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Alaska Oil and Gas Conservation Commission
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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 8/7/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240807
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
END 2-72 50029237810000 224016 6/27/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON RBT
END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON TEMP
END 2-74 50029237850000 224024 7/20/2024 HALLIBURTON MFC
MPU B-24 50029226420000 196009 7/16/2024 HALLIBURTON MFC
MPU E-19A 50029227460100 224010 6/22/2024 HALLIBURTON COILFLAG
NS-10 50029229850000 200182 7/18/2024 HALLIBURTON MFC
NS-10 50029229850000 200182 7/18/2024 HALLIBURTON TEMP
NS-32 50029231790000 203158 7/16/2024 HALLIBURTON MFC
NS-32 50029231790000 203158 7/15/2024 HALLIBURTON TEMP
PBU H-13A 50029205590100 209044 7/23/2024 HALLIBURTON RBT
PBU L-246 50029237650000 223078 7/23/2024 HALLIBURTON IPROF
PBU R-26B 50029215470100 210025 7/5/2024 HALLIBURTON RBT
PBU R-36 50029225220000 194144 6/21/2024 HALLIBURTON RBT
PBU V-216 50029232160000 204130 7/11/2024 HALLIBURTON IPROF
PBU V-217 50029233340000 206162 7/11/2024 HALLIBURTON IPROF
Please include current contact information if different from above.
T39365
T39365
T39365
T39366
T39367
T39368
T39369
T39369
T39370
T39370
T39371
T39372
T39373
T39374
T39375
T39376
PBU L-246 50029237650000 223078 7/23/2024 HALLIBURTON IPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.08.07 13:19:30 -08'00'
Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
07/16/2024
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 07/16/2024.
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 07/16/2024.
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
Digitally signed by Oliver Sternicki
DN: cn=Oliver Sternicki, c=US, o=Hilcorp North Slope
LLC, ou=PBU, email=oliver.sternicki@hilcorp.com
Date: 2024.07.16 13:47:34 -08'00'
Hilcorp North Slope LLC.
Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor
Top-off
Report of Sundry Operations (10-404)
7/16/2024
Well Name PTD #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
date
L-246 223078 500292376500 11 3/23/2024
L-247 223081 500292376600 14 3/23/2024
L-252 223095 500292376800 17 3/23/2024
L-295 223115 500292377400 11 3/23/2024
RBDMS JSB 071924
L-246 223078 500292376500 11 3/23/2024
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230780 Type Inj N Tubing 0 0 0 0 Type Test P
Packer TVD 4364 BBL Pump 0.0 IA 0 0 0 0 Interval I
Test psi 3500 BBL Return 0.0 OA 0 0 0 0 Result F
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230780 Type Inj N Tubing 1000 175 175 175 Type Test P
Packer TVD 4364 BBL Pump 2.1 IA 0 3691 3628 3619 Interval I
Test psi 3500 BBL Return 3.8 OA 0 0 0 0 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:Mud pump Limiter kicked in too soon and we needed to increase our Limiter to get to our initial starting point.
Well was underbalanced and bbls returned were seen to be higher than the intial pumped. Witness waived by Guy Cook.
Notes:
Notes:
Hilcorp Alaska LLC
Prudhoe Bay / West Side / Z Pad
Shane Barber
09/26/23
Notes:Packer set early at 2,343psi and instantly bled off. Troubleshooted with no effect. Moved on to IA MIT and found packer to be set and holding well. Retried the TBG test and
tubing will not hold pressure. Suspect Ball and rod or RHC to have issues. Engineer instructed that we install a BPV and RDMO. Witness waived by Guy Cook.
Notes:
Notes:
Notes:
L-246
L-246
Form 10-426 (Revised 01/2017)2023-0925_MIT_PBU_L-246_2tests
J. Regg; 3/8/2024
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, January 18, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Adam Earl
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
L-246
PRUDHOE BAY UN ORIN L-246
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 01/18/2024
L-246
50-029-23765-00-00
223-078-0
W
SPT
4365
2230780 1500
70 70 71 71
110 292 284 281
INITAL P
Adam Earl
12/5/2023
Initial MIT-IA
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 L-246
Inspection Date:
Tubing
OA
Packer Depth
336 1712 1662 1657IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitAGE231206101738
BBL Pumped:0.9 BBL Returned:0.7
Thursday, January 18, 2024 Page 1 of 1
7. Property Designation (Lease Number):
1. Operations
Performed:
2. Operator Name:
3. Address:
4. Well Class Before Work:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
Susp Well Insp
Install Whipstock
Mod Artificial Lift Perforate New Pool
Perforate
Plug Perforations
Coiled Tubing Ops
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well Other:
Change Approved Program
Operations shutdown
11. Present Well Condition Summary:
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
16. Well Status after work:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
OIL GAS
WINJ WAG GINJ
WDSPL
GSTOR Suspended SPLUG
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
PBU L-246
Convert to Injector
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
223-078
50-029-23765-00-00
20353
Conductor
Surface
Intermediate
Production
Liner
3822
80
5930
5186
13696
18893
20"
9-5/8"
7"
7" x 4-1/2"
4245
26 - 106
25 - 5955
24 - 5210
5199 - 18895
26 - 106
25 - 4496
24 - 4339
4334 - 4245
None
4760 / 3090
5410
5410 / 7500
None
6870 / 5750
7240
7240 / 8430
6220 - 18863
4-1/2" 12.6# L-80 22 - 5857
4492 - 4249
Structural
4-1/2" HES TNT Perm Packer 5270, 4365
5270
4365
Torin Roschinger
Operations Manager
Tyson Shriver
tyson.shriver@hilcorp.com
907-564-4542
PRUDHOE BAY, Schrader Bluff Oil, Orion Development Area
Total Depth
Effective Depth
measured
true vertical
feet
feet
feet
feet
measured
true vertical
measured
measured
feet
feet
feet
feet
measured
true vertical
Plugs
Junk
Packer
Measured depth
True Vertical depth
feet
feet
Perforation depth
Tubing (size, grade, measured and true vertical depth)
Packers and SSSV
(type, measured and true vertical depth)
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.Representative Daily Average Production or Injection Data
Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure
Prior to well operation:
Subsequent to operation:
15. Well Class after work:
Exploratory Development Service StratigraphicDaily Report of Well Operations
Copies of Logs and Surveys Run
Electronic Fracture Stimulation Data
Sundry Number or N/A if C.O. Exempt:
ADL 028239 & 047449
22 - 4493
N/A
N/A
2260 690
5840
1750
450
350
10
323-590
13b. Pools active after work:Schrader Bluff Oil, Orion Development Area
No SSSV Installed
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
Sr Pet Eng: Sr Pet Geo:
Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Sr Res Eng:
Due Within 30 days of Operations
By Grace Christianson at 11:53 am, Dec 15, 2023
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.12.15 06:34:14 -09'00'
Torin
Roschinger
(4662)
DSR-12/18/23
RBDMS JSB 122623
WCB 5-10-2024
ACTIVITY DATE SUMMARY
11/23/2023
T/I/O= 700/125/0 (CONVERSION-PERMANENT) Freeze protected TBG with 2 bbls
of 60/40 and 40 bbls of Crude. Freeze protected IA wih 2 bbls of 60/40 and 91 bbls of
Crude. Pad Op notified of well status upon departure.
Valve Positions - SV/WV/SSV= Closed, MV= Open, IA/OA= OTG
FWHPs= 1100/900/0
11/23/2023 Assist SL with well conversion
11/23/2023
***WELL S/I ON ARRIVAL***(Conversion permanent)
RU POLLARD SLU #60
***CONTINUED ON 11/24/23 WSR***
11/24/2023
***CONTINUED FROM 11/23/23 WSR***(Conversion permanent)
RAN 3.80" GAUGE RING TO JETPUMP AT 5,208' MD
PULLED JETPUMP & GAUGES
LRS LOADED IA w/ CISW & DSL FP
SHIFTED SSD CLOSED w/ 42BO
LRS CONDUCTED MIT-IA TO 2500PSI
***WELL S/I ON DEPARTURE***
11/24/2023
T/I/O=380/31/0 Assist SL with well conversion MIT IA to 2500 PSI (2750 max
applied) PASSED Pump 46 bbls inhibited brine and 53 bbls amb dsl for FP down IA.
Pressured IA with 1.6 bbls dsl to reach test pressure. IA lost 92 psi in 1st 15 min and
25 psi in 2nd 15 min for a total loss of 117 psi in 30 min test. bleed back IAP
11/28/2023
T/I/O = VAC/510/260. Temp = 122°. Assist Ops w/ POI. IA & OA FL @ surface.
Bled OAP as needed for POI (0.1 bbl). Released by Ops. Final WHPs =
VAC/470/20.
SV = C. WV, SSV, MV = O. IA, OA = OTG. 06:00
12/3/2023
T/I/O = 1680/340/100. Temp = 126°. IA FL (pre-AOGCC MIT). On PWI. IA FL @
surface.
SV = C. WV, SSV, MV = O. IA & OA = OTG. 14:30
12/5/2023
T/I/O= 70/336/111 Temp= 128*F. LRS 72 (AOGCC Adam Earl ) MIT-IA to 1500 psi
PASSED at 1657 psi (1700 psi max applied). IA lost 50 psi during the first 15 minutes
and 5 psi during the second 15 minutes. IA lost 55 psi during the 30 minute test.
Pumped 0.9 bbls of 92*F diesel to achieve test pressure. Ble back 0.7 bbls to Final
T/I/O= 71/338/112.
Daily Report of Well Operations
PBU L-246
LRS CONDUCTED MIT-IA TO 2500PSI
MIT IA to 2500 PSI (2750 max
applied) PASSED
LRS 72 (AOGCC Adam Earl ) MIT-IA to 1500 psi(
PASSED at 1657 psi (1700 psi max applied
PULLED JETPUMP & GAUGES
1
Regg, James B (OGC)
From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent:Friday, November 3, 2023 5:03 PM
To:Brooks, Phoebe L (OGC)
Cc:Wallace, Chris D (OGC); Regg, James B (OGC); PB Wells Integrity; Oliver Sternicki; Tyson Shriver
Subject:RE: Hilcorp (PBU) September 2023 MIT Forms
Attachments:MIT PBU L-246 09-25-23.xlsx
All,
I apologize for the late submission, but when reviewing our records, it appears the rig MIT for L‐246 that was conducted
on 09‐25‐23 was not included in our original submission. The well has not been on injecƟon as it was approved for pre‐
producƟon.
Please let me know if you have any quesƟons or concerns.
Andy Ogg
Hilcorp Alaska LLC
Field Well Integrity
andrew.ogg@hilcorp.com
P: (907) 659‐5102
M: (307)399‐3816
From: PB Wells Integrity
Sent: Sunday, October 1, 2023 12:09 PM
To: phoebe.brooks@alaska.gov
Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; jim.regg@alaska.gov
Subject: Hilcorp (PBU) September 2023 MIT Forms
Ms. Brooks,
AƩached are the completed AOGCC MIT forms for the tests completed in September 2023 by Hilcorp North Slope, LLC.
Well: PTD: Notes:
04‐26 1853140 MIT‐T for P&A Sundry 323‐173
09‐22 1831730 2‐Year MIT‐IA per AA AIO 4E.041
B‐17 1790280 4‐Year MIT‐IA
K‐20 2080490 MIT‐T & CMIT‐TxIA Per Sundry 321‐124
L5‐29 1870450 Rig MIT‐T / MIT‐IA & Post iniƟal injecƟon MIT‐IA
NGI‐
13A
2071140 4‐Year MIT‐IA
P‐13 1901110 4‐Year MIT‐IA
S‐41 2101010 2‐Year MIT‐IA per AA AIO 3C.004
X‐33 1961440 2‐Year MIT‐IA per AA AIO 4F.007
Z‐234 2230650 Post iniƟal injecƟon MIT‐IA
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 L-246PTD 2230780
2
Z‐235 2330550 Post iniƟal injecƟon MIT‐IA
Please respond with quesƟons 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.
7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in thes pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd?Yes No
Subsequent Form Required:
Approved By:Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU L-246
Convert to Injector
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK
99503
223-078
50-029-23765-00-00
ADL 028239 & 047449
20353
Conductor
Surface
Intermediate
Production
Liner
3822
80
5930
5186
13696
18893
20"
9-5/8"
7"
7" x 4-1/2"
4245
26 - 106
25 - 5955
24 - 5210
5199 - 18895
26 - 106
25 - 4496
24 - 4339
4334 - 4245
None
4760 / 3090
5410
5410 / 7500
None
6870 / 5750
7240
7240 / 8430
6220 - 18863 4-1/2" 12.6# L-80 22 - 58574492 - 4249
Structural
4-1/2" HES TNT Perm Packer
No SSSV Installed
5270, 4365
No SSSV Installed
Date:
Torin Roschinger
Operations Manager
Tyson Shriver
tyson.shriver@hilcorp.com
907-564-4542
PRUDHOE BAY
12/10/2023
Current Pools:
Schrader Bluff Oil, Orion Development Area
Proposed Pools:
Schrader Bluff Oil, Orion Development Area
Suspension Expiration Date:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov
1522
By Grace Christianson at 8:02 am, Nov 01, 2023
Digitally signed by Aras
Worthington (4643)
DN: cn=Aras Worthington (4643)
Date: 2023.10.31 12:40:37 -
08'00'
Aras
Worthington
(4643)
323-590
SFD 11/1/2023
10-404
DSR-11/2/23MGR01NOV23
* State witnessed MIT-IA to 3500 psi after 10 days of stabilized injection.
*&:
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.11.03
10:43:00 -08'00'11/03/23
RBDMS JSB 110723
Pre-Produced Injector Conversion Sundry
Well: PBU L-246
PTD #223-078
Well Name:L-246 API Number:50-029-23765-00
Current Status:Operable Pre-Produced WAG Injector Revision:0
Estimated Start Date:12/1/2023 Rig:SL/FB
Sundry #:Date Reg. Approval Rec’vd:
Regulatory Contact:Abbie Barker
First Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M)
Second Call Engineer:Marshall Brown (601)-613-0173 (M)
Current Bottom Hole Pressure:1,970 psi @ 4,475’ TVD Regional pressure
Max. Anticipated Surface Pressure:1,522 psi (Based on 0.1 psi/ft. gas gradient)
Last SI WHP:300 psi (Taken on 10/6/23)
Min ID:3.813” X-nip @ 2,803’ MD
Max Angle:115 Deg @ 19,542’ MD
Brief Well Summary:
PBU L-246 is a grassroots pre-produced WAG injector that was drilled in the Schrader Bluff OBd sand and
completed October 2023. The well started pre-production October 11th and will be converted to full time WAG
injection once the I-rig moves off PBU L-252 - ~December 1
st. L-246 is part of a multi-well program targeting the
Schrader Bluff sand on PBU L-pad. This injector will specifically support recently drilled producer PBU L-247.
Variance to 20 AAC 25.412 (b) was approved in PTD #223-078 for packer placement >200’ above top of
perforations.
Objective:
x Pull jet pump and convertwell to full time WAG injection.
Slickline w/ Fullbore Assist:
1. Pull jet pump from SSD at 5,208’ MD.
2. Load IA with corrosion inhibited brine and diesel freeze protect.
3. Close SSD.
DHD
1. Perform online AOGCC MIT-IA.
Attachments:
x Map & AOR
x Current Wellbore Schematic
x Proposed Wellbore Schematic
x Sundry Change Form
grassroots pre-produced WAG injector t
convertwell to full time WAG injection.
Pre-Produced Injector Conversion Sundry
Well: PBU L-246
PTD #223-078
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
PBU L-112 202-229 50-029-23129-00-00 Producer 6438' 4496' 4675' 3537' Closed
7" Casing cement with
143bbls of 12ppg lead
cement followed by 32 bbls
15.8ppg tail cement. Full
returns throughout job.
Estimated TOC ~4675'
PBU L-114A 205-112 50-029-23032-01-00 Producer 5635' 4450' 2650' 2610 Closed
5.5" TOC logged at 2650'
with USIT on 11/3/08.
Kuparuk Producer, not open
to Schrader Bluff
Area of Review PBU L-246
Okay SFD 11/1/2023
Pre-Produced Injector Conversion Sundry
Well: PBU L-246
PTD #223-078
Current WBD:
Pre-Produced Injector Conversion Sundry
Well: PBU L-246
PTD #223-078
Proposed WBD:
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By Grace Christianson at 1:25 pm, Oct 31, 2023
Completed
9/26/2023
JSB
RBDMS JSB 110723
GDSR-11/16/23SFD 12/12/2025
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.10.30 16:00:10 -08'00'
Torin
Roschinger
(4662)Drilling Manager
10/30/23
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU L-246 Date:9/9/2023
Csg Size/Wt/Grade:9 5/8 47 & 40 #L-80 Supervisor:James Lott
Csg Setting Depth:5955 TMD 4495 TVD
Mud Weight:9.2 ppg LOT / FIT Press =690 psi
LOT / FIT =12.15 ppg Hole Depth =5984 md
Fluid Pumped=1.7 Bbls Volume Back =1.5 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
->00 ->028
->212 ->241
->430 ->480
->670 ->6123
->8130 ->8181
->10 195 ->10 255
->12 265 ->12 334
->14 330 ->14 382
->16 402 ->16 447
->18 465 ->18 511
->20 540 ->20 571
->22 590 ->45 1392
->24 650 ->65 2140
->26 690 ->80 2750
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0690 ->02750
->1665 ->52735
->2645 ->10 2727
->3632 ->15 2724
->4625 ->20 2721
->5614 ->25 2718
->6609 ->30 2715
->7598 ->
->8587 ->
->9578 ->
->10 569 ->
-> ->
-> ->
-> ->
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Strokes (# of)
LOT / FIT DATA CASING TEST DATA
690665645632625614609598587578569
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LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
8/31/2023 Spot matt boards and prep L-246 for sub. Install diverter tee on 20" conductor. Move pipe, gen and mud mods to L-Pad arriving at 19:30. Install tow arm and back
tires on sub. Transport sub & cattle chute to L Pad arriving at 22:30. Cont setting matts and start spotting sub over L-246. Cont spotting & leveling sub. Set cattle
chute, pipe shed, mud and gen mods. Trucks released at 05:30. PJSM R/U steam, H2O & air lines. Work on inner connects. Install 4" conductor valves. Start
working on rig acceptance check list.
