM/ MPD 203, 1995psi on, 1950psi off 120 RPM, TRQ on 6-7k, TRQ off 5-6k, WOB 8-10k. ECD 11.68 Max Gas 203u. P/U 115k, SLK 62k, ROT 8384k.
MPD 100% open. Back ream 30'. Drill 6.125 Hole F/ 13,265 to 13,547' MD (5,022' TVD) Total 282' (AROP 47') 215 GPM/ MPD 209, 2069psi on, 1938psi off 120
RPM, TRQ on 6-7k, TRQ off 5-6k, WOB 8-10k. ECD 11.6 Max Gas 152u. P/U 115k, SLK 60k, ROT 84k. MPD 100% open. Back ream 30'. Distance to WP05:
47.62', 24.29' low 40.96' right. 112 concretions drilled, for a total footage of 560 (9.9%). Footage in OBd sand: 5,609'. Out of Zone 58'. Total drilled 5,667'. Daily
disp to PB G&I 513 bbls, total 7863 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily H2O Lake 550 bbls, total 7540 bbls. Daily H2O Duck Lake 0 bbls, total
140 bbls. Daily H2O HWP total 1030 bbls.
1/28/2023 Drill 6.125 Hole F/ 13547' to 13862' MD (5,016' TVD) Total 315' (AROP 53') 225 GPM/ MPD 209, 2182psi on, 2099psi off 120 RPM, TRQ on 6-7k, TRQ off 5-6k,
WOB 6-12k. ECD 11.63 Max Gas 94u. MW IN/OUT 9.09.0+ P/U 115k, SLK 60k, ROT 84k. MPD 100% open. Drill 6.125 Hole F/ 13862' to 14081' MD (5,019'
TVD) Total 219' (AROP 37') 225 GPM/ MPD 209, 2250psi on, 2180psi off 120 RPM, TRQ on 6-7k, TRQ off 5-6k, WOB 6-12k. ECD 11.63 Max Gas 124u. MW
IN/OUT 9.0/9.0+ P/U 116k, SLK 61k, ROT 84k. MPD 100% open. BROOH f/14081' t/11,000' at 30-50'/min 225 GPM/ MPD 207, 1950psi 120 RPM, TRQ 4-5k,
ECD 11.1 Max Gas 31u. MW IN/OUT 9.0/9.0 P/U 113k, SLK 67k, ROT 83k. MPD 100% open. BROOH f/11,000' t/8176' at 30-50'/min 225 GPM/ MPD 207,
1880psi 120 RPM, TRQ 4-5k, ECD 10.9 Max Gas 31u. MW IN/OUT 9.0/9.0 P/U 113k, SLK 67k, ROT 83k. MPD 100% open. Distance to WP05: 26.47', 20.12' low
17.21' right. 132 concretions drilled, for a total footage of 610 (9.7%). Footage in OBd sand: 6206'. Out of Zone 58'. Total drilled 6264'. Daily disp to PB G&I 456
bbls, total 8319 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily H2O Lake 660 bbls, total 8200 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O
HWP total 1030 bbls.
1/29/2023 BROOH f/8176' t/7799' (5008' TVD) at 30-50'/min 225 GPM/ MPD 207, 1568psi 120 RPM, TRQ 3-5k, ECD 10.9 Max Gas 31u. MW IN/OUT 9.0/9.0 P/U 118k, SLK
79k, ROT 87k. Slowed to 10'/min 20RPM pulling into the shoe. MPD 100% open. Circulate and Condition PJSM. Pump 40bbl sweep (150 vis) STS while rotating
and reciprocating. 230 GPM/ MPD 216, 1756psi 60 RPM, TRQ 2-3k, ECD 10.9 Max Gas 15u. Sweep back on time No noticeable increase in cuttings. Flow check
well with Beyond 15 min static. PJSM, pull bushings, open clamp on stack, bring RCD to rig floor and rack back on stand. B/D top drive. Install trip nipple. tighten
clamp, install clamp, install bushings, air boot filled, flood stack and check for leaks-good. Depth @ 7730'. POOH 5 stands, no indication of swabbing. Pump 25bbl
dry job 10.4 ppg. B/D top drive Pulled bushings, installed stripping rubbers, installed bushings and air slips. POOH f/7730 t/4338. Hole fill on, calculated hole fill
observed. P/U-93k S/O-79k. Pulling 150FPM due to tight tolerance in 7" casing. POOH f/4338' t/407' P/U-57k S/O-57k. Monitor well for 5 min before pulling BHA
through stack. Well static. Displacement: Calc-29bbls Act- 36bbls, lost 7bbls. R/B HWDP and jars. L/D flex collars and float subs. Read MWD tools. L/D TM collar
R/B f/ DM t/ ADR. L/D geopilot and bit. P/U-40K S/O-40k. Bit grade: 1-1-WT-A-X--NO-PR. Clean and clear rig floor. PJSM, P/U 4" test joint and pull wear ring. P/U
4" test joint and install test plug. M/U XO's, Pump in sub, 4" TIW and 4" dart valve to test joint. M/U XT-39 pup joint, XT-39 x 4.5" IF XO and torque to save sub.
Check sensators and test chart. Flood stack, choke manifold test jt and TD. Pressure up to 200psi and function valves to get air out. Re-flood and perform shell test.
PJSM, TEST BOPE'S TO 250/3000 PSI FOR 5/5 MINS, WITNESS WAIVED BY BRIAN BIXBY, TEST #1. 4" TEST JT, ANNULAR, UPPER IBOP, 4" DART
VALVE, KILL #3, CMV'S 11,12,13,14,15-PASS, TEST #2. 4" TEST JT, ANNULAR, LOWER IBOP, 4" TIW #1, HCR KILL,. CMV'S 7,8,9,10-FAIL/PASS( TEST
FAILED ON LOW PSI, TROUBLE SHOOT AND DETERMINED 2 7/8" X 51/2" VBR UPR'S FAILED, CONTINUED TESTING W/ ANNULAR INSTEAD OF UPR'S),
TEST #3. 4" TEST JT, ANNULAR, MANUAL KILL, CMV'S 4,5,6-PASS, TEST #4. 4" TEST JT, 2 7/8" X 5 1/2". VBR LPR'S-PASS, PERFORM KOOMEY DRAW
DOWN AT THIS TIME, INITIAL PSI-ACCUMULATOR=3000, MANIFOLD=1600, ANNULAR=1100, FINAL PSI-ACCUMULATOR=1500, MANIFOLD=1500,
ANNULAR=1200, 200 PSI=32 SEC, FULL RECOVERY=101 SEC, NO2 BOTTLE PSI=2287 PSI X6,. BLEED KOOMEY DOWN, B/D STACK TO OPEN DOORS
AND C/O UPR'S. PJSM, CONT. C/O UPPER VBR. REMOVE RAMS INSPECTED AND TOP SEALS ON BOTH RAMS WERE BAD. C/O TOP SEALS, CLEANED
AND INSPECTED RAMS REINSTALLED. PRESSURED UP KOOMEY. READY FOR CONT. TESTING. PJSM, CONT. TEST BOPE'S TO 250/3000 PSI FOR 5/5
MINS, WITNESS WAIVED BY BRIAN BIXBY, TEST #5- 4" UPPER VBR RAMS-GOOD, #6-DID NOT CATCH PSI-#6A-SUPER CHOKE-GOOD TEST #7-
MANUAL SUPER CHOKE-GOOD, L/D TEST JOINT BREAK OFF TIW, SIDE ENTRY, DART. TEST #8-DID NOT BRING ABOVE 250PSI. #8A- BLIND RAMS,
CMV #1,2,3.-GOOD. P/U M/U 4.5" TEST JOINT W/ SIDE ENTRY, #2 TIW AND FILL LINES/PURGE AIR. TEST #9- 4.5" UPPER VBR, TIW#2 AND HCR CHOKE-
GOOD, #10 MANUAL CHOKE-GOOD. #11-4.5" LOWER VBR-GOOD. WHILE. INSPECTING CHART AFTER TESTING NOTICED #4 TEST WAS NOT ABOVE
250PSI. P/U M/U 4"TEST JOINT AND RETEST 4"LOWER VBR-GOOD. R/D test equipment. Clean and clear rig floor. Distance to WP05: 26.47', 20.12' low 17.21'
right. 132 concretions drilled, for a total footage of 610 (9.7%). Footage in OBd sand: 6206'. Out of Zone 58'. Total drilled 6264'. Daily disp to PB G&I 171 bbls, total
8490 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily H2O Lake 360 bbls, total 8560 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP
total 1030 bbls.
1/30/2023 PJSM. P/U Sperry RSS directional BHA #6. M/U New 6.125" Hycalog SKC613M to 5200 Geopilot. M/U BHA to TM. P/UJ 5' pup and pump on tools to warm them
up. Blow down TD. Plug in and download MWD tools. Cont P/U BHA flex collar x2 and Float sub x2, XO, 4X HWDP, XO, Jars, XO, 3x HWDP. RIH out of derrick
f/407' t/2634'. P/U-59K S/O-57k. RIH out of derrick f/2364' t/7740' filling every 2500-3000'. P/U-120K S/O-82K. Broke in geopilot seals at 3200' 10-20-30RPM for
3min each. Monitor well for 5min-static. Drain stack. Pull Beyond riser, set boot saver over stump of stnd 116. P/U stnd 117 w/ rotating head. TQ stnd, set bearing in
RCD then set boot saver. Cut and slip 69' of drill line (11 wraps). Check brake tolerances, 35404 accumulated ton miles, 1256' of drill line left on spool.
Grease/Inspect TD, crown sheaves, block sheaves, FH-80 and over head spinners. Grease wash pipe and IBOP. TIH out of derrick f/7803' t/ 13992' filling pipe
every 2500-3000'. Washed from 13992' t/14081'. Slow running speed at 12415' due to the sidetrack point. Shot a survey at 12667' to verify in new wellbore. P/U-
114k S/O-58K Rot-84K GPM 203 PSI 1850 TQ-6k RPM-40. Drill 6.125 Hole F/ 14082' to 14115' MD (5,020' TVD) Total 34 (AROP 34') 218 GPM/ MPD 209,
1985psi on, 1940psi off 120 RPM, TRQ on 7-8k, TRQ off 7-8k, WOB 3-8k. ECD 11.50 Max Gas 23u. MW IN/OUT 9.0/9.0+ P/U 114k, SLK 58k, ROT 84k. MPD
100% open. Drill 6.125 Hole F/ 14115' to 14494' MD (5,028' TVD) Total 379 (AROP 63') 218 GPM/ MPD 205, 1985psi on, 1940psi off 120 RPM, TRQ on 8-11k,
TRQ off 7-8k, WOB 5-10k. ECD 11.33 Max Gas 141u. MW IN/OUT 9.0/9.0+ P/U 114k, SLK 58k, ROT 84k. MPD 100% open. Distance to WP05: 31.26', 32.61'
High 16.85' right. 135 concretions drilled, for a total footage of 625 (9.5%). Footage in OBd sand: 6555'. Out of Zone 58'. Total drilled 6613'. Daily disp to PB G&I
171 bbls, total 8661 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily H2O Lake 140 bbls, total 8700 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily
H2O HWP total 1030 bbls.
1/31/2023 Drill 6.125 Hole F/ 14494' to 14999' MD (5,025' TVD) Total 505 (AROP 84') 205 GPM/ MPD 195, 1870psi on, 1780psi off 120 RPM, TRQ on 8-11k, TRQ off 8-9k,
WOB 6-11k. ECD 11.78 Max Gas 141u. MW IN/OUT 9.0/9.0+ P/U 126k, SLK 53k, ROT 84k. MPD 100% open. Drill 6.125 Hole F/ 14999' to 15505' MD (5,025'
TVD) Total 506 (AROP 84') 208 GPM/ MPD 195, 1870psi on, 1780psi off 120 RPM, TRQ on 8-11k, TRQ off 8-9k, WOB 6-11k. ECD 11.78 Max Gas 98u. MW
IN/OUT 9.0/9.0+ P/U 126k, SLK 53k, ROT 84k. MPD 100% open. Drill 6.125 Hole F/ 15505' to 16010' MD (5,026' TVD) Total 505 (AROP 84') 208 GPM/ MPD
195, 1940psi on, 1850psi off 120 RPM, TRQ on 7-9k, TRQ off 7-8k, WOB 6-12k. ECD 11.82 Max Gas 98u. MW IN/OUT 9.0/9.0+ P/U 131k, SLK N/A, ROT 85k.
MPD 100% open. Drill 6.125 Hole F/ 16010' to 16264' MD (5,024' TVD) Total 254 (AROP 42') 208 GPM/ MPD 195, 1940psi on, 1850psi off 120 RPM, TRQ on 7-
9k, TRQ off 7-8k, WOB 6-12k. ECD 11.82 Max Gas 107u. MW IN/OUT 9.0/9.0+ P/U 131k, SLK N/A, ROT 85k. MPD 100% open. Distance to WP05: 65.28', 54.85'
low 35.39' right. 148 concretions drilled, for a total footage of 664 (7.9%). Footage in OBd sand: 8367'. Out of Zone 58'. Total drilled 8425'. Daily disp to PB G&I 570
bbls, total 9321 bbls. Daily disp to MP G&I 0 bbls, total 1311 bbls. Daily H2O Lake 700 bbls, total 9400 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O
HWP total 1030 bbls.
2/1/2023 Drill 6.125 Hole F/ 16264' to 16580' MD (5,013' TVD) Total 316 (AROP 53') 195GPM/ MPD 181, 1897psi 120 RPM, TRQ on 8-11k, TRQ off 7-8k, WOB 6-12k.
ECD 11.82 Max Gas 67u. MW IN/OUT 9.0/9.0+ P/U 127k, SLK 47k, ROT 85k. MPD 100% open. Drill 6.125 Hole F/ 16580' to 17025' MD (5,005' TVD) Total 445
(AROP 74') 195GPM/ MPD 181, 1930psi on 1848psi off 120 RPM, TRQ on 9-11k, TRQ off 8-9k, WOB 6-12k. ECD 11.74 Max Gas 179u. MW IN/OUT 9.0/9.0+
P/U 127k, SLK NA, ROT 84k. MPD 100% open. Drill 6.125 Hole F/ 17025' to 17529' MD (4989' TVD) Total 504 (AROP 84') 195GPM/ MPD 181, 1848psi on
1810psi off 120 RPM, TRQ on 9-11k, TRQ off 9-10k, WOB 6-12k. ECD 11.94 Max Gas 230u. MW IN/OUT 8.9/9.0+ P/U 128k, SLK 47k, ROT 83k. MPD 100%
open. Drill 6.125 Hole F/ 17529' to 17615' MD (4987' TVD) Total 86 (AROP 43') 195GPM/ MPD 181, 1912psi on 1857psi off 120 RPM, TRQ on 8-11k, TRQ off 7-
8k, WOB 6-10k. ECD 11.98 Max Gas 303u. MW IN/OUT 8.9/9.0+ P/U 127k, SLK 47k, ROT 85k. MPD 100% open. R&R f/17615 t/17553 while circulate and
condition, pump tandem sweep 32bbls 8.8ppg 39 vis, 32bbl 9.9ppg 150 vis 46bbl late no noticeable increase in cuttings. Cont CBU x2, while prepping pits for
displacement. 195GPM/ MPD 185, 1912psi on 1857psi off 120 RPM, TRQ off 9-10k, ECD 11.99 Max Gas 303u. MW IN/OUT 8.9/9.0+ P/U 127k, SLK N/A, ROT
85k. MPD 100% open. Dynamic loss rate-8bbl/hr. Distance to WP05: 36.38', 34.78' low 10.65' right. 163 concretions drilled, for a total footage of 709 (7.9%).
Footage in OBd sand: 9740'. Out of Zone 58'. Total drilled 9798'. Daily disp to PB G&I 114 bbls, total 9345 bbls. Daily disp to MP G&I 575 bbls, total 1886 bbls.
Daily H2O Lake 1120 bbls, total 10520 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP total 1030 bbls.
2/2/2023 Cont circulating hole clean, racking back stand every BU at 195 gpm, 1980 psi, 120 rpms, 9-10Kft-lbs. Max gas 84U, ECD's 11.99 ppg with 9.0 ppg mud. P/U
127K, S/O N/A, ROTW 85K. Prep pits for SAPP train and displacement. Pump SAPP train and displace well to 9.0 ppg Quickdril-N at 195 gpm, 1970 psi, 100-120
rpms, 10-12Kft-lbs, max gas 94U. P/U 120K, S/O N/A, ROT 85K. Flow check well - static. Obtain SPR's. Drop 1.9" drift and BROOH F/17,615' - T/17,124' at 195
gpm, 1642 psi, 120 rpm, 6-8Kft-lbs, max gas=38u, P/U=131K, S/O=N/A, ROT=85K Pull 25-30 fpm as hole dictates. BROOH F/17,124' - T/13,675' at 195 gpm,
1390 psi, 120 rpms, 8-9Kft-lbs, ECD 10.75 ppg EMW. Max gas 60u P/U=131K, S/O=N/A, ROT=85. Pull 25-30 fpm as hole dictates. BROOH F/13,675' - T/12415'
at 195 gpm, 1190 psi, 120 rpms, 8-9Kft-lbs ECD 10.67 ppg EMW with 9.05 ppg mud. P/U=131K, S/O=N/A, ROT=85. Pull 25-30 fpm as hole dictates. Pull above
sidetrack point at 12430' and RIH two stands without pumps rotary. Obtain a survey to confirm in new hole.. Cont. BROOH F/12,415' - T/10275' at 215 gpm, 1290
psi, 120 rpms, 8-9Kft-lbs, ECD 10.44 ppg EMW, max gas 60U, P/U=114K, S/O=71, ROT=91, Pull 25-30 fpm as hole dictates. Cont. BROOH F/10,275' - To 7803'
at 215 gpm, 1075 psi, 120 rpms, 6-7Kft-lbs, ECD 10.16 ppg EMW, max gas 45U, P/U=111K, S/O=76, ROT=88, Pull 25-30 fpm as hole dictates. Pump tandem low
vis/wt high vis/wt sweep (no increase in cuttings) at 216 gpm, 1065 psi, 40 rpms, 4Kft-lbs. P/U 11K, S/O 76K, ROTW 88K. Blow down top drive. Distance to WP05:
36.38', 34.78' low 10.65' right. 163 concretions drilled, for a total footage of 709 (7.9%). Footage in OBd sand: 9740'. Out of Zone 58'. Total drilled 9798'. Daily disp
to PB G&I 0 bbls, total 9345 bbls. Daily disp to MP G&I 1494 bbls, total 3380 bbls. Daily H2O Lake 2: 140 bbls, total 10660 bbls. Daily H2O Duck Lake 0 bbls, total
140 bbls. Daily H2O HWP 0 bbls total 1030 bbls.
2/3/2023 Monitor well, static. Remove RCD bearing and install trip nipple. Service rig: grease crown, blocks, TD, RLA, Link tilt, spinners, check TD and rotary table oil. POOH
laying down drill pipe from 7803' to 2934'. Cont. POOH laying down drill pipe from 2934' to 407'. Calc displacement for trip 25 bbls, actual 37 bbls. Monitor well,
static. L/D BHA. Drift retrieved on float. Download MWD. Bit Grade 1-2-CT-T-X-I-BT-TD. Clean and clear rig floor. R/U to RIH with 4-1/2" lower completion. C/O
elevators, rig up power tongs. Bring slips and J-box to rig floor Count pipe in shed. RIH with 4-1/2", 12.6#, L-80, H563 lower completion with slotted joints as per
detail to 4012'. Cont. to RIH with 4-1/2", 12.6#, L-80, H563 liner with slotted joints from 4,012' to 5,335', Tq connections to 3800ft-lbs. P/U 74K, S/O 65K. Observe
hydraulic leak on Parker TRS tongs. R/D tongs, R/U backup tongs. Cont. to RIH with 4-1/2", 12.6#, L-80, H563 liner with slotted joints from 5,335' to 8,981', Tq
connections to 3800ft-lbs. P/U 99K, S/O 72K. Daily disp to PB G&I 0 bbls, total 9345 bbls. Daily disp to MP G&I 0 bbls, total 3380 bbls. Daily H2O Lake 2: 140 bbls,
total 10800 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP 0 bbls total 1030 bbls. Daily metal recovered: 0 lbs, Total 40 lbs. Daily Production
Losses: 32 bbls, Total 278 bbls.