9/1/2023 PJSM R/U steam, H2O & air lines around rig. Install all inner connects. Bring on steam and air around rig. Gen power at 06:30. Install flow line, choke, kill & mud
lines. Scope up derrick and bridal down. C/O wash pipe on TD. Set enviro vac and break shack. C/O suction valve & seat on Pod #4 MP #2. R/D squeeze manifold.
Set cutting box and berm. Cont working on rig acceptance check list. Weld lower suction handle on Pit #3. Install over flow plates on shaker beds. Remove studs on
RCD head and unsecure stack. R/D 4" MPD hard lines. R/D RCD head. Install trip nipple flange on stack. Cont working on rig acceptance check list. PJSM Install
Diverter tee. N/U BOPE. Install knife valve. Crane on location 17:00 installing 16" diverter sections, release 18:00. Install koomey lines. Obtain RKB. Install master
bushings, trip nipple and secure stack. SIMOPS Seal weld under belly Ext under shakers. Weld hole in cutting box. Dressed shakers W/ 120 screens. Plumb jet
line in Pit #2. Complete derrick inspection. Install mouse hole in rotary table. Process 5" HWDP. Install 5" Hydraulic elevators. Rig Accepted at 20:00. PJSM P/U
M/U 5" 19.4# S-135 D.P. and rack back in derrick 80 stand (160 Jnts). Drift 3.125" OD. SIMOPS Take on 580 bbls 8.8 ppg Spud Mud to pits. PJSM Cont P/U M/U
5" D.P. Load 64 jnts and process in pipe shed. P/U M/U 32 stands (64 jnts) 5" D.P. & 5" HWDP & Jar in derrick. Drift 3.125" OD & 2.75" OD. PJSM L/D Mouse
hole. Install split bushings. L/D Thread protectors and prep for cut and slip drilling lines. PJSM M/U 5" HWDP stand to TD and set in slips. Move PH8 to home. Pull
covers and draw works.
9/2/2023 Cut and slip drilling line (62'). Mark line, hang blocks w/ TDS M/U to 1 jt 5" HWDP. Install safety clamp on DP. Slip on new drilling line. Install deadman. Unhang
blocks and recalibrate floor and crown saver. Svc traveling equipment. Prep rig floor for handling BHA. Mobilize BHA components to rig floor. M/U 12-1/4" K5M633
Hybrid bit T/ 1.5 8" Mtr (non port float), Bottleneck XO, 1x std 5" NC50 HWDP. Diverter Test - 3025 psi initial, 1950 psi drawdown, 14 sec 200 psi increase, 46 sec
full charge. 2258 psi 6 bottle Nitrogen avg. 7 sec open knife valve, 11 sec close 13-5/8" annular. Test on 5" pipe. Test gas alarms 5/10 ppm H2S, 20/40% LEL. Test
PVT system (good). Witness waived by Guy Cook. Flood mud lines and conductor. P/T mud lines to 3k psi (test good). No leaks observed on surface equipment.
Tag @ 105' MD. Drill 12-1/4" surface hole rathole F/ 105' - T/ 220' MD using minimum parameters to minimize washout at base of conductor. 375 gpm, 380 psi, 30
rpm, 1.7k tq on/off, P/U 45k, S/O 45k. Jet flowine every 5-10' of hole as needed. Heavy pea gravel and sand. POOH F/ 220' to surface w/ no pump or rot. Lost 47
bbls outside of conductor. Inspect 12-1/4" bit (no damage). M/U LWD/MWD smart tools with Gyrodata. Perform RFO. M/U BHA #1 - Bit, Mtr, MWD/LWD. Shallow
pulse test MWD. Slide/Drill 12.25" Surface F/ 220' to 469' MD (469' TVD) Total 249' (AROP 41.5) 450 GPM 820 psi on, 725 psi off 30 RPM, TRQ on 1.5k, TRQ off
1k, WOB 2-6k. ECD 9.68. F/O 55% Max Gas 0u. MW in/out 8.8/8.9. P/U 61k, SLK 56k, ROT 58k. KOP 283' MD. Slide build 3/100. Jet flow line & pump through
bleeder. Heavy pea gravel at shakers till ~440' MD, turning to heavy sand & clay. No losses. Slide/Drill 12.25" Surface F/ 469' to 1,070' MD (1,043' TVD) Total 601'
(AROP 100.2') 450 GPM 1015 psi on, 829 psi off 40 RPM, TRQ on 2-4k, TRQ off 2-3k, WOB 6-12k. ECD 9.58. F/O 55% Max Gas 0u. MW in/out 8.85/8.9. P/U
73k, SLK 69k, ROT 71k. Slide build 4/100. At 715' MD encountered dynamic losses 30-50 bph ECD's 9.56 to 9.78.Jet flow line & pump through bleeder. Distance
to WP05: 4.67', 4.66' Low 0.33' Right. SLD Hrs: 4.25. ROT Hrs: 3.0. Daily disposal G&I: 171 bbls Total 171 bbls. Daily disposal MPU G&I: 57 bbls Total 57 bbls.
Daily H2O Lake 2: 200 bbls Total 200 bbls. Daily loss: 47 bbls. Total surface loss: 47 bbls.
9/3/2023 Slide/Drill 12.25" Surface F/ 1070' to 1859' MD (1691' TVD) Total 789' (AROP 131.5') 500 GPM 1415 psi on, 1230 psi off 40 RPM, TRQ on 4-6k, TRQ off 3-4k,
WOB 6-12k. ECD 10.85. F/O 56%, Max Gas 79u. MW in/out 9.3/9.4. P/U 86k, SLK 71k, ROT 79k. Last Gyro survey at 1186' MD. End 4/100 build at 1,237' MD.
Start 34.06 deg inc 264.38 deg azi, slide as needed to maintain tangent. Jet flowline and l through bleeder as needed. Encountered Hydrate prior to BPRF 1922'
MD 1744' TVD adjust flow rates as needed. Slide/Drill 12.25" Surface F/ 1,859' to 2,610 MD (2,316' TVD) Total 751' (AROP 125.1') 450 GPM 1202 psi on, 1078
psi off 40-80 RPM, TRQ on 5-6k, TRQ off 5k, WOB 8-10k. ECD 10.77. F/O 56% Max Gas 3146u. MW in/out 9.6/9.65. P/U 100k, SLK 80k, ROT 86k. Slide as
needed for tangent. Jet as needed. SIMOPS process 9.625" Csg. Slide/Drill 12.25" Surface F/ 2,610 to 3,419 MD (2,972' TVD) Total 809' (AROP 134.8') 475 GPM
1535 psi on, 1355 psi off 80 RPM, TRQ on 7-8k, TRQ off 6.5-7k, WOB 8-12k. ECD 11.1. F/O 53% Max Gas 1,914u. MW in/out 9.55/9.7. P/U 119k, SLK 87k, ROT
103k. Slide as needed for tangent. Jet as needed. Slide/Drill 12.25" Surface F/ 3,419 to 3,940 MD (3,415' TVD) Total 521' (AROP 86.') 500 GPM 1568 psi on, 1495
psi off 80 RPM, TRQ on 8-11k, TRQ off 9-11k, WOB 6-12k. ECD 10.82. F/O 56% Max Gas 757u. MW in/out 9.4/9.5. P/U 128k, SLK 88k, ROT 106k. Slide as
needed for tangent. Jet as needed. Ream 60'. Distance to WP05: 6.01', 5.49' High 2.43' Left. SLD Hrs: 4.24. ROT Hrs: 10.69. Daily disposal G&I: 1026 bbls Total
1197 bbls. Daily disposal MPU G&I: 57 bbls Total 114 bbls. Daily H2O Lake 2: 1150 bbls Total 1930 bbls. Daily loss: 30 bbls. Total surface loss: 77 bbls.
9/4/2023 Slide/Drill 12.25" Surface F/ 3940' - T/ 4465' MD (3847' TVD) Total 525' (AROP 88.') 550 GPM, 1815 psi on, 1720 psi off, 80 RPM, TRQ on 8-11k, TRQ off 9-11k,
WOB 6-12k. ECD 10.26. F/O 57%, Max Gas 546u. MW in/out 9.4/9.5. P/U 128k, S/O 93k, ROT 140k. Slide as needed for tangent. Jet as needed. Slide/Drill 12.25"
Surface F/ 4465' - T/ 4965' MD (4214' TVD) Total 500' (AROP 83.') 550 GPM, 1885 psi on, 1710 psi off, 80 RPM, TRQ on 11.5k, TRQ off 10k, WOB 6-25k. ECD
10.1. F/O 57%, Max Gas 698u. MW in/out 9.4/9.5. P/U 150k, S/O 100k, ROT 124k. Start final build and turn @ 4529' MD. Slide/Drill 12.25" Surface F/ 4,965 to
5,421 MD (4,422' TVD) Total 456' (AROP 76.') 550 GPM 1940 psi on, 1780 psi off 80 RPM, TRQ on 11-13k, TRQ off 10-12k, WOB 10-12k. ECD 10.25. F/O 52%
Max Gas 729u. MW in/out 9.5/9.55. P/U 154k, SLK 101k, ROT 125k. Jet as needed. Ream 60'.Cont Build/Turn. Slide/Drill 12.25" Surface F/ 5,421 to 5835 MD
(4,492' TVD) Total 414' (AROP 69') 550 GPM 2125 psi on, 1925 psi off 80 RPM, TRQ on 11-15k, TRQ off 10-12k, WOB 8-18k. ECD 10.72. F/O 55% Max Gas
1211u. MW in/out 9.5/9.55. P/U 151k, SLK 94k, ROT 118k. Jet as needed. Ream 60'.Cont Build/Turn. Distance to WP05: 16.82', 9.73' Low 13.72' Left. SLD Hrs:
6.13. ROT Hrs: 10.18. Daily disposal G&I: 684 bbls Total 1881 bbls. Daily disposal MPU G&I: 171 bbls Total 285 bbls. Daily H2O Lake 2: 1175 bbls Total 3105
bbls. Daily loss: 0 bbls. Total surface loss: 77 bbls.
50-029-23765-00-00API #:
Well Name:
Field:
County/State:
PBW L-246
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
9/2/2023Spud Date:
9/5/2023 Slide/Drill 12.25" Surface F/ 5835' - T/ TD 5964' MD (4495' TVD) Total 129' (AROP 86') 550 GPM 2075 psi on, 1950 psi off, 80 RPM, TRQ on 14k, TRQ off 10k,
WOB 5-10k. ECD 10.34, F/O 55% Max Gas 1864u. MW in/out 9.5/9.5. P/U 154k, S/O 90k, ROT 113k. Cont build/turn. Land in OBd sand as per geo. Obtain final
svy. Pump 45 bbl hi vis sweep (300 vis / 9.5 MW). Circulate 3x btms up while racking back 1x stand per btms/up T/ 5690' MD. No increase from sweep (on time).
550 gpm, 1850 psi, 55% F/O, 80 rpm, 11k tq, Max gas 1457u, 350-400u BGG. P/U 154k, S/O 90k, Rot 113k. Trip in on elevators F/ 5690' - T/ 5964' MD without
issue. Monitor well (static with very little to no hydrates breaking out). Prep floor for backreaming operations. Stage 9-5/8" centralizers on floor (58 ea). BROOH F/
5964' - T/ 5545' MD pulling @ 30 fpm, 550 gpm, 1730 psi, 55% F/O 80 rpm, 8.5k tq, 10.1 ECD w/ max gas 775u. No notable gas bump @ btms up from monitoring
well. Continue BROOH F/ 5545' - T/ 2460' MD pulling @ 30-45 fpm as hole allows, 550 gpm, 1430 psi, 50% F/O 80 rpm, 5.5k tq, 10.4 ECD w/ max gas 698u. Hole
was clean with minimal issue backreaming for this time interval. Conr BROOH F/ 2,460' to 719' MD 450 gpm 835 psi 40 rpm Trq 2-3k F/O 47% ECD 10.64 MW
in/out 9.6/9.65, Max Gas 986u. P/U 91k SLK 64k ROT 68k. At 2,167' MD encountered Trq erratic Trq swings 6-11.5k. CBU 2X over 5 stands F/ 2,167' to 1,962'
Prior to BPF. 60% increase in cutting. Cont seeing Trq swing. Reduce rotary F/ 80 to 60 rpm at 1,862' MD. At 1,702' MD hole unloaded heavy sand at shakers. At
1,406' MD reduce rate F/ 550 to 500 gpm. Cont seeing Trq swing and minimal pressure spikes. At 1,152' MD reduced rate to 450 gpm and rotary to 40 rpm at end
of tangent. Heavy sand unloading at 760' MD. Pull speeds 1-20 fpm F/ 2,167' to 719' MD as hole dictated. No losses. BROOH BHA F/ 7,19' to 526' MD. 450 gom
770psi 40 rpm Trq 2.5-10k ECD 9.89 Max Gas 152u. P/U 43k SLK 43k. At 610' MD hole unloaded heavy sand at shakers. At 590' MD monitor well 10 min, static.
POOH on elevators F/ 526' to surface. Rack back 8 stands 5" HWDP W/ Jar. L/D bottle neck X/O & 2 NM FC. Read MWD tools. L/D TM, EWR-M5, DM & GWD
collars. P/U drain Motor, break bit & L/D. Cone Grade: 1-1-WT-A-F-I-NO-TD PDC Grade: 1-2-CT-A-X-I-BF-TD. Stand 7 5" HWDP upper Jnt, mid hard band worn
flat side. PJSM L/D MWD tools and clear rig floor. Service master bushing's. PJSM Swing PH8 in standby. R/D Hydraulic elevators and R/I 9.625" 250T elevators.
P/U R/U 9.625" Csg tools and Equip. R/U power tongs and M/U CRT to TD. Count 159 jnts in pipe shed & 58 9.625" bow spring centralizers on rig floor. Jet
flowline. Ensure over board line is clear. Distance to WP05: 28.89', 17.16' Low 23.24' Left. SLD Hrs: 1.59. ROT Hrs: 0.58. Daily disposal G&I: 803 bbls Total 2684
bbls. Daily disposal MPU G&I: 228 bbls Total 513 bbls. Daily H2O Lake 2: 1070 bbls Total 4175 bbls. Daily loss: 0 bbls. Total surface loss: 77 bbls.
9/6/2023 PJSM RIH 9.625" 40# L-80 TXP BTC. P/U M/U Shoe, blank and FC (BakerLoc) Check floats, good. Drop ByPass Plud as per HES. P/U M/U BFA (BakerLoc) shoe
track 128.73' MD. Cont RIh 9.625" Csg as per tally F/ 128' to 2,481' MD. Circ string volume at 2,068' MD stage up to 7 bpm 132 psi 5 rpm Trq 4.5k. P/U 95k SLK
70k ROT 82k Run speed 50-80 fpm. Trq TXP BTC 20,960 ft/lb. Lost 41 bbls. Fill every 5 jnts, top off 10. PJSM Cont RIH 9.625" 40/47# L-80 TXP BTC F/ 2,481' to
4,726' MD. P/U M/U ES (BakerLoc) at 3,902' MD verify 6 shear pins as per HES. At ES CBU stage up to 6 bpm 190 psi 1-2 rpm Trq 14k stall. Max Gas 737u. Lost
23.6 bbls. Trq 47# TXP BTC 23,820 ft/lb. P/U 216k SLK 118k ROT 121k. Run speed 45 fpm. Filling every 5 jnts, top off 10 jnts. PJSM Cont RIH 9.625" 47# L-80
TXP BTC F/ 4,726' to 5,954' MD. P/U Jnt 155 and tag on depth 5,964' MD L/D Jnt 155.CBU at 4,905' MD stage up to 6 bpm 225 psi 1-2 rpm Trq 14k stall. Max
Gas 342u. Lost 10.4 bbls. P/U 242k SLK 133k ROT 141k. Run speed 45 fpm. Trq 47# TXP BTC 23,820 ft/lb. Filling every 5 jnts, top off 10 jnts. 2 centralizers on
rig floor, 10 jnts 40# & 5 jnts 47# (Correct). PJSM ROT/REC 5,954' to 5,890' MD Condition mud to <20 YP for cement job. Stage pumps up to 6 bpm 165 psi F/O
27% 1-2 rpm Trq stall 15.5k Dynamic losses 8-10 bph. Lost 30 bbls. Heavy sand at shaker. SIMOPS R/D 9.625" Csg tools and Equip. L/D Bail Ext, elevators and
power tongs. Shut down pump throug. bleeder, check dump valve and clean out possum belly. Break out of CRT, blow down and R/U HP cement lines. PJSM
ROT/REC 5,954' to 5,890' MD Condition mud to <20 YP for cement job 6 bpm 320 psi F/O 28% 1-2 rpm Trq stall 15.5k Dynamic losses 8-10 bph. Lost 30 bbls.