2/4/2023 Con. to RIH with 4-1/2", 12.6#, L-80, W563 liner with slotted joints as per tally from 8981' to 10,007', making up ZXHD liner hanger. TQ connections to 3800 ft-lbs.
Cont. to RIH with 4-1/2" lower completion on drill pipe from 10,007' to 13, 510'. P/U 126K, S/O 63K at 50 fpm. Cont. to RIH with 4-1/2" lower completion on drill pipe
out of derrick from 13,510' to 16,314'. Cont. to RIH with 4-1/2" lower completions, pick up, drift and single in with HWDP from 16,314' to 17,505' at 60 fpm. Set
down at 17,505', attempt to work down with 190K up and all available wt down. Establish circulation at 3 bpm, 350 psi. Cont to attempt to work past 17,505' without
sucess. Drop 1.43" phenolic ball. Pick up to 180K to set liner in tension. Pump ball down at 3 bpm, 350 psi. Pressure up to 1040 psi and hold for 2 minutes. Cont.
pressure up to 2000 psi to set ZXHD liner hanger. Slack off to 35K to verify. Cont to pressure up to 4060 psi to shear out ball seat and release. from liner. P/U 124K,
S/O 95K pick up 5.5' to expose dog sub. Establish rotary at 20 rpms and set down 60K on liner top x 2 to set pkr. Pick up to neutral wt. B/D top drive. TOL 7506.65'.
Rig up, flood lines. PT liner top to 1500 psi for ten minutes. Pumped 1.5 bbls, bled back 1.4 bbls. Good test. R/D and blow down liners. Monitor well, static. POOH
laying down HWDP and DP from 7562' to 936'. P/U 50K, S/O 50K. Calc disp 42 bbls, actual 56 bbls. Cont. to POOH laying down drill pipe from 936' to surface. L/D
liner running tool. Clean and clear rig floor. RIH with excess drill pipe in derrick to 4150'. P/U 80K, S/O 68K. Cacl disp 23.4 bbls, act 21.3 bbls. POOH laying down
drill pipe from 4150' to 2205'. P/U 62K, S/O 59K. 2.3 bbls lost during trip out. Daily disp to PB G&I 290 bbls, total 9635 bbls. Daily disp to MP G&I 0 bbls, total 3380
bbls. Daily H2O Lake 2: 140 bbls, total 10940 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP 0 bbls total 1030 bbls. Daily metal recovered: 0
lbs, Total 40 lbs. Daily Production Losses: 43 bbls, Total 321 bbls.
Activity Date Ops Summary
2/5/2023 Cont. to POOH laying down drill pipe from 2205' to surface. Pull wear bushing. Service rig: grease crown blocks, RLA, Link tilt assembly. Check TD oil and rotary
table oil. Rig up to RIH with upper completion. R/U power tongs, install Tq Tech, C/O elevators, order jewelry in shed and count pipe. RIH with 4-1/2", 12.6#, L-80,
W563 upper completion as per detail to 1625'. TQ turn connections to 3800ft-lbs. P/U 48K, S/O 48K. Cont. to RIH with 4-1/2", 12.6#, L-80, W563 upper completion
as per detail from 1625'. M/U space-out pups, full joint, hanger and landing joint. Attempt to land tubing at 7512.42' with mule shoe 5.77' stung into ZXHD tie back
sleeve. Stack out at 7506.8' with 10K down multiple times. Put 1/2 turns in pipe x 2 and continue to stack out at same depth. POOH and L/D 7.88' pup joint. M/U
hanger and landing joint and Land tubing tail at 7504.54' TQ turn connections to 3800ft-lbs. P/U 97K, S/O 73K. RILDS. Rig down Parker TRS equipment. Close
annular and put 500 psi quick test on hanger seals (to ensure seals aren't rolled) - good. L/D landing joint. P/U johnny whacker. Flush stack and surface equipment
and blow down same. N/D BOPE: pull bushings, riser. Install MPD test cap. Pull mouse hole. R/D MPD high pressure lines. Bleed down accumulators system and
disconnect. Pull drip pan. Disconnect choke and kill lines. 4-bolt stack. Cont. N/D BOP and rack back on pedestal. Secure with chain binders. Remove DSA, clean
and grease API ring grooves. Sim Ops: continue cleaning pits. N/U tree: Test tubing hanger void 500/5000 psi - good. Test tree 500/5000 psi - good. Rig down test
equipment. Pull BPV. Spot in LRS. Rig up circulating manifold. Daily disp to PB G&I 57 bbls, total 9692 bbls. Daily disp to MP G&I 0 bbls, total 3380 bbls. Daily
H2O Lake 2: 190 bbls, total 11130 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP 0 bbls total 1030 bbls. Daily metal recovered: 0 lbs, Total 40
lbs. Daily Production Losses: 27 bbls, Total 348 bbls.
2/6/2023 Spot corrosion inhibited brine and diesel for freeze protection. PT lines with LRS 250/1000 psi - change out lo-torq. Reverse circulate 89 bbls CI brine at 3 bpm, 275
psi, 46 bbls diesel 3 bpm 310 psi, followed by 38 bbls quickdril. Shut down and line up on tubing, pump 38 bbls diesel at 3 bpm 210 psi. Allow the well to U-tube for
1 hr. Sim Ops Cont. cleaning pits. Rig up lubricator with ball and rod installed. Open master and drop ball and rod. R/D lubricator. Sim Ops Cont. cleaning pits.
Attempt to pressure up to set PKR, observe 2 Lo-Torq leaking, change out lo-torq. Change out sensator and fittings. Re flood lines. Pressure up to 3500 psi and set
packer. MIT-T to 3500 psi - good. Bleed to 500 psi. MIT-IA to 3500 psi - good. Total pumped 3.8 bbls, bled back 3.7 bbls. Rig down testing lines. Final Pressures on
well: T=0 psi, IA=8psi, OA=0 psi,C/O split bushings wtih master bushings. Clear rig floor of 4" TIW, rental XO's. Un-pin tongs and remove. Bridal up. Sim Ops: cont.
to clean pits, cluean mud manifolds on both pumps, B/D pump #2, B/D rodwash, drain charge pumps. Scope derrick down. Blow down staem and water. Disconnect
interconnects. Secure cellar. Jack up outriggers. Swap to cold start power at 21:00. Cruz trucks on location at 21:00. Pull away and stage axillary equipment. Jack
up motor and mud mod, connect to trucks. Daily disp to PB G&I 630 bbls, total 10322 bbls. Daily disp to MP G&I 0 bbls, total 3380 bbls. Daily H2O Lake 2: 50 bbls,
total 11180 bbls. Daily H2O Duck Lake 0 bbls, total 140 bbls. Daily H2O HWP 0 bbls total 1030 bbls. Daily metal recovered: 0 lbs, Total 40 lbs. Daily Production
Losses: 27 bbls, Total 348 bbls.
2/7/2023 Mobilize mods to 'L' pad. Jack up pipe shed and catwalk and stage on pad. Walk sub base off W-241. Cont. to walk sub-base of W-241. Install tow bar. Mobilize
sub base, pipe shed, and catwalk to L-pad. Set rig mats around L-233. RDMO @ 6:00.
50-029-23741-00-00API #:
Well Name:
Field:
County/State:
PBW W-241
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
MIT-IA to 3500 psi - good.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
2
1
20
56
X Yes No X Yes No 25
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
ArcticCem 909 2.88
Type I/II 753 1.17
4.5
2,373.70
Crossover 9 5/8 47.0 L-80 XP x Vam 2 41.14 2,373.70 2,332.56
2,394.12 2,391.29
Pup Joint 9 5/8 40.0 L-80 TXP Tenaris 17.59 2,391.29
18.09 2,412.21 2,394.12
ES Cementer 10 40.0 L-80 TXP Halliburton 2.83
Pup Joint 9 5/8 40.0 L-80 TXP Tenaris
3,237.62
Casing 9 5/8 40.0 L-80 TXP Tenaris 825.41 3,237.62 2,412.21
3,279.11 3,239.01
Baffle Adapter 10 40.0 L-80 BTC Halliburton 1.39 3,239.01
1.16 3,280.27 3,279.11
Casing 9 5/8 40.0 L-80 TXP Tenaris 40.10
Float Collar 10 40.0 L-80 BTC DHS
(4) on shoe track, (1) every joint to jnt 27, then every other joint to jnt 81.
Casing 9 5/8 40.0 L-80 TXP BTC Tenaris 78.97 3,359.24 3,280.27
www.wellez.net WellEz Information Management LLC ver_04818br
4
Ftg. Returned
Ftg. Cut Jt. Ftg. Balance
No. Jts. Delivered No. Jts. Run
Length Measurements W/O Threads
Ftg. Delivered Ftg. Run
RKB to CHF
Type of Shoe:Bullnose Casing Crew:Parker
10.7 467
3,361.003,371.00
CEMENTING REPORT
Csg Wt. On Slips:55,000
Spud Mud
14:30 1/14/2023 Surface
15.8 157
Bump press
Returns to Surface
Bump Plug?
245/239.5
1430
111
Rig
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 62
9.5 3
90
897
Csg Wt. On Hook:130,000 Type Float Collar:Conventional No. Hrs to Run:13.5
9 5/8 47.0 L-80 Vam 21 Vam
9 5/8 47.0 L-80 Vam 21 Vam
BTC DHS 1.76 3,361.00 3,359.24
2,295.94 2,332.56 36.62
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW W-241 Date Run 13-Jan-23
CASING RECORD
County State Alaska Supv.J. Lott / C. Montague
3,279.11
Floats Held
220.34 624
111 513
Spud Mud/Spacer
Rotate Csg Recip Csg Ft. Min. PPG9.5
Shoe @ 3361 FC @ Top of Liner
181.4 474 260
Casing (Or Liner) Detail
Shoe
Casing
Cut Joint
10 40.0 L-80
urface
90
Returns to Surface
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
3
176
Yes X No Yes X No 19
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe 6 5/8
4730
Rotate Csg Recip Csg Ft. Min. PPG9.5
Shoe @ 7817 FC @ Top of Liner7,692.00
Floats Held
30 47
047
Spud Mud
CASING RECORD
County State Alaska Supv.J. Lott / O Amend
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW W-241 Date Run 20-Jan-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Innovex 1.65 7,816.71 7,815.06
Csg Wt. On Hook:234,000 Type Float Collar:Conventional No. Hrs to Run:17
9.5 6
100
985
FI
R
S
T
S
T
A
G
E
10Tuned spacer 35
274/268
1500
0
MP1
15.8 47
Bump press
Calculated
Bump Plug?
12:15 1/21/2023 6,500
7,816.717,828.00
CEMENTING REPORT
Csg Wt. On Slips:24,000
Spud Mud
27.71 RKB to CHF
Type of Shoe:Enclosed down jet Casing Crew:Parker Wellbore
No. Jts. Delivered 215 No. Jts. Run 181 34
Length Measurements W/O Threads
Ftg. Delivered 9,030.00 Ftg. Run 7,816.00 Ftg. Returned 1,214.00
Ftg. Cut Jt. Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
4
2 ea bow spring and 4 ea SR, 2 ea Hydro Form & 4 ea SR Jnt 2 & 3, 1 ea Bow Spring & 2 ea SR RC Jnt, 1 ea Hydro
Form F/ 5-32 jnts.
7" Csg 7 26.0 L-80 BTC 120.79 7,815.06 7,694.27
FC 6 5/8 BTC Innpvex 2.60 7,694.27 7,691.67
7" Csg 7 26.0 L-80 BTC 39.22 7,691.67 7,652.45
X/O Vam/BTC 7 26.0 L-80 VAM 42.76 7,652.45 7,609.69
7" Csg 7 29.0 L-80 VAM 7,574.65 7,609.69 35.04
Pup 7 29.0 L-80 VAM 9.84 35.04 25.20
Hanger 8 3/4 0.91 25.20
RKB 24.29
Class G 230 1.16
100
6,500
X
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 02/15/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: PBU W-241
PTD: 222-154
API: 50-029-23741-00-00
FINAL LWD FORMATION EVALUATION LOGS (01/11/2023 to 02/02/2023)
EWR-M5, AGR, ABG, PCG, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU W-241 LWD Subfolders:
PBU W-241 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
WELL: PBU W-241PB1
PTD: 222-154
API: 50-029-23741-70-00
FINAL LWD FORMATION EVALUATION LOGS (01/11/2023 to 01/27/2023)
EWR-M5, AGR, ABG, PCG, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
PBU W-241PB1 LWD Subfolders:
Please include current contact information if different from above.
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:20230119 1650 APPROVED Cementing Intermediate PBU W-241 (PTD_ 222-154) Intermediate Log and TOC
Date:Thursday, January 19, 2023 4:53:40 PM
From: Rixse, Melvin G (OGC)
Sent: Thursday, January 19, 2023 4:47 PM
To: Joseph Engel <jengel@hilcorp.com>
Subject: RE: HAK PBU W-241 (PTD: 222-154) Intermediate Log and TOC
Joe,
Thanks for the update. AOGCC geologist agrees with interpretation.
Approved.
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: Joseph Engel <jengel@hilcorp.com>
Sent: Thursday, January 19, 2023 11:36 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: HAK PBU W-241 (PTD: 222-154) Intermediate Log and TOC
Mel –
Attached is the MWD logs for the 8.5” intermediate hole on PBU W-241.
Hilcorp Geologists are calling the Schrader OBC at ~7350’ MD pay, the shallower Schrader Bluff
sands are wet.
Hilcorp is proposing a TOC of 6,500’ MD, top of the Schrader Bluff being at 6,607’ MD, with class g
15.8ppg cement.
We did find heavy oil in the shallow Ugnu4A at ~ 4561’ MD, however Hilcorp does not believe this
zone to be significant as it will not produce or flow on its own, is ~ 20’ TVD thick, and will be isolated
from all Schrader Bluff sands
Due to past cementing issues on W pad, Hilcorp wants to minimize the risk of losses during the
cement job by minimizing the cement column height and displacement ECDs. This will allow us to
use all 15.8ppg high compressive strength cement, vs a lead and tail with 12.0 ppg cement. Also of
concern is with the planned volume of 30% excess and a TOC of ~4,000’, pumped in a gauge hole,
there is a risk that cement could be brought up to plug the OA.
Please let me know if you have any questions. Thank you for your time.
-Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503
Office: 907.777.8395 | Cell: 805.235.6265
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN ORIN W-241
JBR 03/06/2023
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:7
4", 5" and 7" test joints used for testing. The upper IBOP failed during the shell test. Replaced and retested on test #7 for a
pass. Test #2 CMV #8 failed. Serviced and retested for a pass. Test #4 CMVs 1, 2 and 3 failed. Serviced and retested with
other components during test #4B for a pass. Test #8 the blinds failed. Cycle and retest for a fail. C/O and retest for a pass.
Upper pipe rams failed while testing 7". Cycled rams and retested for a fail. Rams were pulled and redressed. Retested upper
rams on 7" for a fail. Change out upper pipe rams to 5" solids and tested for a pass. 7" solids will be installed in the upper pipe
rams and tested before running 7" casing. ***NOTE***: Because of the 4.5"x 7" VBRs not testing on the 7" test joint, I instructed
the company representative to state in the request for witness for the upper pipe ram change, to inform us if they intend to use
the VBRs instead of Solids. Neither of the VBRs that were tested for the 7" held any pressure while trying to test. The first set
of VBRs that were tested would hold approximately 80 psi while pressuring up, but the pressure would drop to zero immediately
after pumping stopped. These seals were inspected and were damaged and replaced. The second set leaked worse than the
first set and would not hold enough pressure to fill the test joint with fluid. No reason for this was found after inspecting the test
Test Results
TEST DATA
Rig Rep:J. Sture/B. SerafineOperator:Hilcorp Alaska, LLC Operator Rep:J. Lott/C. Montague
Rig Owner/Rig No.:Hilcorp Innovation PTD#:2221540 DATE:1/16/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopGDC230114154742
Inspector Guy Cook
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 17.5
MASP:
1572
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 FP
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 2 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" 5000 P
#1 Rams 1 4.5"x7" VBRs FP
#2 Rams 1 Blinds FP
#3 Rams 1 2 7/8"x5.5" V P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8" 5000 P
HCR Valves 2 3 1/8" 5000 P
Kill Line Valves 1 3 1/8" 5000 P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1700
200 PSI Attained P11
Full Pressure Attained P62
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@2283
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P10
#1 Rams P5
#2 Rams P5
#3 Rams P5
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
FP
FP
FP FP
BOPE Test Hilcorp Innovation
1/16/2023
PBU W 241 (PTD 2221540)
AOGCC Inspection # bopgdc2301141547
Test Remarks
4", 5" and 7" test joints used for testing. The upper IBOP failed during the shell test. Replaced and
retested on test #7 for a pass. Test #2 CMV #8 failed. Serviced and retested for a pass. Test #4 CMVs 1,
2 and 3 failed. Serviced and retested with other components during test #4B for a pass. Test #8 the
blinds failed. Cycle and retest for a fail. C/O and retest for a pass. Upper pipe rams failed while testing
7". Cycled rams and retested for a fail. Rams were pulled and redressed. Retested upper rams on 7" for
a fail. Change out upper pipe rams to 5" solids and tested for a pass. 7" solids will be installed in the
upper pipe rams and tested before running 7" casing. ***NOTE***: Because of the 4.5"x 7" VBRs not
testing on the 7" test joint, I instructed the company representative to state in the request for witness
for the upper pipe ram change, to inform us if they intend to use the VBRs instead of Solids. Neither of
the VBRs that were tested for the 7" held any pressure while trying to test. The first set of VBRs that
were tested would hold approximately 80 psi while pressuring up, but the pressure would drop to zero
immediately after pumping stopped. These seals were inspected and were damaged and replaced. The
second set leaked worse than the first set and would not hold enough pressure to fill the test joint with
fluid. No reason for this was found after inspecting the test joint and the rams. Test #12 was
accidentally started on the chart during the high test for Test #9. The pressure was bled off and the test
was restarted on a section of the chart that was not yet used.
upper IBOP failed
CMV #8 failed.CMVs 1,
2 and 3 failed.
blinds failed.Upper pipe rams failed
upper pipe rams to 5"solids
Neither of
the VBRs that were tested for the 7"held any pressure while trying to test.
Date: 1/10/2023 Development:X Exploratory:
Drlg Contractor:Rig No.Innovation AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.:2221540 Rig Phone:
Rig Email:
MISCELLANEOUS: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
ACCUMULATOR SYSTEM:Diverter Size:13 5/8 in.
Systems Pressure:2950 psig P Hole Size:12 1/4 in.
Pressure After Closure:1950 psig P Vent Line(s) Size:16 in.P
200 psi Recharge Time:18 Seconds P Vent Line(s) Length:222.5 ft.P
Full Recharge Time:53 Seconds P Closest Ignition Source:77 ft.P
Nitrogen Bottles (Number of):6 Outlet from Rig Substructure:207 ft.P
Avg. Pressure: 2425 psig P
Accumulator Misc:NA
Vent Line(s) Anchored:P
MUD SYSTEM:Visual Alarm Turns Targeted / Long Radius:NA
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: 10 sec P
Mud System Misc:0 NA Knife Valve Open Time: 6 sec P
Diverter Misc:NA
GAS DETECTORS:Visual Alarm
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 P
Total Test Time:1 hrs Non-Compliance Items:0
Remarks:
Submit to:
jlott@hilcorp.com
TEST DATA
Joel Sture
phoebe.brooks@alaska.gov
Hilcorp North Slope LLC
.Performed diverter test with 5' pipe size.