Heavy sand at shaker. At 2.5 BU Cont to see heavy sand and small wood at shakers. Decision was made to stop ROT/REC due washing out hole. Reduction of
80% of sand at shakers while parked. PJSM, Wet lines w/ 5 bbls H2O (HES) and P/T low kick out 1,331 low/ 4,000 high. Pump 1st stage cement job as follows: 60
bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls) 4.4 bpm, 264 psi. Release F/ Volant, Drop bypass plug. 210 bbls (503 sx) 12 ppg
EconoCem Type I II Lead. cmt, 2.347 yld, 4.6 bpm, 347 psi. 82 bbls (400 sx) 15.8 ppg HalCem Type I II Tail cmt, 1.156 yld, 3.5 bpm, ICP 459 psi FCP 297 psi.
Release F/ Volant, drop shutoff plug. Displace w/ 20 bbls H2O (HES) 6 bpm 400 psi then turn over to rig. Rig disp w/ 256.29 bbls 9.6 ppg spud mud, 6.5 bpm, ICP
232 psi. FCP 390 psi. HES disp 80 bbls 9.4 ppg spacer, 4.8 bpm ICP 370 psi FCP 667 psi. Rig disp 80.61 bbls 9.6 ppg spud mud 3.5 bpm, ICP 564 psi FCP 827
psi. Bump plug, Press up to 1,448 PSI with 433.62 bbls actual / 436.61 bbls calculated. Held pressure for 5 minutes, check floats - good. CIP 05:58 hrs. Lost 11
bbls during job. Daily disposal G&I: 404 bbls Total 3088 bbls. Daily disposal MPU G&I: 171 bbls Total 684 bbls. Daily H2O Lake 2: 530 bbls Total 4705 bbls. Daily
loss: 105 bbls. Total surface loss: 182 bbls.
9/7/2023 Pressure up to 3071 psi and see stage tool shift open. Continue to CBU @ 3bpm staging up to 6 bpm 498 psi. Dump 60 bbls spacer, 98 bbls green cmt, 102 bbls
contaminated mud at bottoms up. Flush Stack and surface equipment with black water. Continue to circulate through stage tool @ 4 bpm prepping for 2nd stage
cmt. Ramping pumps to 7 bpm for 500 stks every hour. PJSM. Pump 2nd stage cement job as per detail: flood lines with 5 bbls water at 5 bpm, 250 psi. Pump 60
bbls 10 ppg tuned spacer (with 4# red dye, 5# polyflake in first 10 bbls) at 4.5 bpm, 213 psi. pump 277 bbls (612 sxs) 11 ppg ArcticCem lead cement at 4.5 bpm,
465psi. Saw spacer and contaminated mud @ 240 bbls into total pumped. Good lead cement. Pump 56 bbls Type I/II 15.8 ppg tail cement at 3.5 bpm, 322 psi.
Drop closing plug. HES displace with 20 bbls water at 6 bpm, 342 psi. Swap to rig pumps and bump plug with 131 bbls (131 calculated) of 9.6 ppg spud mud, slow
rate to 3 bpm last 10 bbls. 500 FCP. Pressure up and observe tool shift close at 1700 psi. Hold 1800 psi for 3 minutes. Bleed off to static indicated tool shifted close.
CIP at 16:45. No losses. 227 bbls cement to surface. Full returns during job. PJSM R/D CRT & blow down surface lines. R/D HP cement lines. Disconnect knife
valve. Install 9.625" elevators. SIMOPS: Load 5" D.P. in pipe shed. PJSM Attach bridge cranes to stack. Unsecure stack. Crane on location at 18:00 and released at
19:30 R/D 16" diverter sections. Break stack and set emergency slips (45k) as per Vault rep onsite. Cut 9.625" Csg & L/D (29.05') Dress 9.625" csg stump. Set
down stack and Johnny Whack stack. L/D trip nipple. R/D stack and secure on pedestal. N/D diverter tee. knife valve and speed head. SIMOPS Off load fluid in pits
and clean. Cont processing 5" D.P. PJSM Prep Annular studs and RCD head for for install. M/U RCD head to Annular. SIMOPS Cont cleaning pits and processing
5" D.P. PJSM Install multi-bowl well head as per Vault rep. Set DSA & test plug. Attempted to test RCMS and failed. Tightened flange bolts to 400 ft/lb and
attempted to test again, fail. Pull test plug. Pull off wellhead. Cut RCMS seal off 9.625" Csg stub. Inspect and found no visual damage. Install new. seals and dress
stub W/ wire wheel. SIMOPS Clean Pits and work on mud pumps. C/O discharge valve and seat on MP #1 Pod 1 & 2. Suction valve and seat on Pod 4. On MP #2
C/O discharge valve and seat Pod 1, 2 & 4. Daily disposal G&I: 1363 bbls Total 4451 bbls. Daily disposal MPU G&I: 744 bbls Total 1428 bbls. Daily H2O Lake 2:
1150 bbls Total 5855 bbls. Daily loss: 11 bbls. Total surface loss: 193 bbls.
9/8/2023 Continue to change out RCMS Seal on Wellhead. Re-land and N/U Wellhead. Re-test successful. Install Test Plug. Land DSA and Stack. N/U BOPE/MPD and
associated equipment. SIMOPS: Finish cleaning pits, C/O Suction line on cuttings box, Prep spots for welder, relocate shaker camera position, cut grating from
rotary table drains. Continue to N/U BOPE/MPD and associated equipment. Install Trip Nipple and Obtain RKB's: Ann 11.79', UPR (VBR's) 14.98', Blinds15.55',
LPR(7" solid) 19.92', ULDS 22.27', LLDS 24.26'. R/U BOPE Test Equipment/Test Jts, flood stack and fill Test Pump Tank, check senators on test manifold.
Perform shell test 250/3000 psi, good. PJSM Perform BOPE test W/ 4.5", 5" & 7 to 250 PSI low and 3,000 PSI high for 5 Min. Tested Choke Manifold 1-15, 5" Dart,
2 ea 5" TIW, 4 TIW, Upper and lower IBOP, Mez Kill, HCR Choke, HCR Kill, manual Choke and Kill, Super Choke and manual to 1,800 PSI, Use 7 for LPRs (7
solid body), Use 4.5. & 5 for Upper VBR (2.875 X 5.5 VBRs) & 4.5 Annular. Checked PVT sensors and return flow. PVT high/ low level alarms. Test H2S 10-20
ppm, LEL 20-40%, Koomey draw drown initial System 3,025 PSI, Manifold 1,450 PSI, Annular 925 PSI, after System 1,450 PSI, Man 1,450 PSI, Annular 950 PSI.
200 PSI increase 20 Sec, full charge 86 sec. Nitrogen 6 bottle average 2,308 PSI. Closing times Ann 11 sec, UPR & Blinds 9/10 sec, LPR 9 sec, HCR Choke & Kill
1/1 sec. Used H2O for test. Witnessed waived by AOGCC Rep Adam Earl. SIMOPS Bring on 580 bbls 9.2 ppg BaraDril N to Pits. PJSM R/D test Equip. Blow down
surface lines and choke manifold. Install 5" Hydraulic elevators. PJSM M/U wear ring running tool and set wear ring. RILDS (4 ea) Lngt 38", OD 10.8", ID 9". L/D
running tool. PJSM P/U M/U Clean Out BHA #2. 8.5" XR+CPS Tricone (3X18.1X16 Jts 0.9419 TFA), 6.75" TerraForce 1.5 deg Motor and 9 stands 5" HWDP & Jar
from derrick to 590' MD. PJSM Single in hole BHA #2 W/ 5" 19.5# S-135 NC50 D.P. F/ 590' to 1,957' MD. Drift 3.125" OD. Dump displacement down drag chain.
P/U 78k SLK 58k. PJSM Wash down F/ 1,957' to ES 2,049' MD (on depth). Saw cement strings at 2,024' MD. 400 gpm 650 psi 40 rpm Trq 4-6k WOB 3-5k P/U
69k SLK 73k. Tripped through 2X with & without rotary no issue. Was down to 2,080' MD. Cont ingle in hole BHA #2 W/ 5" 19.5# S-135 NC50 D.P. F/ 2,080' to
4,300' MD. Drift 3.125" OD. Dump displacement down drag chain. P/U 134k SLK 74k. Daily disposal G&I: 57 bbls Total 4508 bbls. Daily disposal MPU G&I: 0 bbls
Total 1428 bbls. Daily H2O Lake 2: 120 bbls Total 975 bbls. Daily loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/9/2023 Cont single in hole 5" D.P. F/ 4,300' to 5,673' MD. Drift 3.125" OD. P/U 160k SLK 68k. Fill pipe and wash down F/ 5,673' to 5,801' MD. 400 gpm 610 psi 40 rpm
Trq 5-6k P/U 162k SLK 60k ROT 72k. PJSM CBU 1.5X ROT/REC F/ 5,803' to 5,737' MD. 400 gpm 630 psi 40 rpm Trq 4-6k P/U 164k SLK 60k ROT 72k Dumping
clabbered mud as needed. PJSM Flood lines and choke manifold. Shut UPR's. Used MP#1. Perform 9.625" Csg test to 2,700 psi for 30 min, Initial 2750 psi 15 min
lost 26 psi, final 15 min lost 6 psi, good. Pumped 5 bbls. bled 5 bbls. PJSM Wash down F/ 5,801' to BFA at 5,826' MD (On Depth) Cont drill FC & cement to 5,930'
MD. FC 5,869' MD on depth. Ream 2X FC no pumps & no ROT. 400 gpm 900 psi 40 rpm Trq 13-16k P/U 168k SLK 68k ROT 115k. Cont drill cement and 20' of
new F/ 5,826' to 5,984' MD Shoe on depth 5,954' MD ream 2X no issue. Start displacing to 9.2 ppg BaraDril N while drilling 20' of new hole. Pump 30 bbl high Vis
sweep 200 Vis. Cont displacing to 9.2 ppg BaraDril N ROT/REC F/ 5,984' to 5,920' MD. 400 gpm 710 psi 40 rpm Trq 12k P/U 168k SLK 85k ROT 113k. Obtain
SPR's. Monitor well 10 min, static. Rack back 1 stand to 5,925' MD. PJSM Perform FIT 12 ppg EMW. Close UPR's and use MP #1. R/U flood lines. MW 9.2 ppg
4,495' TVD 690 psi - 12.15 ppg EMW. Pumped 1.7 bbls bled 1.5 bbls. R/D & B/D. PJSMPOOH racking back 5" D.P. F/ 5,925' to 590' MD. Pumped 25 bbl dry job.
no losses. P/U 57k SLK 57k. PJSM L/D BHA. L/D 8 jnts 5" HWDO. Rack back 4 stands & jar. L/D 2 jnts 5" HWDP. Milk motor, break off 8.5" Bit. L/D bit and 1.5
deg motor. Bit Grade 1-1-WT-A-E-I-NO-BHA. PJSM Clean and clear rig floor. Stage BHA components om pipe shed and rig floor. Bit, NRP, DM, TM and 2 ea FS.
PJSM P/U M/U 8.5" RSS BHA #3. 8.5" PDC TK66 (6X13 Jets 0.7777 TFA), 8.5" NRP, 8.5" GeoPilot 7600 XL, 6.75" ADR, 8.375" ILS, 6.75" DGR, 6.75" PWD,
6.75" DM, 6.75" ALD, 6.75" CTN & 6.75" TM. Down load MWD. Load nuclear sources. Cont M/U 8.375" Integral Blade, 6.75" FS ( Non Ported/Plunger). 6.75" NM
FC, 6.75" FS ( Non Ported/Plunger), 6.75" NM FC and 4 stands 5" HWDP W/ 6.5" Hydra Jar to 432.73' MD. PJSM RIH BHA #3 W/ 5" 19.5# S-135 NC50 D.P. F
432' to 3,302' MD. Pulse test MWD at 500' MD, good. Break in GeoPilot at 1,664' MD. Drift 3.125" OD. Kicked out 2 bad jnts of rental pipe. Lost 2.5 bbls. P/U 115k
SLK 93k. POOH rack back 5" D.P. F/ 3,602' to 1,696' MD. Single back in hole W/ 5" D.P. F/ 1,696' to 2,268' MD. Drift 3.125" OD. P/U 115k SLK 93k. Daily disposal
G&I: 984 bbls Total 5492 bbls. Daily disposal MPU G&I: 114 bbls Total 1542 bbls. Daily H2O Lake 2: 340 bbls Total 6315 bbls. Daily loss: 0 bbls. Total Production
loss: 0 bbls. Surface Total: 193 bbls.
9/10/2023 Single back in hole W/ 5" D.P. F/ 2,268'' to 5,760'. TIH out of Derrick to 5,888. Pull Trip Nipple and install MPD RCD Bearing. PT MPD Lines to 250/1200 psi. Slip
and Cut 8 wraps (50') Drill line. Check Brakes Calibrate Blocks. SIMOPS: Circulate 400 gpm, 950 psi shearing new mud and increasing lube content to 2% while
Slip/Cut Ops. Service Rig, grease and inspect crown sheaves. Check Top Drive Gear oil. Grease Blocks and Top Drive. Wash down from 5,888' to 5,984', tag btm
no fill. Drill 8.5" hole F/ 5984' - T/ 6,649' MD (4,485' TVD) Total 761' (AROP 127') 550 GPM 1895 psi on, 1845psi off, 120 RPM, TRQ on 12-17k, TRQ off 13-14k,
WOB 8-12k. ECD 10.36, F/O 55% Max Gas 1864u. MW in/out 9.2+/9.3. P/U 162k, S/O 66k, ROT 102k. Drill 8.5" Hole F/ 6,649' to 7,409' MD (4,460' TVD) Total
760' (AROP 126.7') 550 gpm/ mpd 550, 1935 psi on, 1900 psi off, 120 rpm, TRQ on 14-14.5k, TRQ off 12.5-14k, wob 8-12k. ECD 10.56, MW in/out 9.25/9.3, Max
Gas 2657u. P/U 160k, SLK 68k, ROT 101k. MPD 100% open. Back ream 60'. Drill 8.5" Hole F/ 7,409' to 8,110' MD (4,454' TVD) Total 701' (AROP 116.8') 525
gpm/ mpd 525, 1850 psi on, 1800 psi off, 120 rpm, TRQ on 14-18k, TRQ off 13-16k, wob 10-12k. ECD 10.66, MW in/out 9.2/9.25, Max Gas 2836u. P/U 164k,
SLK 60k, ROT 106k. MPD 100% open. Back ream 60'. At 8,012' MD 04:30 was lost Shaker #1. Bring electrician to trouble shot. Adjusting flow rate 450-550 gpm to
control Shaker #2 from running over. Distance to WP05: 19.71', 4.82' Low 19.11' Left. 23 concretions for a total thickness of 62' ( 3% of the lateral). Footage Obd-1
493', OBd-2 204', OBd-3 896', OBd-4 223', PBd-5 275'. Total OBd 2097'. Daily disposal G&I: 171 bbls Total 5663 bbls. Daily disposal MPU G&I: 114 bbls Total
1656 bbls. Daily H2O Lake 2: 270 bbls Total 6585 bbls. Daily loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/11/2023 Drill 8.5" Hole F/8,110' to 8,874' MD (4,427' TVD) Total 764' (AROP 127.3') 550 gpm, 2140 psi on, 2000 psi off, 120 rpm, TRQ on 16.5k, TRQ off 15.5k, wob 8-
12k. ECD 10.82, MW in/out 9.2+/9.3, Max Gas 3021u. P/U 173k, SLK 66k, ROT 105k. MPD 100% open. Back ream 60'. Electrician troubleshot Shaker #1.
Replaced motor lead that looked original. Drill 8.5" Hole F/8,874' to 9,675' MD (4,390' TVD) Total 801' (AROP 133.5') 550 gpm, 2345 psi on, 2255 psi off, 120 rpm,
TRQ on 13-14k, TRQ off 12-13k, wob 8-12k. ECD 10.95, MW in/out 9.3/9.3+, Max Gas 2535u. P/U 136k, SLK 71k, ROT 101k. MPD 100% open. Back ream 60'.
Drill 8.5" Hole F/ 9,675' to 10,194' MD (4,358' TVD) Total 519' (AROP 86.5') 550 gpm/ mpd 550, 2425 psi on, 2355 psi off, 120 rpm, TRQ on 16-17.5k, TRQ off 15-
16k, wob 8-12k. ECD 11.2, MW in/out 9.4/9.45, Max Gas 1758u. P/U 137k, SLK 69k, ROT 100k. MPD 100% open. Back ream 60'. Kicked off for appraisal #1 at
10,015' MD 4,376.05' TVD 93.19 deg inc 296.97 deg azi. targeting ~115 deg. Planned PB is at ~9,500' MD due to OBd-1 being very silty and unviable. Drill 8.5"
Hole F/ 10,194' to 10,660' MD (4,231' TVD) Total 466' (AROP 77.7') 550 gpm/ mpd 550, 2540 psi on, 2390 psi off, 120 rpm, TRQ on 7-10k, TRQ off 8-10k, wob 9-
11k. ECD 11.45, MW in/out 9.3/9.4, Max Gas 1454u. P/U 135k, SLK 64k, ROT 96k. MPD 100% open. Back ream 60'. Distance to WP05: 99.27', 98.82' High 9.38'
Left. 54 concretions for a total thickness of 62' (8.5% of the lateral). Footage Obd-1 725', OBd-2 319', OBd-3 1503', OBd-4 417', PBd-5 1026'. Total OBd 3990'. Out
of zone: 645'. Daily disposal G&I: 974 bbls Total 6637 bbls. Daily disposal MPU G&I: 0 bbls Total 1656 bbls. Daily H2O Lake 2: 885 bbls Total 7470 bbls. Daily
loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/12/2023 Drill 8.5" Appraisal Sec F/10,660' - T/11,227' MD (4,033' TVD) Total 567' (AROP 94.5') 550/550 gpm/mpd, 2540/2390psi on/off, TRQ 7-10K/8-10Kft-lbs on/off.