0
James Lott
0
670-3094
TEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
PBU W-241
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Diverter Systems Inspection Report
GENERAL INFORMATION
WaivedHilcorp
Form 10-425 (Revised 03/2017)2023-0110_Diverter_Hilcorp_Innovation_PBU_W-241
J. Regg; 5/26/2023
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 Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 CenterPoint Drive, Suite 1400
Anchorage Alaska 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU W-241
Hilcorp, LLC
Permit to Drill Number: 222-154
Surface Location: 4577' FSL, 1441' FEL, Sec. 21, T11N, R12E, UM, AK
Bottomhole Location: 29' FNL, 403' FEL, Sec. 07, T11N, R12E, 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,
Jessie L. Chmielowski
Commissioner
DATED this ___ day of December, 2022. 30
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2022.12.30 09:35:52
-09'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address: 6. Proposed Depth: 12. Field/Pool(s):
MD: 17629' TVD: 4952'
4a. Location of Well (Governmental Section): 7. Property Designation:
Surface:
Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 15. Distance to Nearest Well Open
Surface: x-611790 y- 5959551 Zone- 4 to Same Pool:1100'
16. Deviated wells: Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 91 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Driven 20" 129.5# X-52 80' Surface Surface 110' 110'
9-5/8" 47# L-80 Vam 21 2500' Surface Surface 2500' 2108'
9-5/8" 40# L-80 TXP 865' 2500' 2108' 3365' 2580'
8-1/2" 7" 26# L-80 Vam Top 7960' Surface Surface 7960' 5001'
6-1/8" 4-1/2" 12.6# L-80 Hyd 563 9819' 7810' 17629' 4996' 4952'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name: Nathan Sperry
Monty Myers Contact Email:nathan.sperry@hilcorp.com
Drilling Manager Contact Phone:907-777-8450
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
January 2, 2023
14426'
12-1/4"Lead - 877 sx / Tail - 730 sx
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
296 sx Class G
Uncemented Slotted Liner
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Conductor/Structural
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
7509
18. Casing Program: Top - Setting Depth - BottomSpecifications
1699
Total Depth MD (ft): Total Depth TVD (ft):
107205344
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
1572
2604' FSL, 3692' FEL, Sec. 17, T11N, R12E, UM, AK
29' FNL, 403' FEL, Sec. 07, T11N, R12E, UM, AK
85-008
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp North Slope, LLC
4577' FSL, 1441' FEL, Sec. 21, T11N, R12E, UM, AK ADL 028263, 028262 & 047450
PBU W-241
PRUDHOE BAY
SCHRADER BLUFF OIL POOL,
ORION DEVELOPMENT AREA
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Anne Prysunka at 3:35 pm, Dec 15, 2022
MGR22DEC22
50-029-23741-00-00
* BOPE test to 3000 psi. Annular to 2500 psi.
* Variance to 20 AAC 25.412 (b) Approved for packer placement
to be greater than 200' from top of perforations. Packer
to be placed within the reservoir to assure monitoring of
IA so injection remains in zone.
* LWD data for 8-1/2" OH to AOGCC to confirm placement of TOC for 7" casing.
* State to witness MIT-T and MIT-IA to 3500 psi.
222-154
77.3'
50.8' SFD
DSR-12/15/22
(+42 sx in 120' shoe track 772 total tail)
SFD 12/28/2022GCW 12/30/22
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2022.12.30 09:36:09 -09'00'
987
11718
220
CHEV181112
071112PB1
K091112
M
W-26
W-27
W-31
W-31A
W-34
W-44
W-51WETW
Z-01
Z-02
Z-03
Z-04
-05
-06
-07
Z-09
-10
Z-100
102
Z-103
Z-108
Z-11
Z-112PB1
Z-113PB1
Z-114
Z-115
Z-116
Z-12
Z-13
Z-14
Z-15
Z-16 Z-17
Z-18
Z-19
Z-19A
Z-20
Z-21
Z-210
Z-210PB1
-22
Z-23 Z-24
Z-25
Z-26
Z-27
Z-28
-29
-30
Z-31
Z-32
Z-33
Z-35Z-35PB1
Z-38
8PB1
Z-39
Z-46A
Z-50
Z-61
Z-65
Z-66
Z-68
Z-69
Z-70
Z-71
Z-220PB1
Z-220
Z-228
Z-229
Z-222
Z-223
W-241_wp02
HILCORP NORTH SLOPE
Greater Prudhoe Bay
AOR MAP
W-241 Injector (Proposed)
FEET
0 750 1,500 2,250
POSTED WELL DATA
Well Label
WELL SYMBOLS
INJ Well (Water Flood)
P&A Oil/Gas
J&A
Temporarily Abandoned
Active Oil
Injector Location
REMARKS
Well Symbols at top of Schrader Bluff OBd sand (target
of proposed W-241 well). Black dashed circle and lines
= 1320' radius from heel to toe of proosed W-241 lateral
injector
December 1, 2022
PETRA 12/1/2022 2:47:54 PM Z-223Z-221Z-220Z-228Z-229
Well Name PTD API Status
Top of Oil Pool
(SB OBd, MD)
Top of Oil Pool
(SB OBd, TVD)Top of Cmt (MD) Top of Cmt (TVD)
Zonal
Isolation Comments
Z-116 211-124 50-029-23455-00-00 WAG Injector 9942' 4916' 8640' 4323' Closed
7" TOC logged at 8640' MD
with IBC on 12/22/2011.
Kuparuk Injector, not open to
Schrader Bluff
Z-228 222-055 50-029-23718-00-00 Producer 7358' 4906' Surface Surface Open
Active SB Producer. 9-5/8"
cemented fully from shoe at
7492' MD to surface in 12-
1/4" hole. 2 stage cement job.
14bbls excess seen from 1st
stage, 185 bbls excess to
surface on second stage.
Z-229 222-104 50-029-23726-00-00 Producer
N/A Obc Sand
Lateral
N/A Obc Sand
Lateral Surface Surface Open
Active SB Producer. 9-5/8"
cemented fully from shoe at
7318' MD to surface in 12-
1/4" hole. 2 stage cement job.
30bbls excess seen from 1st
stage, 330 bbls excess to
surface on second stage.
Z-220 221-105 50-029-23705-00-00 Producer 5878' 4693' Surface Surface Open
Active SB producer. 9-5/8"
cemented fully from shoe at
6474' MD to surface in 12-
1/4" hole with 229 bbls excess
to surface and no losses.
Z-222 222-083 50-029-23722-00-00 Producer 14238' 4777' Surface Surface Open
Active SB Producer. 9-5/8"
cemented fully from shoe at
6075' MD to surface in 12-
1/4" hole. 2 stage cement job.
60bbls excess seen from 1st
stage, 320 bbls excess to
surface on second stage.
Area of Review PBU W-241
Prudhoe Bay West
(PBU) W-241
Permit to Drill Application
Version 1
12/7/2022
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 13-5/8” 5M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 26
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 27
16.0 Run & Cement 7” Intermediate Casing .................................................................................. 30
17.0 Drill 6-1/8” Hole Section .......................................................................................................... 35
18.0 Run 4-1/2” Injection Liner ...................................................................................................... 40
19.0 Run Upper Completion/ Post Rig Work ................................................................................. 44
20.0 Innovation Rig Diverter Schematic ......................................................................................... 47
21.0 Innovation Rig BOP Schematic ............................................................................................... 48
22.0 Wellhead Schematic ................................................................................................................. 49
23.0 Days Vs Depth .......................................................................................................................... 50
24.0 Formation Tops & Information............................................................................................... 51
25.0 Anticipated Drilling Hazards .................................................................................................. 52
26.0 Innovation Rig Layout ............................................................................................................. 58
27.0 FIT Procedure .......................................................................................................................... 59
28.0 Innovation Rig Choke Manifold Schematic ............................................................................ 60
29.0 Casing Design ........................................................................................................................... 61
30.0 MASP ....................................................................................................................................... 62
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 64
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 65
Page 2
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU W-241
Pad Prudhoe Bay W Pad
Planned Completion Type 4-1/2” Injection
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 17629’ MD / 4952’ TVD
PBTD, MD / TVD 17609’ MD / 4952’ TVD
Surface Location (Governmental) 4577' FSL, 1441' FEL, Sec 21, T11N, R12E, UM, AK
Surface Location (NAD 27) X= 611,789.9, Y=5,959,550.9
Top of Productive Horizon
(Governmental)2604' FSL, 362' FEL, Sec 17, T11N, R12E, UM, AK
TPH Location (NAD 27) X=607532.2, Y=5962794.9
BHL (Governmental) 29' FNL, 403' FEL, Sec 7, T11N, R12E, UM, AK
BHL (NAD 27) X= 602076, Y=5970646
AFE Drilling Days 25
AFE Completion Days 2
Maximum Anticipated Surface
Pressure (intermediate) 1572 psi
Maximum Anticipated Surface
Pressure (production) 1699 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 2199 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 50.8 ft = 77.3 ft
GL Elevation above MSL: 50.8 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
W-241 SB Injector
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-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 VAM 21 6,870 4,750 1,086
8-1/2” 7” 6.184 6.125 7.644 29 L-80 VamTop 8,160 7,030 676
6-1/8” 4-1/2” 3.958 3.833 5.2 12.6 L-80 H563 8,430 7,500 288
Tubing 4-1/2” 3.958 3.833 4.937 12.6 L-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)
Surface &
Intermediate
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
Production 4”3.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x 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.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x 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
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@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 Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Wyatt Rivard 907.777.8547 wrivard@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 mmayfield@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@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 West
W-241 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PBU W-241 is a grassroots injector planned to be drilled in the Schrader Bluff OBd sands. W-241 is part of
a multi-well program targeting the Schrader Bluff sand on PBU W-pad
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set below the SV3. 8-1/2” intermediate
hole will be drilled into the top of the Schrader Bluff OBd sand, with 7” casing ran and cemented. A 6-1/8”
lateral section will be drilled. A 4-1/2” slotted liner will be run in the open hole section, followed by 4-1/2”
injection tubing. This well will not be pre-produced prior to being on injection.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately January 2, 2023, pending rig schedule.