WOB 9-11K. MW 9.3/9.4 in/out, ECD 11.45, Max Gas 1454u. P/U 135K, SLK 64K, ROT 96K. MPD 100% open. Back ream 60'. Drill 8.5" Appraisal Sec F/11,227' -
T/11,508' MD (3967' TVD) Total 281' (AROP 70.25') 550/550 gpm/mpd, 2655/2390psi on/off, TRQ 7-10K/8-10k on/off. WOB 9-11K. MW 9.3/9.4 in/out, ECD
11.45, Max Gas 1593u. P/U 135K, SLK 64K, ROT 96K. MPD 100% open. Back ream 60'. Circulate two bottoms up while rotating and reciprocating, prior to
BROOH. 550gpm=2670psi, Beyond RF=550gpm, ECD=11.55. TQ=10Kft-lbs at 120RPM. P/U=129K, S/O=51K, ROTW=83K. Max Gas=459u. BROOH F/11,508' -
T/9,510' without any issues or losses downhole. 550gpm=2437psi, Beyond RF=532gpm, ECD=11.2. TQ=9-10Kft-lbs at 120RPM. Max Gas 474u. P/U=125K,
S/O=62K, ROTW=95K. Sidetrack as intended at KOP 9,510' MD (4,402' TVD). Troughed F/9,510 - T/ 9,530' at 45FPH with 425gpm, increased to 60FPH to 9,550',
further increased to 80FPH to 9,570' MD. Old survey at 9,570' MD had us at 93.45deg, new survey shows good separation at 88.78deg. BROOH F/9,570' - T/9,510'
(KOP) and tripped back in without pumps on following the path of the new sidetrack as confirmed with ABI. 425gpm=1577psi, ECD=10.69, RF=424gpm. TQ=10K
with 120RPM and 1-4K WOB. P/U=129K, S/O=68K, ROTW=102K. Drill 8.5" Injection Lateral F/9,570' - T/9,635' MD (4395' TVD) Total 65' (AROP 65') 500/500
gpm/mpd, 2100/2060psi on/off, TRQ 10K/9-10K on/off. WOB 10-12K. MW 9.35/9.5 in/out, ECD 11.02, Max Gas 679u. P/U 135K, SLK 64K, ROT 96K. MPD 100%
open. Back ream 60'. At 9,620 we completed a 580 bbl dump and dilute with 9.2ppg BARADRIL-N Mud to help aid in MBT Reduction (15MBT>8.5MBT). Drill 8.5"
Injection Lateral F/9,635' - T/10,274' MD (4372' TVD) Total 639' (AROP 107') 525/525 gpm/mpd, 2180/2120psi on/off, TRQ 12K/11.5K on/off. WOB 12K. MW
9.25/9.4 in/out, ECD 11.87, Max Gas 2456u. P/U 132K, SLK 75K, ROT 103K. MPD 100% open. Back ream 60'. Distance to WP05: 43.97', 36.75' High 24.14'
Right. 48 concretions for a total thickness of 137' (3.2% of the lateral). Footage Obd-1 493', OBd-2 423', OBd-3 1629', OBd-4 644', OBd-5 1064'. Total OBd 4253'.
Out of zone:. Daily loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/13/2023 Drill 8.5" Injection Lateral F/10,274' - T/10,878' MD (4,360' TVD) Total 604' (AROP 101') 550/550 gpm/mpd, 2390/2300psi on/off, TRQ 12K/9K on/off. WOB 6-10K.
MW 9.25/9.35 in/out, ECD 11.15, Max Gas 2233u. P/U 136K, SO 72K, ROT 103K. MPD 100% open. Back ream 60'. Drill 8.5" Injection Lateral F/10,878' -
T/11,758' MD (4,357' TVD) Total 880' (AROP 147') 550/550 gpm/mpd, 2645/2598psi on/off, TRQ 13-13.5K/12-13K on/off. WOB 8-12K. MW 9.35/9.45 in/out, ECD
11.4, Max Gas 3325u. P/U 138K, SO 68K, ROT 99K. MPD 100% open. Back ream 60'. Drill 8.5" Injection Lateral F/11,758' - T/12,401' MD (4,340' TVD) Total 643'
(AROP 108') 550/550 gpm/mpd, 2750/2695psi on/off, TRQ 14K/3-14K on/off. WOB 8-12K. MW 9.35/9.45 in/out, ECD 11.7, Max Gas 2579u. P/U 139K, SO 57K,
ROT 97K. MPD 100% open. Back ream 60'. Drill 8.5" Injection Lateral F/12,401' - T/13,194' MD (4,324' TVD) Total 793' (AROP 133') 550/550 gpm/mpd,
2780/2680psi on/off, TRQ 13-16K/13K on/off. WOB 5-10K. MW 9.35/9.45 in/out, ECD 11.66, Max Gas 3002u. P/U 143K, SO 54K, ROT 100K. MPD 100% open.
Back ream 60'. Distance to WP05: 28.99', 28.98' High 0.46' Right. 78 concretions for a total thickness of 231' (3.2% of the lateral). Footage Obd-1 856', OBd-2 463',
OBd-3 3360', OBd-4 958', OBd-5 1538'. Total OBd 7175'. Out of zone:. Daily loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/14/2023 Drill 8.5" Injection Lateral F/13,194' - T/13,924' MD (4,320' TVD) Total 730' (AROP 122') 550/550 gpm/mpd, 2910/2730psi on/off, TRQ 16K/13K on/off. WOB 10-
12K. MW 9.3/9.4 in/out, ECD 11.72, Max Gas 2911u. P/U 144K, SO 42K, ROT 99K. MPD 100% open. Back ream 60'. Drill 8.5" Injection Lateral F/13,924' -
T/14,456' MD (4,315' TVD) Total 532' (AROP 89') 550/550 gpm/mpd, 2926/2750psi on/off, TRQ 15-17K/13-14K on/off. WOB 10-12K. MW 9.35/9.45 in/out, ECD
11.37, Max Gas 2513u. P/U 145K, SO N/A, ROT 101K. MPD 100% open. Back ream 60'. Completed a dump and dilute of 580bbls at 14,202' MD, MW dropped
down 0.2ppg. Control drilled F/14,158' - T/14,400 at 150fph due to high ECD's and PSI, ECD's were reduced down to 11.27ppg from 11.9ppg. Drill 8.5" Injection
Lateral F/14,456' - T/15,098' MD (4,311' TVD) Total 633' (AROP 106') 550/550 gpm/mpd, 2708/2650psi on/off, TRQ 16-17K/15-16K on/off. WOB 6-12K. MW
9.2/9.3 in/out, ECD 11.3, Max Gas 1594u. P/U 157K, SO N/A, ROT 101K. MPD 100% open. Back ream 60'. Drill 8.5" Injection Lateral F/15,098' - T/15,797' MD
(4,302' TVD) Total 699' (AROP 117') 550/550 gpm/mpd, 2936/2890psi on/off, TRQ 17-19K/16-17K on/off. WOB 6-12K. MW 9.2/9.25 in/out, ECD 11.79, Max Gas
3401u. P/U 162K, SO N/A, ROT 92K. MPD 100% open. Back ream 60'. Began control drilling at 15,685' MD at 150fph to aid in reduction of ECD"s (11.8ppg).
Distance to WP05: 27.86', 27.01' High 6.84' Left. 98 concretions for a total thickness of 322' (3.3% of the lateral). Footage Obd-1 1334', OBd-2 673', OBd-3 4533',
OBd-4 1162', OBd-5 2069'. Total OBd 9771'. Out of zone:. Daily loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/15/2023 Drill 8.5" Injection Lateral F/15,797' - T/16,371' MD (4,283' TVD) Total 574' (AROP 96') 525/511 gpm/mpd, 2865/2805psi on/off, TRQ 16-18K/14-15K on/off,
120RPM. WOB 6-12K. MW 9.2/9.25 in/out, ECD 11.97, Max Gas 3116u. P/U 156K, SO N/A, ROT 91K. MPD 100% open. Back ream 60'. Control Drill 150fph. Drill
8.5" Injection Lateral F/16,371' - T/16,861' MD (4,287' TVD) Total 490' (AROP 82') 525/512 gpm/mpd, 2888/2801psi on/off, TRQ 16-18K/15-17K on/off, 120RPM.
WOB 6-12K. MW 9.2/9.35 in/out, ECD 11.99, Max Gas 1885u. P/U 154K, SO N/A, ROT 88K. MPD 100% open. Back ream 60'. Control Drill 150fph. Fault
observed at 16,580' showing a 7' DTN Throw. Completed a 580bbl dump and dilute at 16,518'. ECD's dropped from 11.9ppg to 11.71ppg. Drill 8.5" Injection
Lateral F/16,861' - T/17,378' MD (4,273' TVD) Total 517' (AROP 86') 525/511 gpm/mpd, 2830/2768psi on/off, TRQ 18-20K/15-18K on/off, 140RPM. WOB 6-12K.
MW 9.2/9.3 in/out, ECD 11.92, Max Gas 970u. P/U 154K, SO N/A, ROT 88K. MPD 100% open. Back ream 60'. Control Drill 150fph. Drill 8.5" Injection Lateral
F/17,378' - T/17,900' MD (4,290' TVD) Total 522' (AROP 87') 525/507 gpm/mpd, 2940/2865psi on/off, TRQ 18-21K/16-18K on/off, 140RPM. WOB 6-10K. MW
9.1/9.1 in/out, ECD 11.97, Max Gas 1763u. P/U 157K, SO N/A, ROT 93K. MPD 100% open. Back ream 60'. Control Drill 150fph. Survey Depth 17,570' MD has us
27.86' from WP05, 27.01' High 6.84' Left. 95 concretions for a total thickness of 289' (2.4% of the lateral). Footage Obd-1 1334', OBd-2 843', OBd-3 5919', OBd-4
1532', OBd-5 2249'. Total OBd 11,877'. Out of zone:. Daily loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/16/2023 Drill 8.5" Injection Lateral F/17,900' - T/18,246' MD (4,281' TVD) Total 346' (AROP 58') 500/484 gpm/mpd, 2766/2710psi on/off, TRQ 18-21K/16-18K on/off,
120RPM. WOB 6-18K. MW 9.1/9.15 in/out, ECD 11.87, Max Gas 3129u. P/U 159K, SO N/A, ROT 93K. MPD 100% open. Back ream 60'. Control Drill 150fph. Drill
8.5" Injection Lateral F/18,246' - T/18,402' MD (4,266' TVD) Total 156' (AROP 52') 500/488 gpm/mpd, 2742/2712psi on/off, TRQ 18-21K/16-18K on/off, 120RPM.
WOB 6-18K. MW 9.1/9.15 in/out, ECD 11.89, Max Gas 1328u. P/U 159K, SO N/A, ROT 93K. MPD 100% open. Back ream 60'. Control Drill 150fph. MP#2 began
leaking out of the tattle tale. Inspected and found the #1 Pod in MP#2 to be cracked and. Swapped out Pod, Liner, Swab and wear plate along with seals. CBU with
MP#1 and rack back a stand every hour while rotating and reciprocating 198gpm, 80 RPM, TQ 15-16K. P/U 154K, S/O 36K, ROTW 91K. Wash back to bottom
F/18,078' - T/18,402' MD at full drilling parameters. Drill 8.5" Injection Lateral F/18,402' - T/18,706' MD (4,263' TVD) Total 304' (AROP 68') 500/483 gpm/mpd,
2838/2777psi on/off, TRQ 18-21K/16-18K on/off, 120RPM. WOB 6-18K. MW 9.1/9.2 in/out, ECD 11.90, Max Gas 2371u. P/U 159K, SO N/A, ROT 91K. MPD
100% open. Back ream 60'. Control Drill 150fph. Drill 8.5" Injection Lateral F/18,706' - T/19,165' MD (4,186' TVD) Total 459' (AROP 77') 500/484 gpm/mpd,
2915/2800psi on/off, TRQ 18-22K/17-19K on/off, 120RPM. WOB 6-18K. MW 9.15/9.2 in/out, ECD 11.91, Max Gas 1912u. P/U 159K, SO N/A, ROT 91K. MPD
100% open. Back ream 60'. Control Drill 150fph. As per GEO we finished our Undulation schedule through the OBd sands and began building our inclination to
115deg at 18,720' to assess the toe up Appraisal - currently we are drilling up through the OBc. Survey Depth 18,779' MD has us 12.39' from WP05, 12.37' Low
0.48' Right. 114 concretions for a total thickness of 377' (2.9% of the lateral). Footage Obd-1 1405', OBd-2 1152', OBd-3 6054', OBd-4 1613', OBd-5 2679'. Total
OBd 13148'. Out of zone:. Daily loss: 0 bbls. Total Production loss: 0 bbls. Surface Total: 193 bbls.
9/17/2023 Drill 8.5" Injection Lateral F/19,165' - T/19,647' MD (3,991' TVD) Total 482' (AROP 81') 425/407 gpm/mpd, 2275/2250psi on/off, TRQ 18-25K/18-21K on/off,
120RPM. WOB 6-18K. MW 9.15/9.2 in/out, ECD 11.91, Max Gas 1912u. P/U 145K, SO N/A, ROT 84K. MPD 100% open. Control Drill 150fph. Loss 25 bbls. Drill
8.5" Injection Lateral F/19,647' - T/19,931' MD (3,991' TVD) Total 284' (AROP 48') 425/410 gpm/mpd, 2534/2457psi on/off, TRQ 18-25K/18-21K on/off, 80-
120RPM. WOB 6-16K. MW 9.15/9.2 in/out, ECD 11.92, Max Gas 1384u. P/U 139K, SO N/A, ROT 84K. MPD 100% open. Control Drill 150fph. Loss 35bbls. Drill
8.5" Injection Lateral F/19,931' - T/20,235' MD (3,842' TVD) Total 304' (AROP 51') 425/434 gpm/mpd, 2696/2617psi on/off, TRQ 18-27K/18-21K on/off, 80-
120RPM. WOB 6-20K. MW 9.25/9.35 in/out, ECD 12.1, Max Gas 1325u. P/U 136K, SO N/A, ROT 82K. MPD 100% open. Control Drill 150fph. Loss 45bbls. Drill
8.5" Injection Lateral F/20,235' - T/20,353' MD (3,821' TVD, 99.98Inc, 295.29 Azm) Total 118' (AROP 59') 450/428 gpm/mpd, 2625/2520psi on/off, TRQ 18-27K/18-
21K on/off, 80-120RPM. WOB 6-20K. MW 9.15/9.25 in/out, ECD 12.08, Max Gas 1325u. P/U 133K, SO N/A, ROT 82K. Loss 30bbls. Obtained Final Survey Depth
20,281.84' MD (3,837.47' TVD, 99.98 Inc. 295.29 Azm.). 81.44' from WP05, 79.37' High and 18.24' Left. Flow checked the well for 10 mins via MPD - No Flow.
BROOH F/20,353' - T/18,914' MD. 475/434 gpm/mpd, 120RPM, TQ18K, Max Gas 1118u, MW 9.1/9.25 in/out, ECD 11.8. P/U 135K, S/O N/A, ROTW 93K. Loss
35 bbls. Pumped Tandem Sweeps (Low-Vis/Hi-Wt, Hi-Vis/Wt). not yet at Surface. Rotate and Reciprocate 100RPM. 121 concretions for a total thickness of 424'
(2.9% of the lateral). Footage Obd-1 1405', OBd-2 1152', OBd-3 6054', OBd-4 1613', OBd-5 2679'. Total OBd 12903'. Out of zone: 1,496'. Daily loss: 170 bbls.
Total Production loss: 195 bbls. Surface Total: 193 bbls.
9/18/2023 Continue circulating Tandem sweep around. sweep arrived 130bbls late, observing a minimal increase in cuttings. Circulate an additional 4 BU. 500/482 gpm/mpd,
2950psi, 120 RPM, TQ 17K, Max Gas 361u. P/U 153K, S/O N/A, ROTW 95K. PJSM - Pump SAPP Train (40bbls SAPP, 20bbls Mud, 40bbls SAPP, 20bbls Mud,
32bbls SAPP) and chase with 9.1ppg QuikDril-N Mud. SAPP Train arrived 105 bbls late, over boarded SAPP train before taking returns to pits.335/326 gpm/mpd,
1450 psi, Loss of 363 bbls for Clean up cycle and displacement. Flow checked the well for 10 mins - Good. BROOH F/18,914 - T/18,259' MD Pulling speed 10-
20fpm. 500gpm had a dynamic Loss Rate of 30-40bph. Reduced Flow and losses slowed to 10-20bph. 425-450/415-425 gpm/mpd, 1315-1509psi, 120 RPM, TQ
19-22K. Beyond 100% open. BROOH F/18,259 - T17,996' MD, Reduced pulling speed down to 1-3fpm as needed due to erratic torque spikes and slight pack offs.