Surface casing will be run to 3,365’ MD / 2,657’ 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 Innovation Rig to well site
2. N/U & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” to section TD, Run and cement 7” casing
6. Drill 6-1/8” lateral to well TD
7. Run 4-1/2” liner
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface & Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
e Schrader Bluff OBd sands. a grassroots injector p
s well will not be pre-produced p
Page 8
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU W-241.
Ensure to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 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.
x 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.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x 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
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x 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)”.
Page 9
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states:
“A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates
pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure
that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the
maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured
depth above the top of the perforations, unless the commission approves a different placement depth as the
commission considers appropriate given the thickness and depth of the confining zone.”
In order to effectively produce this fault block, the current wellplan has the intermediate casing shoe landing at
the OBd production interval at 90 degrees inclination. To make the ball and rod we land to set the production
packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees inclination. The
MD we currently have planned for 70 degrees is at ~7000’ MD. The production packer will be ~50’ MD above
the X nipple which puts it at ~6700 MD / ~4728’ TVD. The intermediate casing shoe is planned at ~7960’ MD /
5001’ TVD which means the planned packer depth is ~1260’ MD away. From a TVD standpoint, the production
tubing packer is ~273’ TVD from the intermediate casing shoe. With the intermediate casing set in the Schrader
Bluff sand, and the injection packer set inside the intermediate casing, injection fluids will be confined to the
Schrader bluff sands.
gq
Hilcorp would like to request a variance from 20 AAC 25.412.(b) w
Page 10
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2” & 6-1/8”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@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)
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 W-241 will utilize a 20” conductor on W-pad. Ensure to review attached surface plat and make
sure rig is over appropriate conductor.
9.2 Ensure PTD, COAs, 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 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
x Cold mud temps are necessary to mitigate hydrate breakout
9.10 Ensure 5” liners in mud pumps.
x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x N/U 20” x 13-5/8” DSA
x N/U 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC with 24 hour notice to witness. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 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:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
Notify AOGCC with 24 hour notice to witness. Function test diverter.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD below the SV3 sand. Confirm this setting depth with the
Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in
DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still
meeting tangent hold target.
x 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
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x 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.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at
base of perm and at TD.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
x Gas hydrates are possible at W-Pad.
n TD below the SV3 sand.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.5+ (For Hydrates/Free Gas based on offset
wells)
x 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.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO 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 to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity. Observe well for flow.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” BTC x NC50, and VAM 21 x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.75” on the location prior to running.
x Top 2,500’ of casing 47# drift 8.525”
x Actual depth to be dependent upon base of permafrost and stage tool
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x 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 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Note: A single stage cement job is planned, however W pad has a history of troublesome
cement jobs not getting cement to surface. A Stage tool will be ran for contingency
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
12.5 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x Bowspring Centralizers only
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to surface
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x 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.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
9-5/8” 47# L-80 VAM21 Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”28,400 ft-lbs 31,550 ft-lbs 34,650 ft-lbs
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
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W-241 SB Injector
Drilling Procedure
12.6 W-pad has a history of no cement returns to surface. HES Stage tool to be ran at base of
permafrost as a contingency tool at ~ 2500’. Centralizers 1/jt for 5 joints above and below stage tool.
x Confirm stage tool depth compatibility with cancellation plug, inclination sensitive
12.7 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
x Actual length of 47# may change due to depth of permafrost as drilled
x Ensure drifted to 8.525”
12.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary. Slow in and out of slips.
12.9 W Pad has history of trouble running casing, use CRT when needed, work through trouble spots
12.10 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.
12.11 Lower casing to setting depth. Confirm measurements.
12.12 Have slips staged in cellar, along with necessary equipment for the operation.
12.13 Circulate and condition mud through CRT. Reduce YP to < 20 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.
W-pad has a history of no cement returns to surface.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
13.0 Cement 9-5/8” 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.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x 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
x Review test reports and ensure pump times are acceptable.
x 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 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + open hole excess (300% for lead and 100% for tail).
W-Pad has a history of no returns to surface on cement jobs requiring top jobs. Lead cement
volume has been increased to mitigate this risk. Job will consist of lead & tail, TOC brought to
surface. Cement will continue to be pumped until clean spacer is observed at surface.
Estimated Single Stage Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4
12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 4 421.8 2366.3
Total Lead 450.4 2526.7 877.3
12-1/4" OH x 9-5/8" Casing (3365' - 2000') x .0558 bpf x 2 152.3 854.4
Total Tail 152.3 854.4 730.3LeadTail
120' * .0758 = 9.1 bbls, 51 cu ft, 161.1 905.4 772.5 (sks)120' shoe track
(300% for lead and 100% for tail)
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
Cement Slurry Design
13.9 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 continu
with the cement job.
13.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.12 Displacement calculation:
2500’ x 0.0732 bpf + (3,365’-120’-2500’) x 0.0758 bpf
183+ 56.5 = 239.5 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.15 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, this is to ensure the stage tool is not prematurely opened.
13.16 If plug is not bumped, consult with Drilling Engineer.
13.17 If cement returns are to surface and HES stage tool is not needed, drop cancellation plug to
neutralize the stage tool. Proceed with setting slips.
13.18 If no returns to surface and HES stage tool is needed, contact drilling engineer.
Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
x Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher
pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or
cement returns to surface and volume pumped to see the returns. Circulate until YP < 20
again in preparation for the 2nd stage of the cement job.
x If stage tool is needed: Ensure the free fall stage tool opening plug is available. This is the
back-up option to open the stage tool if the plugs are not bumped.
x Be prepared for cement returns to surface. Dump cement returns in the cellar or open the
shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to
assist. Ensure to flush out any rig components, hard lines and BOP stack that may have
come in contact with the cement.
x Tentative contingency stage volumes below. Cement volume based on annular volume +
open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC
brought to surface. Cement will continue to be pumped until clean spacer is observed at
surface.
x Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
x After pumping cement, drop ES Cementer closing plug and displace cement with spud mud
out of mud pits.
x Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
x Monitor returns closely while displacing cement. Adjust pump rate if necessary. 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.
x Decide ahead of time what will be done with cement returns once they are at surface. We
should circulate approximately 100 - 150 bbls of cement slurry to surface.
x Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool
closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure
stage tool has closed. Slips will be set as per plan to allow full annulus for returns during
surface cement job. Set slips.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
13.19 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x 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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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 Give AOGCC 24hr notice of BOPE test, for test witness.
14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.3 NU 13-5/8” x 5M BOP as follows:
x 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
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve.
14.4 RU MPD RCD and related equipment
14.5 Run 5” BOP test plug
14.6 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 4-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.7 RD BOP test equipment
14.8 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.9 Mix 9.5 ppg spud mud to be used in intermediate hole
14.10 Set wearbushing in wellhead.
14.11 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.12 Ensure 5” liners in mud pumps.
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Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 P/U 8-1/2” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the intermediate hole section.
15.2 TIH to TOC above the shoetrack. Note depth TOC tagged on morning report.
15.3 RU and test casing to 2,500 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.
15.4 Drill out shoe track and 20’ of new formation.
15.5 CBU and condition mud for FIT.
15.6 Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 11.5 ppg provides >25 bbls based on 9.5ppg MW, 8.46 ppg PP (swab kick at 8.46 ppg BHP).
15.7 Drill 8-1/2” hole section to section TD in the Schrader OBd sand. Confirm this setting depth with
the Geologist and Drilling Engineer while drilling the well.
x Efforts should be made to minimize dog legs. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Well control procedures
x Flow rates, hole cleaning, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x 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.
x Slow in/out of slips and while tripping to keep swab and surge pressures low.
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a ~9.5 by
TD.
x Intermediate Hole AC:
x There are no wells with a clearance factor of <1.0
15.8 8-1/2” hole mud program summary:
Casing test and FIT digital data to AOGCC immediately upon completion of FIT. email: melvin.rixse@alaska.gov
Page 28
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at same ppg as
surface TD MW and ensure we TD with 9.5+ ppg.
Depth Interval MW (ppg)
Surface shoe - TD 9.5+
x 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.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO 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 to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
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Drilling Procedure
15.9 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
15.10 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
15.11 TOOH and LD BHA
No open hole logging program planned.
LWD Gamma-ray/Resistivity data to AOGCC promptly to confirm required TOC
on 8-1/2" OH x 7".
(Eline)
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Drilling Procedure
16.0 Run & Cement 7” Intermediate Casing
16.1 R/U and pull wearbushing.
16.2 R/U 7” casing running equipment (CRT & Tongs)
x Ensure 7” VamTop x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Plan to land the 7” casing on a mandrel hanger.
16.3 P/U shoe joint, visually verify no debris inside joint.
16.4 Continue M/U & thread locking 120’ 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
1 joint – 7”, 1 Centralizer mid joint with stop ring
7” Float Collar
16.5 Continue running 7” intermediate casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 500’ MD above Schrader Bluff
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
7” 29# L-80 VamTop Make-Up Torques:
Casing OD Minimum Optimum Maximum
7”8,460 ft-lbs 9,400 ft-lbs 10,340 ft-lbs
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Drilling Procedure
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Drilling Procedure
16.6 Continue running 7” casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
16.8 Slow in and out of slips.
16.9 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.
16.10 Lower casing to setting depth. Confirm measurements.
16.11 Have emergency slips staged along with necessary equipment for the operation.
16.12 Circulate and condition mud through CRT. Reduce YP to < 20 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.
16.13 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.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x 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
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
16.14 Document efficiency of all possible displacement pumps prior to cement job.
16.15 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.
16.16 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.
16.17 Fill surface lines with water and pressure test.
16.18 Pump 60 bbls 11 ppg tuned spacer.
16.19 Mix and pump cmt per below recipe.
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Drilling Procedure
16.20 Cement volume based on annular volume + open hole excess 6(40%). Job will consist of tail,
TOC brought to 500’ above the Schrader Bluff (Note: TOC will be adjusted to 500’ above
Ugnu hydrocarbon bearing zone if Ugnu contains hydrocarbons).