Dynamic losses staying steady at 10bph. P/U 155k, S/O 36K, ROTW 101K. BROOH F/17,996' - T/16,553' MD. Pulling speed 10-20fpm. Reduced pulling speed to
1-3fpm as needed F/17,650' - T/17,591' and F16,805 - T16,553' MD due to packing off and TQ spikes. 500/485 gpm/mpd, 1984psi, 120RPM, TQ 19-24K,
Dynamic loss 10/bbl hr. P/U 153K, S/O 36K, ROTW 100K. BROOH Loss 216bbls. BROOH F/16,553' - T/14,462' MD. Pulling speed 10-20fpm. Reduced pulling
speed to 1-3fpm as needed F/15,850' - T/15,792' and F/15,210 - T15,023' MD due to packing off and TQ spikes. 525/485 gpm/mpd, 1840psi, 120RPM, TQ 19-
21K, Dynamic loss 10/bbl hr. P/U 152K, S/O 72K, ROTW 100K. Slack off weight regained at 14,462'. 121 concretions for a total thickness of 424' (2.9% of the
lateral). Footage Obd-1 1405', OBd-2 1152', OBd-3 6054', OBd-4 1613', OBd-5 2679'. Total OBd 12903'. Out of zone: 1,496'. Daily loss: 579 bbls. Total Production
loss: 704 bbls. Surface Total: 193 bbls.
9/19/2023 BROOH F/14,462' - T/12,178' MD. Pulling speed 10-20fpm. Reduced pulling speed to 1-3fpm as needed due to packing off and TQ spikes. 550/536 gpm/mpd,
1895psi, 120RPM, TQ 17-18K, Dynamic loss 3-6/bbl hr. P/U 148K, S/O 72K, ROTW 102K. BROOH F/12,178' - T/10,381' MD. Pulling speed 20-30fpm. Reduced
pulling speed to 1-3fpm as needed due to packing off and TQ spikes F/11,640' - T/11,595', F/10,570' - T/10,381'. 550/534 gpm/mpd, 1915psi, 120RPM, TQ 13-
15K, Dynamic loss 2-3/bbl hr. P/U 145K, S/O 75K, ROTW 101K. BROOH F/10,381' - T/9,447' MD. Pulling speed 20-30fpm. Reduced pulling speed to 1-3fpm as
needed due to packing off and TQ spikes F/10,125' - T/10,061', F/9,799' - T/9,575'. 550/534 gpm/mpd, 1885psi, 120RPM, TQ 10-15K, Dynamic loss 1-3/bbl hr.
P/U 143K, S/O 86K, ROTW 101K. RIH on Elevators F/9,447' - 9,687' MD. Shot a survey ensuring good separation from PB1 (KOP = 9,510') ensuring path to the
Mother bore was taken - DD/MWD confirmed Good separation. BROOH F/9,687' - T/6,840' MD. Pulling speed 20-30fpm. Reduced pulling speed to 1-3fpm as
needed due to packing off and TQ spikes F/8,805' - T/8,749', F/7,720' - T/7,610'. 550/534 gpm/mpd, 1885psi, 120RPM, TQ 10-15K, Dynamic loss 1-3/bbl hr. P/U
143K, S/O 86K, ROTW 101K. 121 concretions for a total thickness of 424' (2.9% of the lateral). Footage Obd-1 1405', OBd-2 1152', OBd-3 6054', OBd-4 1613',
OBd-5 2679'. Total OBd 12903'. Out of zone: 1,496'. Daily loss: 98 bbls. Total Production loss: 802 bbls. Surface Total: 193 bbls.
9/20/2023 BROOH F/6,840' - T/5,948' MD. Reduced Rotary to 60RPM as we pulled up into shoe - no issues. Pulling speed for BROOH 20-30fpm. Reduced pulling speed to 1-
3fpm as needed due to packing off & TQ spikes. 550/525 gpm/mpd, 1625psi, 120RPM, TQ 6-8K, Dynamic loss 1-3/bbl hr. P/U 122K, S/O 106K, ROTW 114K.
Pump 40bbl Hi-Vis Sweep. sweep was observed to come back on time showing a 25% increase in cuttings. 550/534 gpm/mpd, 1606psi, 80RPM, 4-6Kft-lbs TQ.
Monitor well for 10 mins - No flow. Drain stack, pull bushings, remove grey clamp and pull bearing to rig floor. remove RCD bearing from drill pipe. Install trip nipple,
flood stack and check for leaks - no leaks. Lay down drill pipe to the shed F/5,948' - T/5,630' verifying not swabbing in well. Pumped a 45 bbl Corrosion inhibited dry-
job, blow down top drive and surface equipment. Lay down drill pipe to the shed F/5,630' - T/4,250'MD. P/U 117K, S/O106K, CALC=10.8bbls, ACT=11.1bbls,
Loss=0.3bbls. L/D drill pipe F/4,250' - T/432' (BHA). P/U 68K, S/O 59K, CALC=33.5bbls, ACT=47.5bbls, Loss=14bbls. Remove Air slips, install bushings and
stripping rubbers. Move/prep iron Roughneck, clean and clear rig floor in prep for Tripping in the hole from Derrick. 1.5bph static loss rate. Trip in the hole out of the
Derrick F/432' - T/5,070' MD. P/U 129K, S/O 113k, CALC=114.8bbls, ACT=101.6bbls, Loss=13.2bbls for 73 stands. Monitor well for flow - No flow. Pump 45bbl
Corrosion inhibited dry-job. Lay down drill pipe to the shed F/5,070' - T/432' MD. Verified for no swabbing after first 10 joints - no swabbing. P/U 58K, S/O56K,
CALC=36.7bbls. ACT=49.6bbls, Loss=12.9bbls. Clean and Clear the rig floor. Send out Air slips and extra thread protectors. Monitor well on trip tank while
prepping to slip and cut. Install TIW and hang blocks. 1.5bph static loss rate. Slip and cut 75' of Drilling Line (1,014 Ton miles). Line left on spool 3,431'. Check
Brake. Reset floor, board and crown savers. Complete Rig Service. Crown sheave wobble EAM, Grease top drive, FH-80, overhead spinners, tongs and elevators.
PJSM - L/D BHA. L/D last drill pipe joint and rack back HWDP. L/D Jars, NM-Flex Collars, Float sub. Clear Floor and HES Reps remove Sources. Download MWD
and L/D Remaining BHA and GEO-Pilot. Bit Grade: 2-2-WT-A-X-I-CT-TD.
9/21/2023 PJSM - R/U to Run Casing. P/U Slips, Elevators, Tongs, Collar Clamps for 4.5" and 7". verify with mandrels. Install 4.5" Elevators and count pipe in shed. M/U
Shoe (Eccentric and Blank) joint and run in the hole with 4.5" H563 12.6# L-80 solid body liner F/Surface - T/5,314' MD, installing slotted liner joints as per tally. TQ
connections to 3,800ft-lbs. P/U 80K, S/O68K, CALC=22.8bbls, ACT=15.4bbls, Loss=7.4bbls. Continue RIH with 4.5" Liner F/5,314 - T/9,144' MD. P/U 4.5" XN-
Nipple, Swap over handling equipment to 7". P/U 4.5"x7" XO Jt. AZIP 7" Expandable Packer #1, 6 joints of 7" H563 26# L-80 Liner and AZIP 7" Expandable packer
#2 T/9,371' MD. RIH with 7" Liner F/9,371' - T/11,766' MD. P/U 121K, S/O 71K. Continue RIH with 7" H563 26# Liner F/11,766 - T/13,710' MD. Swap over
handling equipment to 5" DP. P/U Baker SLZXP packer per Rep (6 screws on setting tool and 7 screws on the slips). TQ 7" H563 26# Liner T/9400ft-lbs. P/U 121K,
S/O 71K, CALC=42.1, ACT=29.4, Loss=12.7bbls. Run in the hole with 5" DP out of the derrick. Pump 10bbls down string ensuring packer has clear flow path -
good. Run in the hole F/13,710' - T/17,165'. P/U 166K, S/O 50K. CALC=34.2bbls, ACT=25.1bbls, Loss=9.1bbls. SIMOPS: Tally HWDP in shed. Run in the hole
with 5" DP out Derrick F/17,165' - T/17,899' MD. Slack off weight started dropping off quickly and we continued running in the hole with 5" HWDP F/17,899' -
18,895' (Set Depth). P/U192K, S/O 42K. Not able to rotate pipe, TQ stalling at 5K. CALC=14.0bbls, ACT=8bbls, Loss=6bbls. M/U Top Drive and Reciprocated
while pumping 1.5x String volumes ensuring clear flow path to packer for dropping setting ball. 4bpm=650psi. Dropped 1.125" Phenolic Ball, pumped 600 strokes
at 3bpm, reduced to 1.5bpm seeing ball set on seat at 913 strokes. Pressure up to 2,060 psi and hold for 5 minutes. Slack off to 36K, increase pressure to 2,976psi
and hold for 5 minutes. Pressure up to 3,797psi, unable to blow out seat with Rig pumps, Increase to 4,089psi with test pump and shear out ball seat. P/U 143K
seeing good breakover - Free from Packer. R/U to test SLZXP Liner Top Packer. Close UPR flood lines and Test to 1500psi for 10 mins - Good test. Pumped
1.0bbls, bled back 1.4bbls. Rack back 1 stand to clear liner top. Monitor well for 10 mins - Good. Pump Corrosion inhibited 10.1ppg dry job. L/D 5" HWDP to shed
F/18,857 - T/18,632'. 121 concretions for a total thickness of 424' (2.9% of the lateral). Footage Obd-1 1405', OBd-2 1152', OBd-3 6054', OBd-4 1613', OBd-5
2679'. Total OBd 12903'. Out of zone: 1,496'. Daily loss: 55 bbls. Total Production loss: 907 bbls. Surface Total: 193 bbls.
Activity Date Ops Summary
9/22/2023 L/D 5" Drill Pipe F/5,099' - T/4,810' MD. P/U 137K, No slack off per Baker Rep. Rig Service - Grease all Handling equipment, fix failed bail angle sensor, fixed pipe
spinner proximity switch, disconnected driller side spinner motor on overhead spinners. Continue L/D 5" Drill Pipe F/4,810' - T/35' MD. L/D Baker Liner Running
tool. P/U 54K, No Slack off per baker rep. CALC=70bbls, ACT=56bbls, Loss=14bbls. RIH with open ended drill pipe out of the derrick F/Surface - T/4,003' MD. P/U
92K, S/O53K. CALC=25.2bbls, ACT=21.6bbls, Loss3.6bbls. Pull bushing, install stripping rubbers and air slips. POOH with 5" drill pipe F/4,003' - T/Surface. P/U
92K, S/O 63K. CALC=34.7bbls, ACT=37.7bbls, Loss=5.8bbls. RIH with open ended drill pipe out of the derrick F/Surface - T/2,193' MD. P/U 82K, S/O 71K.
CALC=19.6bbls, ACT=14bbls, Loss=5.6bbls. Pull bushing, install stripping rubbers and air slips. POOH with 5" drill pipe F/2,193' - T/Surface. P/U 46K, S/O 44K.
CALC=19.6bbls, ACT=25.6bbls, Loss=6bbls. Pull Air slips, bushings, stripping rubbers, drain stack and M/U Running tools. BOLDS. Pull wear ring, flush and flood
stack. Clean and clear the rig floor. R/D Rig Tongs, thread protectors. Load 4.5" and 7" Test joints in shed. Grease crown. Install Test plug. Flood Lines and function
valves. Perform shell test (good). Test BOPe to 250/3000psi for 5 min hold on chart. Tests completed on 4.5" and 7" Test Joints. Annular tested on 4.5" TJ. Test
CMV 7-15, 4" Dart/TIW, UPR/LWR IBOP's, Manual & HCR Kill. UPR fitted w/2-7/8"x5.5" VBR's, LPR fitted w/7" SBR. Test Gas alarms/lights (H2S:10&20ppm,
LEL: 20&40%), PVT. Test #2 F/P, HP bleeding off, Reflood lines with a passing test. Continue testing BOPe. Test CMV 1-6, 5" Dart/TIW, Mezz Kill, Manual & HCR
Choke. Conduct Accumulator Drawdown test: ACC initial=3000psi, after=1450psi. 200psi re-charge=24 seconds, full recovery=89 seconds, 6 bottle average
N2=2267psi. Test #8 Fail on SuperChoke. Actuator position switch failing - replaced and Passed. SIMOPS: R/U Casing equipment. R/D BOP Testing equipment.
AOGCC Witness Waived by Brian Bixby.
9/23/2023 Rig down BOP test equipment. Attempt to pull test plug (No Go). P/U pulling 30K over. Flush and vac out stack. Found significant debris on top of plug from working
rams during BOP test. Work test plug free with minimal effort once clear of debris. Clean and clear rig floor. R/U Parker casing equipment. Double stack hydraulic
tongs, 250T elevators w/ properly sized slips, and safety clamp. M/U XO w/ TIW. PJSM, M/U 7" Bullet Seal assy and RIH w/ 7" BTC Tieback, L-80, 26# casing
T/2284' MD. 9.2Kft-lbs TQ. S/O 70K, P/U 73K. 1-2 BPH static loss rate w/ 9.2 brine. Continue RIH w/ 7" BTC Tieback, L-80, 26# casing. 9.2Kft-lbs TQ. F/2284' -
T/tag depth 5211.24' on jt #127(2.37' deep). Set down 10K 2x. 25 bbls loss for trip. P/U 140K, S/O 110K. Observed 3-4K seal drag prior to tag. L/D tag jts
127&126. M/U 3.05', 21.55' pup jts below jt 125. M/U hanger w/ landing jt. RIH and landout 1.18' off no go (shoe @ 5210.06' MD). R/U circ equpment, lwr annular
psi (~375 psi). Psi up 200 on OA (held psi). Stripped up observing psi dump on depth to locate seals. Establish circulation @ 1bpm 160 psi (reverse circ). Pump
89bbls of 9.1ppg CI Brine and chased with 53bbls of FP Diesel from LRS at 2BPM. ICP:161psi, FCP:360psi. Strip back down thru the annular landing the hanger
with 70K string weight. R/D Circulating Equipment. L/D 7" Landing Joint. Swap over Elevators to 5". Drained stack and picked up the Packoff running tool. Land
Packoff and RILDS. PT void 500/5000psi for 10/10mins - Good. PT Test 9.625" x 7" OA to 1500psi for 30 mins (charted) via LRS. Initial=1698psi,
15mins=1650psi, 30mins=1639 - Good. Pumped 1.7bbls and bled back 1.7bbls. PJSM R/U Parker TRS. R/D 5" Elevators and P/U 4.5" Elevators (mandrel
verified). R/U Torque Turn computer and perform Dump test to 5,940ft/lbs - Good. RIH with 4.5" JFE Bear CR 12.6# L-80 TBG F/Surface - T/1,279' MD as per tally.
M/U X-Nipple with RHC, HES TNT Packer (6 shear screws), Durasleeve (Ports closed). Replaced Joint #17 (bad pin) with #153 and replaced Box on #16. P/U 45K,
S/O43K. CALC=3.8bbls, ACT=1bbls, Loss=2.8bbls. RIH with JFE Bear CR 12.6# L-80 TBG F/1,279' - T/3,765' MD. Encountering a string of joints that are
containing debris in the Clear Run Boxes/Pins that are damaging joints. Began cleaning Boxes and pins and applying light coats of BOL4010NM and Galling has
been reduced. P/U 68K, S/O 61K. Daily Lost Down Hole (QuikDril-N): 39bbls. Total Lost Downhole (QuikDril-N): 79bbls.
9/24/2023 Continue RIH with 4.5" JFE Bear 12.6# Tubing TQ Turning T/5,400ft-lbs, F/3,628' - T/5,857.49' TBG MD. spacing out accordingly. Make up Hanger per Vault
Wellhead Rep. Land Hanger with 34K string weight. RILDS and L/D Landing Joint. Set CTS-BPV. CALC=28bbls, ACT=-27bbls, Loss=55bls. R/D Handling
equipment from rig floor. Power tongs, TQ turn equipment, Elevators and slips. Clean and clear rig floor. M/U Stack cleaning device and flush at full rate a total of 3
times. Flush through Poor boy degasser, Choke, Kill and Bleeder. Blow down Top drive, Choke, Kill and Bleeder. While over a Cellar prior to Summer maintenance -
Pressure wash Derrick and thoroughly clean Top drive for removal. Send down all handling equipment and subs/crossovers to Pipe shed for inventory and
disassembly for Inspections. Offload Mud from Pits and begin cleaning. Blow down all surface lines, cement hoses, Choke/Kill HCR's and Gas buster. R/D
Choke/Kill Lines, break all connections on stack maintaining 4 bolt connection. Break MPD Head and leave 4 bolted. Open Grey Clamp and R/D MPD Lines. Blow
down Hole Fill. Continue Pressure washing windwalls and Derrick. Continue breaking down Handling equipment for summer maintenance. Continue Cleaning pits.
Bleed down Koomey. Pulled Bushings, Trip nipple and install MPD Cap. R/U MPD Slings, install barrier on Rotary Table. Open Ram doors and remove all rams.