Estimated Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
16.21 After pumping cement, drop top plug and displace cement with mud out of mud pits.
16.22 Monitor returns closely while displacing cement. Adjust pump rate if necessary.
16.23 Land top plug on stage collar and pressure up to 500 psi over bump pressure. Bleed pressure and
check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement
builds compressive strength.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
Tail Slurry
System HalCem
Density 15.8 lb/gal
Yield 1.17 ft3/sk
Mixed
Water 5.08 gal/sk
()
f (Note: TOC will be adjusted to 500’ aboveg(
Ugnu hydrocarbon bearing zone if Ugnu contains hydrocarbons)
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Drilling Procedure
x Note calculated top of cement
x 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
17.0 Drill 6-1/8” Hole Section
17.1 MU 6-1/8” Cleanout BHA (Milltooth Bit & 1.22° PDM)
17.2 TIH w/ 6-1/8” cleanout BHA to float collar with 4” dp
17.3 RU and test casing to 2,500 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.
17.4 Drill out shoe track and 20’ of new formation.
17.5 CBU and condition mud for FIT.
17.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.7 ppg FIT is the minimum
required to drill ahead
x 9.7 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5ppg BHP)
17.7 POOH and LD cleanout BHA
17.8 PU 6-1/8” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 4” 14# XT39
x Run a ported float in the production hole section.
17.9 6-1/8” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x 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
7" casing test and FIT digital data to AOGCC upon completion of FIT. Email: melvin.rixse@alaska.gov
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Drilling Procedure
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.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x 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.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total
Solids
MBT HPHT Hardness
Production 8.9-9.5 15-25 -
ALAP
15 - 30 4-6 <10% <8 <11.0 <100
System Formulation:
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 – 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
17.10 TIH with 6-1/8” directional assembly to bottom
17.11 Install MPD RCD
17.12 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
x Density may change based upon TD of surface hole section
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Drilling Procedure
17.13 Begin drilling 6-1/8” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x 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
15.14 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 150-250 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x 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.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x 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 the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OBa sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OB Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 6-1/8” Lateral A/C:
x There are no wells with CF < 1.0
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV and rotation (120+ RPM). Pump tandem sweeps if
needed
OBd SFD
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Drilling Procedure
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
17.14 Monitor the returned fluids carefully while displacing to brine.
15.19 BROOH with the drilling assembly to the 7” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 7” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
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Drilling Procedure
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
x Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
18.0 Run 4-1/2” Injection Liner
18.1 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:
x P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
18.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 12.6# W563 x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
18.3 Run 4-1/2” injection liner
x 4-1/2” liner will be floated to bottom for improved T&D. Liner will be isolated by float shoe
and float collar at the toe, closed NCS sleeves along liner length and the Airlock buoyancy
system at top of liner.
x Use Tenaris approved thread compound. Dope pin end only w/ paint brush. Wipe off
excess.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
x See data sheets on the next page for MU torque for the 4-1/2” liner connections.
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Drilling Procedure
18.4 Confirm with OE whether or not this is required. Ensure to run enough liner to provide for
setting the liner hanger at ~ 6500’ MD
x Confirm set depth with completion engineer.
x 3-5 joints of 7” will be ran under the liner hanger for the production packer. Confirm with
completion engineer.
18.5 Ensure hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
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Drilling Procedure
18.6 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.
18.7 M/U Baker SLZXP liner top packer to 4-1/2” liner.
18.8 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.
18.9 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x Fill drill pipe on the fly above the Airlock Bouyancy system. Monitor FL and if filling is
required due to losses/surging.
18.10 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.
18.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
18.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
18.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
18.14 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
18.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
18.16 Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
18.17 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
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.
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Drilling Procedure
18.18 Bleed DP pressure to 0 psi. 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.
18.19 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
18.20 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
18.21 PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
18.22 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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Drilling Procedure
19.0 Run Upper Completion/ Post Rig Work
19.1 RU to run 4-1/2”, 12.6#, L-80 VAMTOP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, VAMTOP x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
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Drilling Procedure
19.2 PU, MU and RH with the following 4-1/2” injection completion jewelry (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 1x XN Nipple
x 1x GLM
x 3x X Nipple
x 1x Production Packer
x XXX joints, 4-1/2”, 12.6#, L-80, VAMTOP
x X1 WLEG, set as close to 7” x 4-1/2” liner xo as possible
19.3 PU and MU the 4-1/2” tubing hanger.
19.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
19.5 Land the tubing hanger and RILDS. Lay down the landing joint.
19.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
19.7 NU the tubing head adapter and NU the tree.
19.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
19.9 Pull the plug off tool and BPV.
19.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel
freeze protect for both tubing and IA to 2,500’ MD.
19.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
19.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
i. Note this test must be witnessed by the AOGCC representative.
ii. Notify wells group coordinator prior to performing,
1. Contact number: 659-5102
2. pbwellsintegrity@hilcorp.com
19.13 Bleed both the IA and tubing to 0 psi.
19.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
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19.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
19.16 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
2. Fullbore
a. Shear hydraulic toe port
3. Coil
a. Shift injection sleeves open
4. Well Tie in
5. Put well on injection
a. AOGCC witnessed MIT-IA once injection is stable
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Drilling Procedure
20.0 Innovation Rig Diverter Schematic
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Drilling Procedure
21.0 Innovation Rig BOP Schematic
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Drilling Procedure
22.0 Wellhead Schematic
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23.0 Days Vs Depth
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24.0 Formation Tops & Information
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25.0 Anticipated Drilling Hazards
12-1/4” 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.
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:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
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.
H2S:
Treat every hole section as though it has the potential for H2S. PBU W-pad has a history of H2S on
wells in all reservoirs.
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Drilling Procedure
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.
Page 54
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. 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 > 300
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.
Cretaceous Over Pressure:
W-Pad does not have a history of over-pressure in the cretaceous interval (4500-5300’ TVD). However,
as a precaution ensure MW is above 9.0. Be prepared while drilling this interval.
H2S:
Treat every hole section as though it has the potential for H2S. PBU W-pad has a history of H2S on
wells in all reservoirs.
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.
Page 55
Prudhoe Bay West
W-241 SB Injector
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:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Gas Cut Mud
Gas cut mud as been seen on W pad, ensure sufficient MW is used during hole section. Ensure gas
detectors are always functioning. Watch swab effect.
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.
Casing Running
Casing running issue have been noted on W pad, gravels, stability wood chunks, etc. Watch casing run,
and ensure to condition hole prior to running casing, ex: backream trouble intervals.
8-1/2” Section specific A/C:
x There are no wells with a CF <1.0
Page 56
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
6-1/8” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. 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.
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:
Treat every hole section as though it has the potential for H2S. PBU W-pad has a history of H2S on
wells in all reservoirs.
4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 57
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
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” Lateral A/C:
x There are no wells with a CF <1.0
Page 58
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
26.0 Innovation Rig Layout
Page 59
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
27.0 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.
Page 60
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
28.0 Innovation Rig Choke Manifold Schematic
Page 61
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
29.0 Casing Design
Page 62
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
30.0 MASP
Page 63
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
Page 64
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 65
Prudhoe Bay West
W-241 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
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:
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
South(-)/North(+) (1500 usft/in)-9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0
West(-)/East(+) (1500 usft/in)
W-241 wp04 CP5
W-241 wp04 CP4
W-241 wp02 CP3
W-241 wp02 CP2
W-241 wp02 CP1
9 5/8" x 12 1/4"
7" x 8 1/2"
4 1/2" x 6 3/4"500125017502000225025002750300032503500375040004250450047505 0 0 04952W-241 wp05Start Dir 2º/100' : 250' MD, 250'TVD
Start Dir 3º/100' : 450' MD, 449.84'TVD
End Dir : 2007.68' MD, 1796.15' TVD
Start Dir 3º/100' : 6177.43' MD, 4440.38'TVD
End Dir : 7601.65' MD, 4979.23' TVD
Start Dir 2.5º/100' : 7751.65' MD, 4992.3'TVD
Start Dir 2.5º/100' : 10143.79' MD, 4997.3'TVD
End Dir : 10349.63' MD, 4997.13' TVD
Start Dir 2.5º/100' : 13871.22' MD, 4997.29'TVD
End Dir : 14665.52' MD, 4995.16' TVD
Start Dir 2.5º/100' : 15286.67' MD, 4983.47'TVD
Start Dir 2º/100' : 16258.73' MD, 4967.3'TVD
End Dir : 16631.69' MD, 4962.74' TVD
Total Depth : 17629.29' MD, 4952.3' TVD CASING DETAILS
TVD TVDSS MD Size Name
2656.89 2579.59 3365.00 9-5/8 9 5/8" x 12 1/4"
5001.08 4923.78 7960.00 7 7" x 8 1/2"
4952.30 4875.00 17629.05 4-1/2 4 1/2" x 6 3/4"
Project: Prudhoe Bay
Site: W
Well: Plan: W-241
Wellbore: W-241
Plan: W-241 wp05
WELL DETAILS: Plan: W-241
50.80
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
5959550.890 611789.860 70° 17' 54.4127 N 149° 5' 40.8074 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: W-241, True North
Vertical (TVD) Reference: W-241 asbuilt rkb @ 77.30usft
Measured Depth Reference:W-241 asbuilt rkb @ 77.30usft
Calculation Method:Minimum Curvature
0750150022503000375045005250True Vertical Depth (1500 usft/in)0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250Vertical Section at 320.00° (1500 usft/in)W-241 wp02 CP1W-241 wp02 CP2W-241 wp02 CP3W-241 wp04 CP4W-241 wp04 CP59 5/8" x 12 1/4"7" x 8 1/2"4 1/2" x 6 3/4"5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750017629W-241 wp05Start Dir 2º/100' : 250' MD, 250'TVDStart Dir 3º/100' : 450' MD, 449.84'TVDEnd Dir : 2007.68' MD, 1796.15' TVDStart Dir 3º/100' : 6177.43' MD, 4440.38'TVDEnd Dir : 7601.65' MD, 4979.23' TVDStart Dir 2.5º/100' : 7751.65' MD, 4992.3'TVDEnd Dir : 7957.08' MD, 5001.08' TVDStart Dir 2.5º/100' : 10143.79' MD, 4997.3'TVDEnd Dir : 10349.63' MD, 4997.13' TVDStart Dir 2.5º/100' : 13871.22' MD, 4997.29'TVDEnd Dir : 14665.52' MD, 4995.16' TVDStart Dir 2.5º/100' : 15286.67' MD, 4983.47'TVDStart Dir 2º/100' : 16258.73' MD, 4967.3'TVDEnd Dir : 16631.69' MD, 4962.74' TVDTotal Depth : 17629.29' MD, 4952.3' TVDBPRFSV3SV1Ugnu 4AUG3Ugnu MBNBOAOBd Hilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: W-24150.80+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005959550.890611789.860 70° 17' 54.4127 N 149° 5' 40.8074 WSURVEY PROGRAMDate: 2022-10-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 500.00 W-241 wp05 (W-241) GYD_Quest GWD500.00 3365.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag3365.00 7960.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag7960.00 17629.29 W-241 wp05 (W-241) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1922.30 1845.00 2206.61 BPRF2527.30 2450.00 3160.65 SV33029.30 2952.00 3952.27 SV13411.30 3334.00 4554.65 Ugnu 4A3757.30 3680.00 5100.27 UG34537.30 4460.00 6336.26 Ugnu MB4704.30 4627.00 6649.50 NB4810.30 4733.00 6894.67 OA4998.30 4921.00 7839.71 OBd REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: W-241, True NorthVertical (TVD) Reference:W-241 asbuilt rkb @ 77.30usftMeasured Depth Reference:W-241 asbuilt rkb @ 77.30usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:WWell:Plan: W-241Wellbore:W-241Design:W-241 wp05CASING DETAILSTVD TVDSS MD SizeName2656.89 2579.59 3365.00 9-5/8 9 5/8" x 12 1/4"5001.08 4923.78 7960.00 7 7" x 8 1/2"4952.30 4875.00 17629.05 4-1/2 4 1/2" x 6 3/4"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 250' MD, 250'TVD3 450.00 4.00 315.00 449.84 4.93 -4.93 2.00 315.00 6.95 Start Dir 3º/100' : 450' MD, 449.84'TVD4 2007.68 50.64 303.26 1796.15 395.53 -579.10 3.00 -12.48 675.23 End Dir : 2007.68' MD, 1796.15' TVD5 6177.43 50.64 303.26 4440.38 2163.77 -3275.06 0.00 0.00 3762.71 Start Dir 3º/100' : 6177.43' MD, 4440.38'TVD6 7601.65 85.00 331.38 4979.23 3133.85 -4114.54 3.00 43.79 5045.44 End Dir : 7601.65' MD, 4979.23' TVD7 7751.65 85.00 331.38 4992.30 3265.02 -4186.12 0.00 0.00 5191.93 W-241 wp02 CP1 Start Dir 2.5º/100' : 7751.65' MD, 4992.3'TVD8 7957.08 90.10 330.77 5001.08 3444.59 -4285.36 2.50 -6.87 5393.29 End Dir : 7957.08' MD, 5001.08' TVD9 10143.79 90.10 330.77 4997.30 5352.79 -5353.29 0.00 0.00 7541.50 W-241 wp02 CP2 Start Dir 2.5º/100' : 10143.79' MD, 4997.3'TVD10 10349.63 90.00335.91 4997.13 5536.68 -5445.62 2.50 91.13 7741.72 End Dir : 10349.63' MD, 4997.13' TVD11 13871.22 90.00335.91 4997.29 8751.59 -6882.97 0.00 0.00 11128.39 Start Dir 2.5º/100' : 13871.22' MD, 4997.29'TVD12 14438.47 90.00 321.73 4997.30 9235.66 -7175.89 2.50 -89.99 11687.50 W-241 wp02 CP313 14665.52 91.08 327.30 4995.16 9420.46 -7307.63 2.50 79.03 11913.75 End Dir : 14665.52' MD, 4995.16' TVD14 15286.67 91.08 327.30 4983.47 9943.09 -7643.11 0.00 0.0012529.75 Start Dir 2.5º/100' : 15286.67' MD, 4983.47'TVD15 16258.73 90.80 303.00 4967.30 10627.01 -8323.42 2.50 -90.4413490.95 W-241 wp04 CP4 Start Dir 2º/100' : 16258.73' MD, 4967.3'TVD16 16631.69 90.60 295.54 4962.74 10809.22 -8648.51 2.00 -91.49 13839.50 End Dir : 16631.69' MD, 4962.74' TVD17 17629.29 90.60 295.54 4952.30 11239.35 -9548.55 0.00 0.00 14747.53 W-241 wp04 CP5 Total Depth : 17629.29' MD, 4952.3' TVD
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0.001.002.003.004.00Separation Factor0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800Measured Depth (400 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: W-241 NAD 1927 (NADCON CONUS)Alaska Zone 0450.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959550.890611789.86070° 17' 54.4127 N149° 5' 40.8074 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: W-241, True NorthVertical (TVD) Reference: W-241 asbuilt rkb @ 77.30usftMeasured Depth Reference:W-241 asbuilt rkb @ 77.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-10-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 W-241 wp05 (W-241) GYD_Quest GWD500.00 3365.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag3365.00 7960.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag7960.00 17629.29 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800Measured Depth (400 usft/in)W-31W-32W-211W-29W-30GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 17629.29Project: Prudhoe BaySite: WWell: Plan: W-241Wellbore: W-241Plan: W-241 wp05Ladder / S.F. Plots1 of 3CASING DETAILSTVD TVDSS MD Size Name2656.89 2579.59 3365.00 9-5/8 9 5/8" x 12 1/4"5001.08 4923.78 7960.00 7 7" x 8 1/2"4952.30 4875.00 17629.05 4-1/2 4 1/2" x 6 3/4"
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0.001.002.003.004.00Separation Factor3300 3575 3850 4125 4400 4675 4950 5225 5500 5775 6050 6325 6600 6875 7150 7425 7700 7975 8250Measured Depth (550 usft/in)W-26B wp03No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: W-241 NAD 1927 (NADCON CONUS)Alaska Zone 0450.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959550.890611789.86070° 17' 54.4127 N149° 5' 40.8074 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: W-241, True NorthVertical (TVD) Reference: W-241 asbuilt rkb @ 77.30usftMeasured Depth Reference:W-241 asbuilt rkb @ 77.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-10-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 W-241 wp05 (W-241) GYD_Quest GWD500.00 3365.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag3365.00 7960.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag7960.00 17629.29 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)3300 3575 3850 4125 4400 4675 4950 5225 5500 5775 6050 6325 6600 6875 7150 7425 7700 7975 8250Measured Depth (550 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 17629.29Project: Prudhoe BaySite: WWell: Plan: W-241Wellbore: W-241Plan: W-241 wp05Ladder / S.F. Plots2 of 3CASING DETAILSTVD TVDSS MD Size Name2656.89 2579.59 3365.00 9-5/8 9 5/8" x 12 1/4"5001.08 4923.78 7960.00 7 7" x 8 1/2"4952.30 4875.00 17629.05 4-1/2 4 1/2" x 6 3/4"
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0.001.002.003.004.00Separation Factor8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250 21000 21750Measured Depth (1500 usft/in)W-26B wp03Z-220Z-222No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: W-241 NAD 1927 (NADCON CONUS)Alaska Zone 0450.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959550.890611789.86070° 17' 54.4127 N149° 5' 40.8074 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: W-241, True NorthVertical (TVD) Reference: W-241 asbuilt rkb @ 77.30usftMeasured Depth Reference:W-241 asbuilt rkb @ 77.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-10-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 W-241 wp05 (W-241) GYD_Quest GWD500.00 3365.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag3365.00 7960.00 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag7960.00 17629.29 W-241 wp05 (W-241) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250 21000 21750Measured Depth (1500 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 17629.29Project: Prudhoe BaySite: WWell: Plan: W-241Wellbore: W-241Plan: W-241 wp05Ladder / S.F. Plots3 of 3CASING DETAILSTVD TVDSS MD Size Name2656.89 2579.59 3365.00 9-5/8 9 5/8" x 12 1/4"5001.08 4923.78 7960.00 7 7" x 8 1/2"4952.30 4875.00 17629.05 4-1/2 4 1/2" x 6 3/4"
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN ORIN W-241Initial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2221540PRUDHOE BAY, SCHRADER BLUF OIL - 640135NA1 Permit fee attachedYes Surface Location lies within ADL0028263; Top Productive Interval lies in ADL0028262; TD lies in ADL0047450.2 Lease number appropriateYes3 Unique well name and numberYes PBU Schrader Bluff, Orion Development Area – 640135, governed by CO 505B.0044 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Governed by AIO 26B, issued May 4, 2010; corrected February 3, 202114 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sYes Z-116, Z-220, Z-222, Z-228, Z-22915 All wells within 1/4 mile area of review identified (For service well only)No Well will not be pre-produced16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 Driven to 110'18 Conductor string providedYes 9-5/8" surface casing with shoe set below the SV319 Surface casing protects all known USDWsYes Fully cemented surface casing20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes 7" intermediate shoe set horizontally in the reservoir. TOC cement to be above all hydrocarbons22 CMT will cover all known productive horizonsYes 9-5/8" 47# L-80 across the permafrost, 9-5/8" 40# L-80 below23 Casing designs adequate for C, T, B & permafrostYes Innovation has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grass roots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no close approaches.26 Adequate wellbore separation proposedYes 16" diverter below full BOPE27 If diverter required, does it meet regulationsYes All fluids overbalanced to pore pressure28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram, 1 flow cross tested to 3000 psi29 BOPEs, do they meet regulationYes 5M stack30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes PBU W pad is an H2S pad. Monitoring will be required33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No Measures required. W-Pad has a history of H2S. Rig has sensors & alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Normal presures evpected. MPD will be available to mitigate abnormal pressures.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate12/28/2022ApprMGRDate12/22/2022ApprSFDDate12/28/2022AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 12/30/2022
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 nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
PBU W-241
Schrader Bluff Oil Pool, Orion
Development Area
222-154
Prudhoe Bay