Clean and put rams on ram rack. clean all cavities and lightly grease seals. Apply oil to door bolts prior to closing doors and securing. SIMOPS: continue cleaning
pits and checking pressure on tires for upcoming rig move. Pull Squeeze manifold out of cellar along with diverter "T". Pull MPD head and remove studs from stack.
Unbolt stack and set on pedestal and secure. Remove DSA for inspection.
9/25/2023 Install Compression ring and tree. Torque to 3,332ft-lbs as per wellhead rep. SIMOPS: Rig up Squeeze Manifold on the floor for reversing the CI Brine and FP
Diesel down the IA. Test tree void 500/5000psi for 10/10mins - Good. Test tree to 250/5000psi for 10/10mins - Good. R/D Test equipment,Flood lines and PT.
Reverse down the IA with 150bbls of 9.1ppg CI Brine (ICP=254 at 2bpm, FCP=315psi at 2.5bpm) and 69bbls of FP Diesel (ICP=130psi at 2.5bpm, FCP=975psi at
1.5bpm). Shut down and allow fluid to "U" tube from IA (7"x4.5") to TBG (4.5"). Start "U" tube at 11:45. Continued Allowing Diesel to "U" tube between IA and TBG.
178psi on Tubing, 184psi on IA. Continue clean pits and rigging down in preparation for rig move. Shut in Tubing/IA and bleed off pressure from squeeze manifold.
R/D Hose to rig floor and wait on parts. R/U to set packer and prep for Rig move. Bridal up Yoke to Top Drive with Bridal Lines. Lay Herculite and rig mats at Rig
maintenance location. M/U 7" OTIS Riser from Wells group and load 1-7/8" Ball and Rod with Rollers. Rig up 1502 connections and flood lines. OTIS Cap Leaking,
rig down and find O-ring failures. Source O-Rings. Flood Lines and found Whitey valves leaking on 7" riser - replace. O-Ring on OTIS cap leaking still - replace. PT
Surface lines to 2500psi - Good. Line up to 4.5" TBG for setting TNT packer. Pump at 0.25bpm, 188psi, pressure not increasing beyond (injecting), shutdown.
Bring pumps on at 1bpm, seeing pressure climb and reduced to 0.5bpm, pressure climbing to 1,154psi and fall off to 462psi, but continues climbing. Reduce rate to
0.4bpm and pressure continues to climb to 2,343psi and falls flat to 252psi (injecting). Pressure back up at 1.5bpm, pressure not increasing beyond 243psi
(Injecting). Reverse circulate down IA at 0.4bpm and see pressure climb rapidly to 694psi, tubing not climbing - shutdown pumps. IA Pressure holding steady at
578psi, indicating possible packer set. Conduct MIT on 7" x 4.5" IA to 3500psi for 30 mins (Start: 3,691psi, 15min: 3,628psi, 30min: 3,619psi) - Good. Max TBG/OA
195/280psi observed during MIT. During MIT, pumped 2.1bbls, bled back 2 bbls. Tried pressuring up on Tubing again at 1bpm, pressure climbing to 271psi
(injecting). Consulted with Engineer and decision was made to move forward with RDMO. Total of 3.6bbls injected when attempting to pump down tubing during
duration.
9/26/2023 L/D 7" OTIS Riser. R/D squeeze manifold and send down beaver slide. Hoist Lubricator to Rig floor and drop thru table to wellhead. R/U Lubricator, install BPV,
check for psi (0 psi) - Good. RDMO 02:00. Ending well pressures TBG=164 psi, IA=26 psi, OA=0 psi.
Well Name:
Field:
County/State:
PBW L-246
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
50-029-23765-00-00API #:
ACTIVITYDATE SUMMARY
9/26/2023
T/I/O=180/SI/SI. Set 4" CIW BPV #152. LTT (PASSED). Hung Sign. Final
WHP's=BPV/SI/SI. ***JOB COMPLETE***. RDMO.
9/27/2023
****WELL S/I ON ARRIVAL***
PULLED BALL & ROD & RHC BODY FROM 5,339' MD
SET PX PLUG & P-PRONG AT 5,339' MD
MIT-T TO 3500PSI (Pass)
PULLED P-PRONG & PX PLUG BODY FROM 5,339' MD
***WELL S/I ON DEPARTURE***
9/27/2023
T/I/O=BPV/SI/SI. Torque Upper Tree to MV to API specs. PT Against MV. 300 psi low
& 5000 psi high (PASSED). Pull 4" CIW BPV #152. PT Tree Cap to 500 psi
(PASSED). ***JOB COMPLETE*** RDMO. Final WHP's=180/180/0.
9/28/2023
CT #9 1.75" 0.156" Coil Tubing - Job Scope: Set XXN Plug, Set 7" Open-Hole
Packers
Travel to L-246. Start ticket @ 0300. MIRU, M/U YJ 3.80" drift, RIH tag XN at 9747
POOH. RIH with YJ MHA and 4.5" XXN plug. Work Plug down through Nipples to
NO GO at XN NIpple. Pressure test Tbg. to 2000 psi to confirm good seals.
***Continue WSR to 9/29/23***
9/29/2023
CT #9 1.75" 0.156" Coil Tubing - Job Scope: Set XXN Plug, Set 7" Open-Hole
Packers, Retrieve XXN Plug
Good PT of Plug to 2000 psi WHP. PUH to above XO, 9600'. Kill Well, 5 bbls Meth
Spear, 250 bbls KCL, Work pipe back down to XN nipple, Fighting Lockup. Order
Baroid NXS with Lube 776, Safelube. Run Plug back to XN Nipple 9747' with no
issues. Apply 5000 psi setting pressure to Saltel Packers per SLB sequence.
POOH. FP Tubing with Diesel 38 bbls.
Final T/I/O 340/250/0
***Job in Progress***
9/30/2023
CT #9 1.75" 0.156" Coil Tubing - Job Scope: Set XXN Plug, Set 7" Open-Hole
Packers, Retrieve XXN Plug
LD YJ Tools and XXN plug. Plug Packing Seals Missing. FP Coil with 32 bbls
diesel. RDMO.
Final T/I/O 340/250/0
***Job Completed ***
Daily Report of Well Operations
PBU L-246
Daily Report of Well Operations
PBU L-246
10/2/2023
***WELL SHUT IN ON ARRIVAL*** OBJECTIVE: PERFORATE 7 INTERVAL WITH
ALTUS TRACTOR
RIG UP YJ ELINE & ALTUS TRACTOR.
PT PCE 300 PSI LOW /3500 PSI HIGH.
RUN #1 W/CH (WP 5-2)/ ALTUS 2-1/8" TRACTOR/2.5'' MAX OD CENTRALIZER,
10' X 2'' GEO RAZOR GUN 54/7'' MAX OAL TO PERFORATE TWO INTERVAL
9200'-9210' AND 8550'-8560' CCL TO BOTTOM TOP SHOT GUN 18' CCL STO
DEPTH=9182', CCL TO TOP SHOT TOP GUN 6.9' CCL STOP DEPTH=8543.1'
ALL GUN FIRED.
LAY DOWN FOR THE NIGHT
***CONTINUE JOB ON 10/03/23***
10/3/2023
***CONTINUED JOB FROM 10/02/23*** PERFORATE 5 INTERVAL WITH ALTUS
TRACTOR
RIG UP YJ ELINE & ALTUS TRACTOR.
PT PCE 300 PSI LOW /3000 PSI HIGH
RUN #1 W/CH (WP 5-2)/ ALTUS 2-1/8" TRACTOR/2.5'' MAX OD CENTRALIZER,
X2 10' X 2'' GEO RAZOR6 spf 60 Deg PHASE GUN, 54/7' MAX OAL TO
PERFORATE TWO INTERVAL 7950'-7960' AND 7570'-7580' CCL TO BOTTOM
TOP SHOT GUN 18' CCL STOP DEPTH=7932', CCL
TO TOP SHOT TOP GUN 6.9' CCL STOP DEPTH=7563.1'
RUN #2 W/CH (WP 5-2)/ ALTUS 2-1/8" TRACTOR/2.5'' MAX OD CENTRALIZER,
X3 10' 2'' GEO RAZOR6 spf 60 Deg PHASE GUN, 64/7' MAX OAL TO
PERFORATE THREE INTERVALS 7150'-7160' , 6700'-6710' AND 6220'-6230' CCL
TO BOTTOM OF TOP SHOT GUN 29.2' CCL STOP DEPTH=7120.8', CCL
TO TOP SHOT OF MID GUN 18' CCL STOP DEPTH=6682', CCL TO TOP SHOT
OF TOP GUN 6.9' CCL STOP DEPTH=6213.1'
GAMMA RAY CORRELATE TO HES MD OPEN HOLE LOG DATED 12-SEP-2023
JOB COMPLETE
***WELL S/I ON DEPARTURE***
10/4/2023
***WELL S/I ON ARRIVAL***
ATTEMPTED TO SET 3.81'' PX-PLUG (never made depth)
ATTEMPTING TO RECOVER 3.81'' PX-PLUG FROM 5077' SLM, WORK TO 4601'
SLM (cont on next day)
***WSR CONT 10-5-23***
10/4/2023
T/I/O = 129/0/0 LRS 72 Assist Slickline as directed (NEW WELL POST) ***Job
Continued to 10-05-2023***
10/5/2023
T/I/O 387/0/0 (Assist Slickline/MIT-T) TFS U3. Pumped 5 bbls of DSL down the
TBG to monitor pressures and attempt an MIT-T MAP @ 3750 psi. Reached test
pressure at 3755 psi on the TBG. First 15 minutes TBG lost 141 psi. Second 15
minutes TBG lost 30 psi. Total loss over 30 minutes= 171 psi. ***PASS***. Bleed
back TBG to 789 psi for slickline to pull prong. SI bleeds took back 1.4 bbls of DSL.
*Job continues to 10-6-23*
Daily Report of Well Operations
PBU L-246
10/5/2023
T/I/O = 500/VAC/VAC. Temp = SI. IA FL (SL). IA FL near surface.
SL in control of valves upon depature. 23:00
10/5/2023
***WSR CONT FROM10-4-23***
PULLED 4-1/2" PX PLUG BODY FROM 4,613' SLM
RAN 4-1/2" BRUSH, 3.80" G-RING. B&F TUBING WITH 180* DIESEL DOWN TO
5,424' SLM
RAN 3.80" G-RING, 5' x 1/78" STEM, 3.80" G-RING, 2.00" SAMPLE BAILER DOWN
TO 5,440' SLM(no sample)
SET 4-1/2" PX PLUG BODY & PRONG AT 5,339' MD
RAN 4-1/2" 42 BO (SELF RELEASING KEYS) TO SSD - DURA SLEEVE AT 5,208'
MD(unsheared)
T-BIRD RAN MULTIPLE MIT-T'S. SEE T-BIRD LOG.
T-BIRD PERFORMED PASSING MIT-T... T/IA/OA START PRESS. 3755#psi/0#/0#
1ST 15MIN 3614# (-141#psi) 2ND 15MIN 3584#psi (-30#psi)
PULLED P- PRONG FROM PLUG BODY @ 5399' MD
PULLED 3.81'' PX-PLUG BODY FROM 5399' MD
SHIFTED 3.81'' SSD-XD-DURA SLEEVE w/ 42BO @ 5,207' SLM (5,208' MD
(shoulders facing down to open)
***WSR CONT ON 10-6-23***
10/5/2023
***Continue Job from 10-04-2023*** Assist Slickline as directed (NEW WELL POST)
Pumped 120 bbls 180* Diesel into TBG to assist SL w/ B&F. Slickline in control of
well upon LRS departure. Pad op notified.
10/6/2023
*Job continues from 10-5-23* (Assist slickline) TFS U3. Pumped 40 bbls of DSL
down the IA to confirm the sliding sleeve is open for slickline to set a jet pump. Well
left in control of slickline upon departure. flags and tags hung
10/6/2023
***WSR CONT FROM 10-5-23***
T-BIRD PUMPED DOWN AI TO CONFIRM SLEEVE IS OPEN, TOTAL 40 bbls 2 TO
3bpm TBG 800#psi, IA 650#psi, NO ISSUES
SET 3.81'' X-LOCK w/ EQ-SUB CHAMPION 4.5¿ 13A JET PUMP w/ SBHPS (batt.
connected @ 13:01)(secdary lock down, select, 4 x 3/16" ports)(LIH 126'')
RAN 4-1/2'' CHECK SET (sheared)
***JOB COMPLETE, WELL LEFT S/I***
10/7/2023
***WELL S/I ON ARRIVAL***
PULLED CHAMPION 4.5" 13A JET PUMP w/ EQ HOUSING ON LOCK.(To remove
EQ housing for proper spacing)
RAN 4-1/2" 42BO (SELF RELEASING KEYS, SHOULDER FACING DOWN) TO
VERIFY SLEEVE IS OPEN @ 5208' MD w/ NO ISSUES, PIN UNTOUCHED
SET 3.81'' X-LOCK (secdary lock down,lih121'') CHAMPION 4.5¿ 13A JET PUMP w/
SBHPS (batt connected10-6-23 @ 13:01) @ 5208' MD (hung tag)
RAN 4-1/2'' CHECK SET TO JET PUMP @ 5208' MD (sheared)
***JOB COMPLETE, WELL LEFT S/I***
10/8/2023
***WSR CONT FROM 10-7-23***
R/D POLLARD #61
***WELL LEFT S/I ***
10/8/2023
LRS Welltesting Unit #1. Begin WSR on 10/08/23. NWKO on L-246. IL well L-246,
OL FL to LDF. Unit spotted, permit signed, Begin RU. Continue WSR on 10/09/23.
10/9/2023
LRS Welltesting Unit #1. Continue WSR from 10/08/23. NWKO on L-246. IL well L-
246, OL FL to LDF. Continue RU. Sustained winds @ 23, gusts to 34 mph, begin
Weather SB. End WSR on 10/09/23.
10/10/2023
LRS Welltesting Unit #1. Begin WSR on 10/10/23. NWKO on L-246. IL well L-246,
OL Temporary FL on L-246. Winds diminished, Continue RU. RU complete, Pt
complete. Prejob WD with PO, doesn't want to Pop till AM, Blind in Skid needs to be
rolled. Continue to prep for Pop.Continue WSR on 10/11/23.
Daily Report of Well Operations
PBU L-246
10/11/2023
LRS Welltesting Unit #1. Continue WSR from 10/10/23. NWKO. IL well L-246, OL L-
246 Temporary FL,. SB for ops to roll blind. Pop well. Flowback.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
91
50
Yes X No Yes X No 6.4
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?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
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?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:
Casing (Or Liner) Detail
Shoe
RKB
10
318 4330.87
SE
C
O
N
D
S
T
A
G
E
MP 1
16:45
Surface
Rotate Csg Recip Csg Ft. Min. PPG9.6
Shoe @ 5954.77 FC @ Top of Liner5,868.92
Floats Held
30 693
375 318
Spud Mud
CASING RECORD
County State Alaska Supv.S Barber
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-246 Date Run 6-Sep-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC OSP 1.77 5,954.77 5,953.00
25.05
Csg Wt. On Hook:133,000 Type Float Collar:BFA No. Hrs to Run:15.5
9.6 6
1800
10
11 277 4.5
99
827
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer W/ 4# red dye/ 5# Pol E Fla 60
15.8
500
3.5
9.5 6 131/131
436.61/433.62
1448
98
MP 1
15.8 82
Bump press
ES Cementer
Bump Plug?
5:58 9/7/2023 2,049
2049.04
5,954.775,964.00
CEMENTING REPORT
Csg Wt. On Slips:45,000
Spud Mud
Tuned Spacer W/ 4# red dye/ 5# Pol E Flak
612 2.54
Stage Collar @
60
Bump press
100
227
ES Cementer Closure OK
56
ArcticCem Type I/II
Type
HalCem Type I/II 270
12 210
26.78 RKB to CHF
Type of Shoe:Conventional Casing Crew:Parker Wellbore
No. Jts. Delivered 159 No. Jts. Run 144 15
Length Measurements W/O
Threads
Ftg. Delivered 6,519.00 Ftg. Run 5,954.00 Ftg. Returned 565.00
Ftg. Cut Jt.29.05 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
Jnt 1 2 ea BS & 4 ea SR 10' from end, 1 ea BS & 2 ea SR jnt 2 & 3. Every jnt F/ 4-25, every other F/ jnt 27-49, 1 ea
F/ 91-94, 1 ea BS & 1 ea SR on ES pups, 1 ea jnt 105-108, every third jnt F/ 111-150. 62 total solid bow spring & 8
Stop rings
9.625" Csg 9 5/8 40.0 L-80 BTC 82.69 5,953.00 5,870.31
FC 10 BTC OSP 1.39 5,870.31 5,868.92
9.625" Csg 9 5/8 40.0 L-80 BTC 41.48 5,868.92 5,827.44
Baffle Adapter 10 BTC Halliburton 1.40 5,827.44 5,826.04
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 3,756.10 5,826.04 2,069.94
Pup 9 5/8 40.0 L-80 BTC 18.07 2,069.94 2,051.87
ES Cementer 10 BTC Halliburton 2.83 2,051.87 2,049.04
Pup 9 5/8 40.0 L-80 BTC 17.60 2,049.04 2,031.44
9.625" Csg 9 5/8 47.0 L-80 TXP BTC 2,006.39 2,031.44
Econo Cem Type I/II 503 2.35
HalCem Type I/II 400 1.16
4.6
1.17
9/7/2023 0
Spud Mud
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Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.09.18 10:02:55 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.09.18 11:03:27 -08'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 10/04/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: PBU L-246
PTD: 223-078
API: 50-029-23765-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (09/02/2023 to 09/18/2023)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU L-246 LWD Subfolders:
PBU L-246 Geosteering Subfolders:
Please include current contact information if different from above.
PTD: 223-078
PBU L-246: T38038
PBU L-246 PB1: T38039
10/5/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.10.05
08:43:18 -08'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
WELL: PBU L-246PB1
PTD: 223-078
API: 50-029-23765-70-00
FINAL LWD FORMATION EVALUATION LOGS (09/02/2023 to 09/12/2023)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
PBU L-246PB1 LWD Subfolders:
Please include current contact information if different from above.
10/5/2023
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From:McLellan, Bryan J (OGC)
To:Joseph Engel
Subject:RE: [EXTERNAL] RE: HAK PBU L-246 (PTD: 223-078) Lower Completion Change
Date:Friday, September 15, 2023 10:54:00 AM
Attachments:image002.png
image003.png
Joe,
Hilcorp has approval to proceed with the longer liner as shown in the diagram and described below as part of the approved PTD.
This email is sufficient, no need for sundry.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Joseph Engel <jengel@hilcorp.com>
Sent: Friday, September 15, 2023 10:37 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Josh Stephens <Josh.Stephens@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] RE: HAK PBU L-246 (PTD: 223-078) Lower Completion Change
Absolutely. Please see the proposed schematic showing the increased length of 7”, plugback isolation packers, and PB1.
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
Office: 907.777.8395 | Cell: 805.235.6265
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, September 14, 2023 3:54 PM
To: Joseph Engel <jengel@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Josh Stephens <Josh.Stephens@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: [EXTERNAL] RE: HAK PBU L-246 (PTD: 223-078) Lower Completion Change
Joe,
The proposed schematic in your email below appears to be the same as the one in the PTD application. Can you send an updated
proposed diagram?
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
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: Joseph Engel <jengel@hilcorp.com>
Sent: Thursday, September 14, 2023 3:23 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Josh Stephens <Josh.Stephens@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: HAK PBU L-246 (PTD: 223-078) Lower Completion Change
Mel / Bryan –
After running modeling of the liner run for L-246 and wanting to isolate PB1 with inflatable packers, Hilcorp would like to increase
the amount of 7” ran in the lower completion. The well was permitted for a 7 x 4-1/2” Liner, with ~ 700’ of 7” and we are
proposing a change to ~ 3500’ of 7” and the rest 4-1/2”.
Please let me know if you need anything else beyond an email notification for this change. A copy of the approved PTD and
schematic are attached for your reference.
Thank you for your time.
-Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
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 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.
_____________________________________________________________________________________
Revised By:JLS 9/13/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well:PBU L-246
Last Completed:TBD
PTD:
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20"Conductor 129.5 / X52 / Weld N/A Surface 107’N/A
9-5/8"Surface 47/ L-80 /BTC 8.681 Surface ~2,500’0.0732
9-5/8”Surface 40 / L-80 /VAM 21 8.835 ~2,500’5,850’0.0758
7”Tieback 26 / L-80 /BTC 6.276 Surface 5,185’0.0383
7”Liner 26 /L-80 Hyd 563 6.276 5,185’9,600’0.0383
4-1/2”Liner 12.6 / L-80 /H563 3.958 9,600’20,294’0.0155
TUBING DETAIL
4-1/2"Tubing 12.6# / L-80 /JFE Bear 3.958 Surface 5,850’0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 –Lead –407 sx / Tail –395 sx
Stg 2 –Lead –679 sx / Tail –268 sx
8-1/2”Cementless Slotted Liner
WELL INCLINATION DETAIL
KOP @ 300’
90°Hole Angle = @ 5,987’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API:TBD
Completion Date:TBD
JEWELRY DETAIL
No.Top MD Item ID
1 2,800’X Nipple 3.813”
2 5,198’X Nipple w/ Sliding Sleeve and Jet Pump 3.813”
3 5,185’7”x 9-5/8” Liner Hanger w/ Tieback Sleeve
4 5,198’Seal Assembly
5 5,258’HES TNT Packer
6 5,318’X Nipple 3.813”
7 5,850’WLEG –Bottom
8 9,400’
9,600’7”AZIP Expandable metal packers
9 9,640’4.5”XN Nipple
10 20,294’Shoe
4-1/2”SLOTTED LINER DETAIL –10’Slots in middle of joints
Jts Top (MD)Top (TVD)Btm (MD)Btm (TVD)
TBD TBD TBD TBD TBD
“““““
“““““
TBD TBD TBD TBD TBD
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay, Schrader Bluff Oil Pool, PBU L-246
Hilcorp Alaska, LLC
Permit to Drill Number: 223-078
Surface Location: 2277' FSL, 4116' FEL, Sec. 34, T12N, R11E, UM, AK
Bottomhole Location: 1426' FNL, 724' FWL, Sec. 30, T12N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above-referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of August 2023. 28
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.28 16:23:24 -08'00'
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: 20294' TVD: 3884'
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): 73.7'15.Distance to Nearest Well Open
Surface: x-582802 y- 5977994 Zone- 4 47.2' to Same Pool: 2085'
16.Deviated wells: Kickoff depth: 300 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 125 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Driven 20" 129.5# X-52 80 Surface Surface 107' 107'
12-1/4" 9-5/8" 47# L-80 BTC 2500' Surface Surface 2500' 2228'
12-1/4" 9-5/8" 40# L-80 Vam 21 3350' 2500' 2228' 5850' 4476'
Tieback 7" 26# L-80 BTC 5185' Surface Surface 5185' 4475'
8-1/2" 7"x4-1/2" 26#/12.6# L-80 Hyd 563 15109' 5185' 4475' 20294' 3884'
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: Joe Engel
Monty Myers Contact Email:jengel@hilcorp.com
Drilling Manager Contact Phone:907-777-8395
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
746'
September 5, 2023
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):
Uncemented Tieback
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)
Stg 1 L - 407 sx / T - 395 sx
5019
18. Casing Program: Top - Setting Depth - BottomSpecifications
1969
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
Stg 2 L - 679 sx / T - 268 sx
1522
2442' FSL, 2044' FEL, Sec. 33, T12N, R11E, UM, AK
1426' FNL, 724' FWL, Sec. 30, T12N, R11E, UM, AK
00-001
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp North Slope, LLC
2277' FSL, 4116' FEL, Sec. 34, T12N, R11E, UM, AK ADL 028239 & 047449
PBU L-246
PRUDHOE BAY FIELD /
SCHRADER BLUFF OIL POOL
ORION DEVELOPMENT AREA
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
ooo
oo
oo
oo
oo
oo
oo
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
8.21.2023Drilling Manager
08/21/23
Monty M
Myers
By Grace Christianson at 11:41 am, Aug 22, 2023
MGR28AUG2023
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing test of 9-5/8" surface casing and FIT digital data to AOGCC
immediately up performing the FIT.
* State witness MIT-IA to 3500 psi within 10 days after stabilized
injection.
* Variance to 20 AAC 25.412 (b) approved for packer placement >200' above top of perforations as liner
top packer required to be placed within the Orion oil pool to assure in-zone injection.
A.Dewhurst 23 AUG 2023 DSR-8/23/23
1522
50-029-23765-00-00223-078
*&:
08/28/23
08/28/23
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.08.28 16:24:01 -08'00'
27282930
343332
33-29E
L-01
L-01A
L-02
L-02A
L-03
L-03APB1
L-04
L-100
L-101
L-102
L-103
L-105
L-106
L-108
L-109
L-110
L-111
L-112
L-114
L-114A
L-115
L-116
L-117 L-118
L-121 L-121A
L-122
L-123
L-124
L-200
L-204
L-205
L-205A
L-205L1
L-205L2
L-205PB1
L-211
L-211PB1
L-212
L-212PB2
L-213
L-215
L-2
L-218
L-221
L-222
L-50
L-51
NWE1-01
NWE2-01
NWEILEEN-1
L-240
L-206
L-246_wp02
HILCORP NORTH SLOPE
Greater Prudhoe Bay
AOR MAP
L-246 Injector (Proposed)
FEET
0 1,000 2,000 3,000
POSTED WELL DATA
Well Label
WELL SYMBOLS
Location
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 L-246 well). Black dashed circles and lines
= 1320' radius from heel to toe of proposed L-246 lateralinjector.
May 18, 2023
PETRA 5/18/2023 2:47:49 PM
KUPARUK
RIVER UNIT
PRUDHOE
BAY UNIT
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
PBU L-112 202-229 50-029-23129-00-00 Producer 6438' 4496' 4675' 3537' Closed
7" Casing cement with
143bbls of 12ppg lead cement
followed by 32 bbls 15.8ppg
tail cement. Full returns
throughout job. Estimated
TOC ~4675'
PBU L-114A 205-112 50-029-23032-01-00 Producer 5635' 4450' 2650' 2610 Closed
5.5" TOC logged at 2650' with
USIT on 11/3/08. Kuparuk
Producer, not open to
Schrader Bluff
Area of Review PBU L-246i
Prudhoe Bay West
(PBU) L-246
Drilling Program
Version 1
8/15/2023
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 ................................................................................................. 23
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner ...................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 39
19.0 Innovation Rig Diverter Schematic ......................................................................................... 41
20.0 Innovation Rig BOP Schematic ............................................................................................... 42
21.0 Wellhead Schematic ................................................................................................................. 43
22.0 Days Vs Depth .......................................................................................................................... 44
23.0 Formation Tops & Information............................................................................................... 45
24.0 Anticipated Drilling Hazards .................................................................................................. 47
25.0 Innovation Rig Layout ............................................................................................................. 51
26.0 FIT Procedure .......................................................................................................................... 52
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 53
28.0 Casing Design ........................................................................................................................... 54
29.0 8-1/2” Hole Section MASP ....................................................................................................... 55
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 57
Page 2
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU L-246
Pad Prudhoe Bay L Pad
Planned Completion Type 4-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 20,294’ MD / 3,884’ TVD
PBTD, MD / TVD 20,284’ MD / 3,884’ TVD
Surface Location (Governmental) 2,277' FSL, 4,116' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582,802, Y= 5,977,994
Top of Productive Horizon
(Governmental)2442' FSL, 2044' FEL, Sec 33, T12N, R11E, UM, AK
TPH Location (NAD 27) X= 579,592 , Y=5,978,124
BHL (Governmental) 1426' FNL, 724' FWL, Sec 30, T12N, R11E, UM, AK
BHL (NAD 27) X= 566,870, Y= 5,984,690
AFE Number 231-00106
AFE Drilling Days 26
AFE Completion Days 3
Maximum Anticipated Pressure
(Surface) 1522 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1969 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft +47.2ft =73.7ft
GL Elevation above MSL: 47.2 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-246 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 BTC 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.565 26 L-80 BTC 7,254 5,410 604
8-1/2”7” 6.276 6.151 7.656 26 L-80 H563 7254 5410 604
4-1/2” 3.958 3.833 5.2 12.6 L-80
H563 7780 6350 267
Tubing 4-1/2” 3.958 3.833 4.937 12.6 L-80 JFEBEAR 8430 7500 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 &
Production
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
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-246 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 Josh Stephens 907.777.8420 josh.stephens@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Natalie Brent 907.564.4313 nbrent@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
_____________________________________________________________________________________
Revised By: JNL 8/21/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-246
Last Completed: TBD
PTD:
TD =20,294’ (MD) / TD =3,883’ (TVD)
20”
Orig. KB Elev.: 73.7’ / GL Elev.: 47.2’
7”
4
9-5/8”
1
2
3
See
Slotted
Liner
Detail
7”x
4-1/2”
XO
PBTD = 20,292’ (MD) / PBTD = 3,883’ (TVD)
9-5/8” ‘ES’
Cementer @
~2,500’
4-1/2”
7
6
5
8
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 107’ N/A
9-5/8" Surface 47/ L-80 / BTC 8.681 Surface ~2,500’ 0.0732
9-5/8” Surface 40 / L-80 / VAM 21 8.835 ~2,500’ 5,850’ 0.0758
7” Tieback 26 / L-80 / BTC 6.276 Surface 5,185’ 0.0383
7” Liner 26 / L-80 Hyd 563 6.276 5,185’ 5,850’ 0.0383
4-1/2” Liner 12.6 / L-80 / H563 3.958 5,850’ 20,294’ 0.0155
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / JFE Bear 3.958 Surface 5,850’ 0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 407 sx / Tail – 395 sx
Stg 2 – Lead – 679 sx / Tail – 268 sx
8-1/2” Cementless Slotted Liner
WELL INCLINATION DETAIL
KOP @ 300’
90° Hole Angle = @ 5,987’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. Top MD Item ID
1 2,800’ X Nipple 3.813”
2 5,138’ X Nipple w/ Sliding Sleeve and Jet Pump 3.813”
3 5,185’ 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve
4 5,198’ Baker gauge carrier
6 5,318’ X Nipple 3.813”
7 5,850’ WLEG – Bottom
8 20,294’ Shoe
4-1/2” SLOTTED LINER DETAIL
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
TBD TBD TBD TBD TBD
““ “ “ “
“““““
TBD TBD TBD TBD TBD
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Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-246 is a grassroots injector planned to be drilled in the Schrader Bluff OBd sand. L-246 is part of a
multi well program targeting the Schrader Bluff sand on PBU L-pad.
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set in the OBd. An 8-1/2” section will
be drilled in the OBd. A 4-1/2” slotted injection liner will be run in the open hole section, followed by a 7”
tieback, and the well will be completed with injection tubing. L-246 is planned to be pre-produced for 30
days via jet pump, prior to being put on injection.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately September 7, 2023, pending rig schedule.
Surface casing will be run to 5,850’ MD / 4,475’ TVD and cemented to surface via a 2 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” hole to TD
6. Run 4-1/2” injection liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. Remote Ops geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote Ops geologist. LWD: GR + ADR (For geo-steering)
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L-246 SB Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-246. 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)”.
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L-246 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
1) “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 surface casing shoe landing at the
OBd production interval at ~88 degrees inclination. In order 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 ~5332’ MD. The production packer will be
~50’ MD above the X nipple which puts it at ~5258’ MD / ~4368’ TVD. The surface casing shoe is planned at
~5850’ MD / 4476’ TVD which means the planned packer depth is ~600’ MD away. From a TVD standpoint, the
production tubing packer is ~108’ TVD from the surface casing shoe. With the surface casing set in the Schrader
Bluff sand, and the injection packer set inside the surface casing, injection fluids will be confined to the Schrader
bluff sands.
Approved for liner top packer/ production packer to be placed >200' above top of perforations as long as liner top packer is
placed within the Orion oil pool. - mgr
g
t ~5258’ MD / ~4368’ TVD.
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Prudhoe Bay West
L-246 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”
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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L-246 SB Injector
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-246 will utilize a newly set 20” conductor on L-pad. Ensure to review attached surface plat
and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 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).
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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L-246 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. 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.
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L-246 SB Injector
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
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L-246 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.
x Bit will be a Baker Huges Kymera K5M633, Jetting 3x12 & 3x15
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 in the OBd 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 (pending MW increase due to hydrates). This is to combat
hydrates and free gas risk and offset any gas cut MW, based upon offset wells.
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L-246 SB Injector
Drilling Procedure
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
x Be prepared for gas hydrates. In PBW they have been encountered typically around 1660’
TVD (Base of Perm) to 2740’ TVD (Top Ugnu). Be prepared for hydrates:
x Gas Hydrates are present on L PAD
x Keep mud temperature as cool as possible, Target 60-70*F
x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
x Drill through hydrate sands and quickly as possible, do not backream.
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the
well. MW will not control gas hydrates, but will affect how gas breaks out at surface.
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.
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L-246 SB Injector
Drilling Procedure
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 – 9.5 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
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. Drop mud temp as low as possible as well.
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.
x Ensure mud temp is as low as possible when backreaming before and through the SV 2 & 3
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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Prudhoe Bay West
L-246 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 TXP 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 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 Ensure bypass baffle is correctly installed on top of float collar.
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.
This end up.
Bypass Baffle
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L-246 SB Injector
Drilling Procedure
12.5 Float equipment and Stage tool equipment drawings:
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L-246 SB Injector
Drilling Procedure
12.6 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 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,500’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
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.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD).
x Confirm depth of first major hydrates seen (possibly SV3) and position stage tool above if
possible, confirm with geo and drilling engineer before adjusting depth and ensure there is
enough 1st stage cement available
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 47# L-80 TXP Make-Up Torques
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
9-5/8” 40# L-80 BTC MUT – Make up to Mark 10 jts Take Average
Casing OD Minimum Optimum Maximum
9-5/8”18,000 ft-lbs Mark 23,060 ft-lbs
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L-246 SB Injector
Drilling Procedure
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Drilling Procedure
12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
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.
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L-246 SB Injector
Drilling Procedure
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
x Ensure drifted to 8.525”
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 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.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 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.
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L-246 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 + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Casing (5,850'-1,000'-2,500') x 0.0558 bpf x 1.3 170.4 956.0
Total Lead 170.4 956.0 406.8
12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.8
9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0
Total Tail 81.6 457.8 394.7
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Prudhoe Bay West
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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (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.
13.10 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.
13.11 Displacement calculation:
= 2500 *.0732 + (5,850-2500-120)*.0758
=427.9 bbls
13.12 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.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
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.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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L-246 SB Injector
Drilling Procedure
13.16 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.
13.17 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.
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Prudhoe Bay West
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Drilling Procedure
Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 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. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
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 3 316.3 1774.3
Total Lead 344.9 1934.8 678.9
12-1/4" OH x 9-5/8" Casing (2500 - 2000') x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6
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Lead Slurry Tail Slurry
System Arctic Cem G
Density 11.0 lb/gal 15.8 lb/gal
Yield 2.85 ft3/sk 1.17 ft3/sk
Mixed
Water 14.6 gal/sk 5.08 gal/sk
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Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
13.26 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.27 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.
13.28 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.
13.29 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.
13.30 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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Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 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 2-7/8” x 5-1/2” 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
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 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 3-1/2” test joint
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
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 9.5 ppg Baradrill-N fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” directional BHA
x Motor and Triple Combo
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 5” 19.5# S-135 NC50.
x Run a solid float in the production hole section.
Schrader Bluff Bit Jetting Guidelines for NOV TK66
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.2 TIH w/ 8-1/2” BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. 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.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 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. Submit
casing test and FIT digital data to AOGCC.
x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP)
email FIT and casing test digital data to AOGCC immediately upon completion of FIT. email: melvin.rixse@alaska.gov
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Drilling Procedure
15.8 8-1/2” 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
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 HPH
T
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
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
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Drilling Procedure
X-CIDE 207 0.015 ppb
15.9 Install MPD RCD
15.10 Displace wellbore to 9.5 ppg Baradrill-N drilling fluid
15.11 Begin drilling 8-1/2” 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 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 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 Reservior plan is to cross all lobes of the Schrader Bluff sand and TD beneath the OBD.
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 MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Hole Section A/C:
x There are no wells with a 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.
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Drilling Procedure
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 (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
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 BROOH with the drilling assembly to the 9-5/8” 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
15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.19 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.20 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
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
15.21 POOH and LD BHA.
15.22 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
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
16.0 Run 4-1/2” Injection Liner
16.1 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.
16.2 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.
16.3 Run 4-1/2” injection 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
16.4 Confirm with OE whether or not this is required. Ensure to run enough liner to provide for
setting the liner hanger at ~ 5,700’ 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.
16.5 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
16.6 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.
16.5. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.6. 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.
16.7. 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 Monitor FL and if filling is required due to losses/surging.
16.8. 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.
16.9. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.10. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.11. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.12. 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
16.13. 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.
16.14. 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.
16.15. 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
16.16. 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.
16.17. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.18. 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.
16.19. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.20. 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
17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 BTC tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, BTC
Confirm Torques with casing hand
=
17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs
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Drilling Procedure
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 4-1/2”, 12.6#, L-80 JFE Bear tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, JFE Bear 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.
18.2 PU, MU and RH with the following 4-1/2” GL completion jewelry (tally to be provided by
Operations Engineer):
x Torque Turn All Connections
x Tubing Jewelry to include:
x 1x ‘X’ Nipple
x 1x SSD
x 1x Production Packer
x 1x X Nipple
x 1x WLEG
x XXX joints, 4-1/2”, 12.6#, L-80, JFEBEAR
18.3 PU and MU the 4-1/2” tubing hanger.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited KCL follow by ~150 bbls of diesel freeze
protect for both tubing and IA to 2,500’ TVD.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
Page 40
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
18.12 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.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. CTU
a. Pull ball and rod in 4-1/2” production packer
Page 41
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 42
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 43
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
21.0 Wellhead Schematic
Page 44
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
22.0 Days Vs Depth
Page 45
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
COMMENTS
SV5 Ice 1,748 1,605.0 -1531 706 8.46
BPRF Water 1,923 1,750.0 -1676 770 8.46
SV3 Gas Hydrates 2,308 2,069.0 -1995 910 8.46 Gas Hydrates expected SV3, SV2, & SV1 sands: ~2300' - 3000' MD
SV1 Gas Hydrates 2,876 2,539.0 -2465 1117 8.46
Ugnu 4A Heavy Oil 3,245 2,845.0 -2771 1252 8.46 Possible Heavy Oil in Ugnu 4A: ~ 3250' - 3350' MD
UG3 Water 3,645 3,176.0 -3102 1397 8.46
Ugnu LA Water 4,265 3,690.0 -3616 1624 8.46
Ugnu MB Water 4,509 3,893.0 -3819 1713 8.46
NA Schrader Bluff Water 4,774 4,097.0 -4023 1803 8.46
OA Top Schrader Bluff Water 5,025 4,257.0 -4183 1873 8.46
Obc Top Schrader Bluff Oil 5,415 4,422.0 -4348 1946 8.46
OBd Top (Heel) Schrader Bluff Oil 5,816 4,475.0 -4401 1969 8.46
OBd (Toe) Schrader Bluff Oil 19,150 4,234.0 -4160 1863 8.46
Well TD (NB sand) Schrader Bluff Oil? 20,294 3,884.0 -3810 1709 8.46
L-246 wp04ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY EXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING EASTING Est.
Pressure Gradient
Page 46
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
Page 47
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
24.0 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.
Gas Hydrates/Free Gas
Gas hydrates have been seen on PBU L Pad. They were reported between 1660’ and 2740’ TVD. MW
has been chosen based upon successful trouble free penetrations of offset wells.
x PBU L-206 (2021) saw gas hydrates from the base of permafrost to top of Ugnu 4, with the
highest levels in the SV3 & 2.
o Keep mud temperature as cool as possible, Target 60-70*F
o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
o Drill through hydrate sands and quickly as possible, do not backream.
o Reduce flowrate as needed to help control hydrates in the mud column.
Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not
prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been
disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible
while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone.
Excessive circulation will accelerate formation thawing which can increase the amount of hydrates
released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with
both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud
cut weight. Isolate/dump contaminated fluid to remove hydrates from the system.
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
Page 48
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
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 L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
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 49
Prudhoe Bay West
L-246 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.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
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 50
Prudhoe Bay West
L-246 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.
8.5” Hole Section Specific AC:
x There are no wells with a CF < 1.0
Page 51
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
25.0 Innovation Rig Layout
Page 52
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
26.0 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 53
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
28.0 Casing Design
Page 55
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 56
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Prudhoe Bay West
L-246 SB Injector
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
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-1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000
Vertical Section at 293.00° (2000 usft/in)
L-246 wp01 tgt1
L-246 wp01 tgt4L-246 wp01 tgt2 L-246 wp01 tgt3
L-246 wp02 tgt5
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
5 00
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 00 0
5500
6000
6500
7000
7500
8000
8500
9000
9500
10000
10500
110
00
11
500
12000
12500
13000
13500
1
4000
14500
1
5000
15500
16000
16500
17000
17500
18000
18500
19000
1
9
5
0
0
2
0
0
0
0
2
0
2
9
4
L-246 wp04
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 4º/100' : 500' MD, 499.63'TVD
End Dir : 1201.54' MD, 1152.18' TVD
Start Dir 5º/100' : 4508.14' MD, 3891.62'TVD
End Dir : 5698.07' MD, 4468.47' TVD
Start Dir 2º/100' : 5798.07' MD, 4473.7'TVD
Begin Geosteering lateral
SV5
BPRF
SV3
SV1
Ugnu 4A
UG3
Ugnu LA
Ugnu MB
NA
OA
Obc
Obd
Hilcorp North Slope, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: L-246
47.20
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 5977994.19 582801.96 70° 20' 59.4982 N 149° 19' 39.9130 W
SURVEY PROGRAM
Date: 2023-05-18T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
26.50 1500.00 L-246 wp04 (L-246) GYD_Quest GWD
1500.00 5850.00 L-246 wp04 (L-246) 3_MWD+IFR2+MS+Sag
5850.00 20294.19 L-246 wp04 (L-246) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
1604.60 1530.90 1747.63 SV5
1749.60 1675.90 1922.65 BPRF
2068.60 1994.90 2307.69 SV3
2538.60 2464.90 2875.00 SV1
2844.60 2770.90 3244.35 Ugnu 4A
3175.60 3101.90 3643.88 UG3
3689.60 3615.90 4264.30 Ugnu LA
3892.60 3818.90 4509.32 Ugnu MB
4096.60 4022.90 4773.73 NA
4256.60 4182.90 5025.21 OA
4421.60 4347.90 5415.63 Obc
4474.60 4400.90 5816.39 Obd
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-246, True North
Vertical (TVD) Reference:L-246 as staked @ 73.70usft
Measured Depth Reference:L-246 as staked @ 73.70usft
Calculation Method: Minimum Curvature
Project:Prudhoe Bay
Site:L
Well:Plan: L-246
Wellbore:L-246
Design:L-246 wp04
CASING DETAILS
TVD TVDSS MD Size Name
4475.95 4402.25 5850.00 9-5/8 9 5/8" x 12 1/4"
3883.60 3809.90 20294.19 4-1/2 4 1/2" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00
2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD
3 500.00 6.00 265.00 499.63 -0.91 -10.42 3.00 265.00 9.24 Start Dir 4º/100' : 500' MD, 499.63'TVD
4 950.00 24.00 265.00 932.52 -11.02 -125.97 4.00 0.00 111.65
5 1201.54 34.06 264.38 1152.18 -22.41 -247.34 4.00 -2.00 218.92 End Dir : 1201.54' MD, 1152.18' TVD
6 4508.14 34.06 264.38 3891.62 -203.83 -2090.20 0.00 0.00 1844.40 Start Dir 5º/100' : 4508.14' MD, 3891.62'TVD
7 5698.07 87.00 298.27 4468.47 69.99 -3031.19 5.00 40.26 2817.57 End Dir : 5698.07' MD, 4468.47' TVD
8 5798.07 87.00 298.27 4473.70 117.29 -3119.14 0.00 0.00 2917.01 L-246 wp01 tgt1 Start Dir 2º/100' : 5798.07' MD, 4473.7'TVD
9 5986.67 90.77 298.27 4477.37 206.58 -3285.19 2.00 0.00 3104.75
10 11082.95 90.77 298.27 4408.70 2620.09 -7773.20 0.00 0.00 8179.02 L-246 wp01 tgt2
11 11133.40 91.76 298.06 4407.59 2643.90 -7817.66 2.00 -11.83 8229.25
12 15168.32 91.76 298.06 4283.70 4541.20 -11376.53 0.00 0.00 12246.54 L-246 wp01 tgt3
13 15224.10 90.65 298.18 4282.53 4567.49 -11425.71 2.00 174.10 12302.08
14 18207.17 90.65 298.18 4248.70 5976.02 -14055.09 0.00 0.00 15272.79 L-246 wp01 tgt4
15 18296.75 90.92 296.41 4247.47 6017.08 -14134.68 2.00 -81.15 15362.11
16 19149.74 90.92 296.41 4233.70 6396.40 -14898.57 0.00 0.00 16213.48 L-246 wp02 tgt5
17 20294.19 125.26 296.41 3883.60 6873.02 -15858.41 3.00 0.00 17283.25 Total Depth : 20294.19' MD, 3883.6' TVD
-3000
-2000
-1000
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
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-17000 -16000 -15000 -14000 -13000 -12000 -11000 -10000 -9000 -8000 -7000 -6000 -5000 -4000 -3000 -2000 -1000 0 1000
West(-)/East(+) (2000 usft/in)
L-246 wp02 tgt5
L-246 wp01 tgt3
L-246 wp01 tgt2
L-246 wp01 tgt4
L-246 wp01 tgt1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
2501
0
0
0
1
50
0
2
00
0
2
50
0
30
0
0
3
75
0
4000
4250
3884
L-246 wp04
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 4º/100' : 500' MD, 499.63'TVD
End Dir : 1201.54' MD, 1152.18' TVD
Start Dir 5º/100' : 4508.14' MD, 3891.62'TVD
End Dir : 5698.07' MD, 4468.47' TVD
Start Dir 2º/100' : 5798.07' MD, 4473.7'TVD
Begin Geosteering lateral
Total Depth : 20294.19' MD, 3883.6' TVD CASING DETAILS
TVD TVDSS MD Size Name
4475.95 4402.25 5850.00 9-5/8 9 5/8" x 12 1/4"
3883.60 3809.90 20294.19 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: L
Well: Plan: L-246
Wellbore: L-246
Plan: L-246 wp04
WELL DETAILS: Plan: L-246
47.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5977994.19 582801.96 70° 20' 59.4982 N 149° 19' 39.9130 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-246, True North
Vertical (TVD) Reference:L-246 as staked @ 73.70usft
Measured Depth Reference:L-246 as staked @ 73.70usft
Calculation Method:Minimum Curvature
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0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175
Measured Depth (650 usft/in)
L-112
L-114B
L-114A
L-247 wp03
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: L-246 NAD 1927 (NADCON CONUS)Alaska Zone 04
47.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5977994.19 582801.96 70° 20' 59.4982 N 149° 19' 39.9130 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-246, True North
Vertical (TVD) Reference:L-246 as staked @ 73.70usft
Measured Depth Reference:L-246 as staked @ 73.70usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-05-18T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
26.50 1500.00 L-246 wp04 (L-246) GYD_Quest GWD
1500.00 5850.00 L-246 wp04 (L-246) 3_MWD+IFR2+MS+Sag
5850.00 20294.19 L-246 wp04 (L-246) 3_MWD+IFR2+MS+Sag
0.00
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60.00
90.00
120.00
150.00
180.00
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0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175
Measured Depth (650 usft/in)
L-287 wp02
L-254
L-293
L-295 wp05
L-253
NO GLOBAL FILTER: Using user defined selection & filtering criteria
26.50 To 20294.19
Project: Prudhoe Bay
Site: L
Well: Plan: L-246
Wellbore: L-246
Plan: L-246 wp04
Ladder / S.F. Plots
1 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4475.95 4402.25 5850.00 9-5/8 9 5/8" x 12 1/4"
3883.60 3809.90 20294.19 4-1/2 4 1/2" x 8 1/2"
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6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250
Measured Depth (1500 usft/in)
L-112A
L-114B
L-247 wp03
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: L-246 NAD 1927 (NADCON CONUS)Alaska Zone 04
47.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5977994.19 582801.96 70° 20' 59.4982 N 149° 19' 39.9130 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-246, True North
Vertical (TVD) Reference:L-246 as staked @ 73.70usft
Measured Depth Reference:L-246 as staked @ 73.70usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-05-18T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
26.50 1500.00 L-246 wp04 (L-246) GYD_Quest GWD
1500.00 5850.00 L-246 wp04 (L-246) 3_MWD+IFR2+MS+Sag
5850.00 20294.19 L-246 wp04 (L-246) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250
Measured Depth (1500 usft/in)
NO GLOBAL FILTER: Using user defined selection & filtering criteria
26.50 To 20294.19
Project: Prudhoe Bay
Site: L
Well: Plan: L-246
Wellbore: L-246
Plan: L-246 wp04
Ladder / S.F. Plots
2 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4475.95 4402.25 5850.00 9-5/8 9 5/8" x 12 1/4"
3883.60 3809.90 20294.19 4-1/2 4 1/2" x 8 1/2"
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.
X
223-078
SCHRADER BLUF OIL
PRUDHOE BAY
PBU L-246
WELL PERMIT CHECKLIST
Company Hilcorp North Slope, LLC
Well Name:PRUDHOE BAY UN ORIN L-246
Initial Class/Type SER / PEND GeoArea 890 Unit 11650 On/Off Shore On
Program SERField & Pool Well bore seg
Annular DisposalPTD#:2230780
PRUDHOE BAY, KUPARUK RIVER OIL - 64014
NA1 Permit fee attached
Yes ADL028239 and ADL0474492 Lease number appropriate
Yes3 Unique well name and number
Yes PRUDHOE BAY, SCHRADER BLUF OIL - 640135 - governed by 505B, 505B.0044 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
NA6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
No Pending issuance of CO 505C (Expansion of Schrader Bluff Oil Pool)11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
No Pending issuance of AIO 26C (Expansion of Schrader Bluff Oil Pool)14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For
Yes15 All wells within 1/4 mile area of review identified (For service well only)
Yes Planned for 30 days of pre-production via jet pump16 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 114'18 Conductor string provided
Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWs
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csg
Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir22 CMT will cover all known productive horizons
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.23 Casing designs adequate for C, T, B & permafrost
Yes Innovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pit
Yes This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approved
Yes Halliburton collision scan shows no close approaches.26 Adequate wellbore separation proposed
Yes 16" Diverter below BOPE27 If diverter required, does it meet regulations
Yes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequate
Yes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulation
Yes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)
Yes Innovation has 2-9/16" piper ball valves, 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)
Yes32 Work will occur without operation shutdown
Yes PBU L pad has H2S history. Monitoring will be required.33 Is presence of H2S gas probable
Yes34 Mechanical condition of wells within AOR verified (For service well only)
No PBU L-pad is H2S bearing. Max reading at L-203 (2021) is 300ppm.35 Permit can be issued w/o hydrogen sulfide measures
Yes No overpressure anticipated. Gas hydrates and associated free gas expected in 12.25" hole section36 Data presented on potential overpressure zones
NA37 Seismic analysis of shallow gas zones
NA38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
ADD
Date
8/23/2023
Appr
MGR
Date
8/28/2023
Appr
ADD
Date
8/23/2023
Administration
Engineering
Geology
Geologic
Commissioner:Date:Engineering
Commissioner:Date Public
Commissioner Date
*&:
