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From:Wallace, Chris D (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: OPERABLE: WAG Injector L-252 (PTD #2230950) passed AOGCC MIT-IA
Date:Monday, February 2, 2026 4:40:18 PM
From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent: Monday, February 2, 2026 4:33 PM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB
Wells Integrity <PBWellsIntegrity@hilcorp.com>
Subject: OPERABLE: WAG Injector L-252 (PTD #2230950) passed AOGCC MIT-IA
Mr. Wallace,
An AOGCC MIT-IA passed to 2,295 psi on 02/01/26. The well will now be classified as OPERABLE.
Please respond with any questions.
Andy Ogg
Hilcorp Alaska LLC
Field Well Integrity
andrew.ogg@hilcorp.com
P: (907) 659-5102
M: (307) 399-3816
From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Sent: Friday, January 16, 2026 1:23 PM
To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Subject: [EXTERNAL] RE: UPDATE UNDER EVALUATION: WAG Injector L-252 (PTD #223095)
Anomalous IA casing pressure
Ryan,
Your request for an additional 28 days for monitoring and diagnostics is approved.
Thanks and Regards,
Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907)
793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska
Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure
of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please
delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you,
contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov.
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent: Friday, January 16, 2026 10:46 AM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Subject: UPDATE UNDER EVALUATION: WAG Injector L-252 (PTD #223095) Anomalous IA casing
pressure
Mr. Wallace,
WAG Injector L-252 (PTD # 223095) current 28 day under evaluation period expires on
01/19. Due to a combination of rig spacing / access (currently drilling L-287) and weather
delay, we would like to request an additional 28 days to perform online witnessed
AOGCC MIT-IA on L-252. The well remains on stable PWI injection with stable injection
rate / temperature and casing pressure.
Please call with any questions or concerns,
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659-5102
M: (907) 232-1005
From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent: Monday, December 22, 2025 5:03 PM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: jim.regg <jim.regg@alaska.gov>; Oliver Sternicki <oliver.sternicki@hilcorp.com>; Torin
Roschinger <torin.roschinger@hilcorp.com>
Subject: UNDER EVALUATION: WAG Injector L-252 (PTD #223095) Anomalous IA casing pressure
Mr. Wallace,
WAG Injector L-252 (PTD # 223095) has been observed to experience an abrupt IA
pressure drop from 250 psi to 10 psi while on PWI with no corresponding shift in injection
rate, temperature, or pressure. There has been no change in surface OA casing
pressure. The well is now classified as UNDER EVALUATION and on a 28 day clock to be
resolved.
Plan Forward:
1. Fullbore: MIT-IA
2. Well Integrity: Further diagnostics as required.
Please call with any questions or concerns.
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659-5102
M: (907) 232-1005
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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:Wallace, Chris D (OGC)
To:PB Wells Integrity
Subject:RE: UPDATE UNDER EVALUATION: WAG Injector L-252 (PTD #223095) Anomalous IA casing pressure
Date:Friday, January 16, 2026 1:23:35 PM
Attachments:L-252.docx
Ryan,
Your request for an additional 28 days for monitoring and diagnostics is approved.
Thanks and Regards,
Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907)
793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska
Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure
of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please
delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you,
contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov.
From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent: Friday, January 16, 2026 10:46 AM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Subject: UPDATE UNDER EVALUATION: WAG Injector L-252 (PTD #223095) Anomalous IA casing
pressure
Mr. Wallace,
WAG Injector L-252 (PTD # 223095) current 28 day under evaluation period expires on
01/19. Due to a combination of rig spacing / access (currently drilling L-287) and weather
delay, we would like to request an additional 28 days to perform online witnessed
AOGCC MIT-IA on L-252. The well remains on stable PWI injection with stable injection
rate / temperature and casing pressure.
Please call with any questions or concerns,
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659-5102
M: (907) 232-1005
From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent: Monday, December 22, 2025 5:03 PM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: jim.regg <jim.regg@alaska.gov>; Oliver Sternicki <oliver.sternicki@hilcorp.com>; Torin
Roschinger <torin.roschinger@hilcorp.com>
Subject: UNDER EVALUATION: WAG Injector L-252 (PTD #223095) Anomalous IA casing pressure
Mr. Wallace,
WAG Injector L-252 (PTD # 223095) has been observed to experience an abrupt IA
pressure drop from 250 psi to 10 psi while on PWI with no corresponding shift in injection
rate, temperature, or pressure. There has been no change in surface OA casing
pressure. The well is now classified as UNDER EVALUATION and on a 28 day clock to be
resolved.
Plan Forward:
1. Fullbore: MIT-IA
2. Well Integrity: Further diagnostics as required.
Please call with any questions or concerns.
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659-5102
M: (907) 232-1005
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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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:Wallace, Chris D (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: UNDER EVALUATION: WAG Injector L-252 (PTD #223095) Anomalous IA casing pressure
Date:Tuesday, December 23, 2025 7:40:57 AM
Attachments:L-252.docx
From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent: Monday, December 22, 2025 5:03 PM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>;
Torin Roschinger <Torin.Roschinger@hilcorp.com>
Subject: UNDER EVALUATION: WAG Injector L-252 (PTD #223095) Anomalous IA casing pressure
Mr. Wallace,
WAG Injector L-252 (PTD # 223095) has been observed to experience an abrupt IA
pressure drop from 250 psi to 10 psi while on PWI with no corresponding shift in injection
rate, temperature, or pressure. There has been no change in surface OA casing
pressure. The well is now classified as UNDER EVALUATION and on a 28 day clock to be
resolved.
Plan Forward:
1. Fullbore: MIT-IA
2. Well Integrity: Further diagnostics as required.
Please call with any questions or concerns.
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659-5102
M: (907) 232-1005
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No 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. 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-252
Patch Tubing, Convert to Injection
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
223-095
50-029-23768-00-00
17211
Conductor
Surface
Intermediate Tiebac
Production
Liner / Slotted Liner
4475
80
8228
6759
10437
17209
20"
9-5/8"
7"
7" x 4-1/2"
4475
27 - 107
26 - 8254
24 - 6783
6774 - 17211
27 - 107
26 - 4457
24 - 4077
4073 - 4475
None
4760 / 3090
5410
5410 / 7500
None
6870 / 5750
7240
7240 / 8430
8398 - 17178
4-1/2" 12.6# L-80 22 - 8206
4459 - 4465
Structural
4-1/2" HES TNT Perm Packer 6838, 4102
6838
4102
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 0028239, 0028241
22 - 4456
N/A
N/A
276 27 1192
2878
150
800
300
211
323-670
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 11:29 am, Apr 08, 2024
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2024.04.05 17:03:57 -08'00'
Torin
Roschinger
(4662)
RBDMS JSB 041024
WCB 2024-07-09
DSR-4/12/24
ACTIVITY DATE SUMMARY
3/1/2024
***WELL S/I ON ARRIVAL*** (NEW WELL POST)
RAN 10' x 3.00" PUMP BAILER(msfb) TO JET PUMP @ 6,773' MD(no recovery,
metal marks on bottom)
PULLED 4-1/2" JET PUMP w/ DUAL GUAGES ON BOTTOM FROM DURASLEEVE
SSD @ 6,773' MD
RAN 4-1/2" BRUSH, 3.80" G-RING, MADE SEVERAL BRUSH PASSES THROUGH
X-NIP @ 3,594' MD, THROUGH SSD @ 6,773' MD, AND X-NIP @ 6,912' MD
RAN 4-1/2'' X-LINE, 4-1/2'' x 2-7/8'' NIP. REDUCER TO SET @ 6912' MD
RAN CHECK SET TO NIP. REDUCER @ 6912' MD (Good)
***WSR CONT. ON 03-02-2024***
3/2/2024
T/I/O=170/136/0 (NEW WELL POST) Assist SL: Load IA - Loaded IA with 9 bbls of
60/40, 82 bbls of Inhibited Brine, and 101 bbls of Diesel. PT'd plug for SL with 8.5
bbls of Diesel.
SL in control of well upon departure.
FWHPs= 320/210/0
***Man Down Drill Cold Weather***
3/2/2024
***WSR CONT. FROM 03-01-2024***
RAN 4-1/2" 42 BO TO SHIFT DURASLEEVE SSD SHUT AT 6,773' MD
SET 2.31" XX PLUG IN 4-1/2" x 2-7/8" NIPPLE REDUCER AT 6,912' MD
LRS PERFORMED COMBO PRESSURE TEST (see lrs log)
PULLED 2-7/8" XX-PLUG BODY FROM 4-1/2" x 2-7/8" NIPPLE REDUCER @ 6,912'
MD
***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED OF WELL STATUS***
3/18/2024
******WELL S/I ON ARRIVAL*** (SET 3.68'' NS LOWER PATCH)
RIG UP YJ ELINE.
MAN DOWN DRILL
PT PCE 300 PSI LOW /3000 PSI HIGH
SET LOWER PATCH ME AT 5575' ELM, TOP OF PACKER AT 5573', BOTTOM OF
PACKER AT 5580'
CCL TO MID ELEMENT 9.8' CCL STOP DEPTH 5565.2'
CCL LOG CORRELATE TO READ LDL SURVEY DATED 25-NOV-2024
JOB COMPLETE
**WELL S/I ON DEPARTURE***
3/26/2024
***WELL S/I ON ARRIVAL***
SET NS 450-668 MONO-PAK UPPER STRADDLE, 2-7/8'' STL, NSAK-SNAP LATCH
3'' SEAL ( OAL LIH 18'.47'') ON LOWER STRADDLE @ 5575' SLM (see log)
PULLED & RE-SET NS 450-668 MONO-PAK UPPER STRADDLE, 2-7/8'' STL,
NSAK-SNAP LATCH 3'' SEAL ( OAL LIH 18'.47'') ON LOWER STRADDLE @ 5575'
SLM (see log)
RAN 45 KB TEST TOOL FOR HYD SETTING PACKER(3.20" no go, 3.00" seal, 46"
oal). S/D IN UPPER PACKER @ 5,554' SLM (see log)
LAY DOWN FOR WINDS
WELL CONTROL DILL w/ NIGHT CREW & WSL
***START WEATHER TICKET ON 3-27-24***
Daily Report of Well Operations
PBU L-252
SET NS 450-668 MONO-PAK UPPER STRADDLE, 2-7/8'' STL, NSAK-SNAP LATCH
3'' SEAL ( OAL LIH 18'.47'') ON LOWER STRADDLE @ 5575' SLM (see log)() @(g)
PULLED & RE-SET NS 450-668 MONO-PAK UPPER STRADDLE, 2-7/8'' STL,
NSAK-SNAP LATCH 3'' SEAL ( OAL LIH 18'.47'') ON LOWER STRADDLE @ 5575'
SLM (see log)
Daily Report of Well Operations
PBU L-252
3/28/2024
***WELL S/I ON ARRIVAL***
RAN 45 KB TEST TOOL FOR HYD SETTING PACKER(3.20" no go, 3.00" seal, 46"
oal) S/D IN UPPER PACKER @ 5,555' MD (2bpm not catching psi)
RAN 4-1/2" D&D HOLE FINDER TO TOP OF PACKER @ 5,555' MD &
PRESSURED UP TBG TO 1800psi
STEMMED UP & RAN 45 KB TEST TOOL FOR HYD SETTING PACKER(3.20" no
go, 3.00" seal, 46" oal) S/D IN UPPER PACKER @ 5,555' MD (pressured up)
LRS PERFORMED PASSING PT ON IA TO 3500 psi (see lrs log)
***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED OF WELL STATUS***
3/28/2024
T/I/O= 266/100/5 Assist Slickline (New Well Post) Pumped 25 bbls of crude down
tubing and caught pressure. Came online to assist setting the packer at 2 bpm
Pumped a totaol of 90 bbls and no indication packer set. SL ran D&D hole finder to
top of packer. Casme online and tbg pressured up to 1800 psi. Bled down and
slickline swapped tools to run the 45 KB test tool. Pressured up to 200 psi. Ran
jumper to IA and pumped 2.6 bbls of crude down IA to 3539 psi. 1st 15 min IA lost 38
psi and 12 psi 2nd 15 mins for a total loss of 50 pis in 30 mins. PT Passed. Bled IA
down to 500 psi..FWHP = 108/489/7. Pad Op notified upon departure. Slickline on
well upon departure.
3/30/2024
T/I/O= 414/611/0 Temp= SI AOGCC MIT IA PASSED to 3656 psi.(Witnessed by
AOGCC Inspector Sully Sullivan) Pumped 2.3 bbls of diesed down IA to achieve test
pressure. IA lost 120 psi 1st 15 mins and lost 24 psi 2nd 15 mins for a total loss lof
144 in 30 mins. Bled back ~ 2.1 bbls. Final WHPs 413/596/0.
3/30/2024
T/I/O = 420/611/0 . Temp = SI. TBG FL (WIE request). No AL. TBG FL @ 840' (12
bbls).
LRS in control of well upon departure. 09:50.
4/2/2024
T/I/O = 191/613/107 Temp= On inj AOGCC PASSED to 1665 psi (Witnessed by
AOGCC Inspector Sully Sullivan) Pumped 0.75 bbls of warm diesel down IA to
achieve test pressure. IA lost 43 psi 1st 15 mins and 0 psi 2nd 15 mins for a total loss
of 43 psi in 30 mins. Bled back 0.7 bbls. FWHP = 195/699/133. Pad Op notified upon
departure.
AOGCC MIT IA PASSED to 3656 psi.(Witnessed by
AOGCC Inspector Sully Sullivan)
AOGCC PASSED to 1665 psi (Witnessed by
AOGCC Inspector Sully Sullivan)
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-252 223095 500292376800 17 3/23/2024
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, May 21, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Sully Sullivan
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
L-252
PRUDHOE BAY UN ORIN L-252
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 05/21/2024
L-252
50-029-23768-00-00
223-095-0
W
SPT
4102
2230950 1500
195 194 195 195
125 277 271 272
OTHER P
Sully Sullivan
4/2/2024
MIT-IA Post Patch and stabalization. Per Sundry # 323-670
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-252
Inspection Date:
Tubing
OA
Packer Depth
633 1708 1665 1665IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSTS240403154226
BBL Pumped:0.8 BBL Returned:0.7
Tuesday, May 21, 2024 Page 1 of 1
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Friday, April 12, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Sully Sullivan
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
L-252
PRUDHOE BAY UN ORIN L-252
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 04/12/2024
L-252
50-029-23768-00-00
223-095-0
N
SPT
4102
2230950 3500
414 416 416 416
0 1 1 1
OTHER P
Sully Sullivan
3/30/2024
Offline MITIA per Sundry 323-670 for the purpose of converting to an injector.
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-252
Inspection Date:
Tubing
OA
Packer Depth
611 3800 3680 3656IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSTS240331092919
BBL Pumped:2.3 BBL Returned:2.1
Friday, April 12, 2024 Page 1 of 1
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:Clint Montague - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:PB Wells Integrity; Aras Worthington
Subject:PBU L-252 10-426
Date:Thursday, November 23, 2023 11:47:13 AM
Attachments:PBU L-252 10-426 (4).xlsx
Some people who received this message don't often get email from cmontague@hilcorp.com. Learn why this isimportant
Attached is form 10-426 for L-252. Let me know if you have any questions.
Clint Montague
Hilcorp DSM Innovation
907-670-3094 Office
907-394-0776 Cell
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
PBU L-252
PTD 2230950
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-095 Type Inj N Tubing 23 3694 3612 3595 Type Test P
Packer TVD 4101 BBL Pump 2.0 IA 0 348 347 331 Interval I
Test psi 3500 BBL Return 2.0 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-095 Type Inj N Tubing 25 635 803 939 Type Test P
Packer TVD 4101 BBL Pump 2.4 IA 12 3724 3577 3480 Interval I
Test psi 3500 BBL Return 2.2 OA 0 216 200 175 Result F
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-095 Type Inj N Tubing 0 3690 3644 3632 Type Test P
Packer TVD 4101 BBL Pump 2.9 IA 0 3690 3644 3632 Interval I
Test psi 3500 BBL Return 2.9 OA 0 232 238 234 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
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:Failed MIT-IA
L-252
Notes:Combined MIT-T/IA to ensure integrity of packer.
Notes:
Hilcorp Alaska LLC
Prudhoe Bay / West Side / L Pad
Witness Waived by Guy Cook
Clinton Montague
11/22/23
Notes:
Notes:
Notes:
Notes:
L-252
L-252
Form 10-426 (Revised 01/2017)2023-1122_MIT_PBU_L-252_3tests
J. Regg; 5/6/2024
7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in this pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd?Yes No
Subsequent Form Required:
Approved By:Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU L-252
Patch Tubing, Convert
to Injection
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK
99503
223-095
50-029-23768-00-00
CO 505B
ADL 0028239, 0028241
17211
Conductor
Surface
Intermediate Tiebac
Production
Liner / Slotted Liner
4475
80
8228
6759
10437
17209
20"
9-5/8"
7"
7" x 4-1/2"
4475
27 - 107
26 - 8254
24 - 6783
6774 - 17211
1581
27 - 107
26 - 4457
24 - 4077
4073 - 4475
None
4760 / 3090
5410
5410 / 7500
None
6870 / 5750
7240
7240 / 8430
8398 - 17178 4-1/2" 12.6# L-80 L-80 22 - 82064459 - 4465
Structural
4-1/2" HES TNT Perm Packer
No SSSV Installed
6838, 4102
Date:
Torin Roschinger
Operations Manager
Aras Worthington
aras.worthington@hilcorp.com
907-564-4763
PRUDHOE BAY
1/1/2024
Current Pools:
SCHRADER BLUFF, Orion Dev Area
Proposed Pools:
SCHRADER BLUFF, Orion Dev 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
By Grace Christianson at 1:44 pm, Dec 15, 2023
Digitally signed by Aras
Worthington (4643)
DN: cn=Aras Worthington (4643)
Date: 2023.12.15 10:34:54 -
09'00'
Aras
Worthington
(4643)
323-670
1581
* MIT-IA to 3500 psi. 24 hour notice for state to witness.
* MIT-IA to 1500 psi after 10 days of stabilized injection.
DSR-12/18/23
10-404
MGR18DEC23 SFD 12/19/2023
505C SFD
, Convert
to Injection
*&:
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.12.20 11:24:41 -09'00'12/20/23
RBDMS JSB 122623
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
Well Name:L-252 API Number:50-029-23768-00-00
Current Status:Producer Rig:SL, EL, FB
Estimated Start Date:January 2024 Estimated Duration:14 days
Sundry #Date Approval Rec’vd:
Regulatory Contact:Abbie Barker New PTD Number:223-095
First Call Engineer:Aras Worthington (907) 564-4763 907.440.7692 (Cell)
Current Bottom Hole Pressure:
Max Bottom Hole Pressure:
Max. Proposed Surface Pressure:
Min ID:
1969 psi @ 3,884’ TVD 1969
psi @ 3,884’ TVD
1581 psi
3.813” X-Nipple at 3694’ MD
(Estimated)
(Estimated)
(Estimated based on .1psi/ft)
Brief Well Summary:
L-252i was drilled as an OBd injector. The AOGCC granted 60 days of pre-production via jet pump. The MITT
on-rig passed but the MITIA failed, indicating IA x Tubing communication. This was confirmed by an MITIA
attempt post-rig which yielded a LLR of ~1 gpm @ 3500 psi, and the tubing pressuring up throughout the MIT
and LLR test. A Leak-Detect-Log was performed indicating a leak in a tubing collar at 5,566’ MD.
Because the leak rate in the tubing was very small, Hilcorp sought and acquired approval from the AOGCC to
pre-produce the well with the tubing leak and then patch the leak after pre-production is complete.
Objective:Pull Jet Pump after 60-day pre-production period has ended. Close the sliding sleeve. Install a
tubing patch over the collar leak in the tubing. MITIA to 3500 psi. Convert the well to an Injector.
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
AOR:
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
Procedure:
Slickline- Pull Jet Pump and close SSD
1. Pull Jet Pump from ~6,773’ MD.
2. Load the IA with inhibited 1% KCL and FP with diesel.
3. RIH with 4.5” sleeve shifting tool and close SSD @ 6,773’ MD.
4. Set 4-1/2” x 2-7/8” nipple reducer in the X-nipple @ 6,912’ MD.
E-Line – Set tubing patch
1. Set patch with mid-element (ME) at 5,560’ MD and 5,571’ MD. Reference attached LDL.
Fullbore - MITs
1. Perform AOGCC witnessed MITIA to 3500 psi.
2. Perform AOGCC witnessed online MITIA to 1500 psi after injection stabilizes.
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Leak-Detect-Log
4. Tubing Patch Schematic
5. Sundry Change Form
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
Current Schematic
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
Proposed Schematic
5560’– 5571’ –Tubing Patch
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
Patch Tubing, Convert to Injector
Well:L-252
PTD: 223-095
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By Grace Christianson at 11:56 am, Dec 15, 2023
Completed
11/23/2023
JSB
RBDMS JSB 010224
GDSR-1/29/24SFD 12/11/2025
Drilling Manager
12/12/23
Monty M
Myers
Digitally signed by Aras
Worthington (4643)
DN: cn=Aras Worthington (4643)
Date: 2023.12.15 11:34:45 -
09'00'
Aras
Worthington
(4643)
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU L-252 Date:11/14/2023
Csg Size/Wt/Grade:9 5/8 47 & 40 #L-80 Supervisor:James Lott
Csg Setting Depth:8251 TMD 4457 TVD
Mud Weight:9.2 ppg LOT / FIT Press =653 psi
LOT / FIT =12.02 ppg Hole Depth =8279 md
Fluid Pumped=1.6 Bbls Volume Back =1.4 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter P9.15ressure Enter Strokes 665
Here Here Here Here
->06 ->00
->240 ->262
->4 126 ->473
->6 190 ->6128
->8 242 ->8165
->10 288 ->10 203
->12 332 ->12 250
->14 372 ->14 300
->16 418 ->16 350
->18 454 ->18 394
->20 487 ->20 440
->22 518 ->45 1050
->26 606 ->90 2200
->30 653 ->109 2662
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 653 ->0 2662
->1 538 ->5 2630
->2 537 ->10 2624
->3 525 ->15 2619
->4 514 ->20 2614
->5 506 ->25 2610
->6 498 ->30 2605
->7 491 ->
->8 483 ->
->9 477 ->
->10 472 ->
-> ->
-> ->
-> ->
0
2
4
6
8
10
12
14
16
18
20
22
26
30
0
2 4
6
8
10
12
14
16
18
20
45
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 102030405060708090100110120
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
653
538537525514506498491483477472
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 5 10 15 20 25 30
Pr
e
s
s
u
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e
(
p
s
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)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
ACTIVITYDATE SUMMARY
11/22/2023
Assist I-Rig w/ Freeze Protect IA. Pumped 72 bbls 60* DSL into IA. Rig in-control of
well upon departure.
11/22/2023
M/U TBG HGR to string, RIH, land at verified RKB. RILDS. Set 4" CTS / BPV, S/B
for N/D BOP. Clean void, inspect TBG HGR neck and lift threads. install SBMS,
CTS BPV and ring gasket. N/U THA & DHT. R/U test equipment and test void to
500/5000 psi for 10 min each. passed. Assist w/ tree test. passed Pull CTS plug,
CTS BPV.
11/23/2023
T/I/O=10/25/0 MIT IA (post rig) Pressured IA to 3500 psi with 3.62 bbls crude. 1st
15 min lost 204 psi, 2nd 15 min lost 151 psi fro a total loss of 255 psi in 30 min test.
Tbg pressure increased from 10 psi to 796 psi. repressured IA to 3500 psi with .68
bbls crude for a LLR of 1.05 GPM. Bleed back IA 635/22/0
11/24/2023
T/I/O= 565/10/0 (NEW WELL POST) Assist SL, troubleshoot IA - MIT-IA
***FAILED*** LLR of .56 gpm. Pumped 4.75 bbls of Crude to troubleshoot IA. Bled
back ~2 bbls.
SL in control of well upon departure.
FWHPs= 150/150/0
11/24/2023
***WELL S/I ON ARRIVAL*** (New well post)
RAN 3.81" 42BO, 8' x 1.75" STEM, 3.81" 42 BO TO SSD AT 6,773' MD (open &
closed multiple times)
LRS PERFORMED FAILING MIT-IA (established LLR of .56 gpm)
***WELL S/I ON DEPARTURE***
11/25/2023
***WELL S/I UPON ARRIVAL***
T-BIRD PRESSURE UP IA TO 3500 IA;
READ STOP COUNTS EVERY 5' FROM 6793' TO 6758;
START UP PASS FROM 6890' TO SURFACE
LEAK DETECTED AT 5566'
STOP COUNTS EVERY 5' FROM 5586' TO 5556'
4BBL PUMPED
LEAK RATE 0.7 GAL/MIN
***WELL S/I UPON DEPARTURE***
11/25/2023
***WELL S/I UPON ARRIVAL***
MIRU HES
MIRU READ
MIRU T-BIRD
11/25/2023
T/I/O= 0/112/0 (Assist Eline w/ LDL) TFS U3. Pumped 4 bbls of crude down the IA
keeping 3500 psi on IA and bleeding TBG down as needed . Established LLR of (~0.7
GPM). Well left in control of eline upon departure
11/27/2023 LRS 70 Assist Slickline (NEW WELL POST) ***Job Continued to 11-28-2023***
11/27/2023
***WELL S/I ON ARRIVAL*** (New well post)
RAN 42 BO TO SHIFT SSD OPEN AT 6,773' MD
PULLED BALL & ROD FROM RHC BODY AT 6,911' MD
***CONTINUED ON 11/28/23 WSR***
11/28/2023
***CONTINUED FROM 11/27/23 WSR*** (New well post)
LRS PUMP DOWN IA AT 2BBLS PER MINUTE TO VERIFY SSD OPEN
PULLED RHC PLUG BODY FROM 6,911' MD
SET 4 1/2" JETPUMP & GAUGES(11'-6") IN SSD AT 6,773'MD
RAN 4 1/2 X CHECK SET TO JETPUMP(Sheared)
LRS PUMPED DOWN IA TO VERIFY FLOW THROUGH JET PUMP
***WELL S/I ON DEPARTURE***
Daily Report of Well Operations
PBU L-252
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: 12/05/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: PBU L-252
PTD: 223-095
API: 50-029-23768-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (11/02/2023 to 11/17/2023)
x ROP, BST (GR), RST (EWR), DGR, ABG, ADR (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
LWD Subfolders:
Geosteering Subfolders:
Please include current contact information if different from above.
PTD: 223-095
T38202
12/6/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.06
09:35:30 -09'00'
From:Rixse, Melvin G (OGC)
To:Aras Worthington
Cc:Torin Roschinger; Tyson Shriver; Oliver Sternicki
Subject:20231127 1410 Approval PBU L-252 PTD #223-095
Date:Monday, November 27, 2023 2:11:29 PM
Attachments:image001.png
image002.png
Aras,
Hilcorp is approved to pre-produce well PTD22-095 PBU L-252 for 60 days on jet pump. After 60 days of pre-production the tubing
leak will be patched prior to putting the well on injection.
Your summary procedure below is approved.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is
for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you,
contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Torin Roschinger, Tyson Shriver, Oliver Sternicki
From: Aras Worthington <Aras.Worthington@hilcorp.com>
Sent: Monday, November 27, 2023 1:48 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Torin Roschinger <Torin.Roschinger@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com>; Oliver Sternicki
<Oliver.Sternicki@hilcorp.com>
Subject: PBU L-252 PTD #223-095
Mel,
Diagnostics over the weekend yielded the following:
1. The LLR from the IA to the tubing is very small (0.7 gpm @ ~3500 psi)
2. The leak is in a tubing collar @ 5,566’ MD (screenshot below, full log attached)
3. The leak appears to be one-way (MITT passes, MITIA fails)
We propose the following path forward:
1. Install the jet pump for pre-production
2. Put the well online for pre-production in its current state (the very small leak will not materially affect the jet pump performance
and the integrity of the completion as a producer is not affected by the one-way tubing leak because the jet pump allows
communication to the IA regardless)
3. When the pre-production period is over, pull the jet pump and patch the tubing
4. Perform AOGCC witnessed MITIA to verify two-barriers for service as an injector
5. Put the well on injection
Please advise if this path forward is acceptable to the AOGCC.
Thanks and best regards,
Aras Worthington
Sr. Operations Engineer, PE
Hilcorp North Slope
Aras.worthington@hilcorp.com
907-564-4763
907-440-7692 mobile
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Wednesday, November 22, 2023 3:30 PM
To: Aras Worthington Aras.Worthington@hilcorp.com
Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com>
Subject: [EXTERNAL] RE: PBU L-252 PTD #223-095
Aras,
I appreciate the notification. Hilcorp is approved to RDMO Innovation Rig to hut for the IA leak.
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.
Please inform AOGCC to the findings when diagnosis is complete.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is
for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you,
contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Oliver, Tyson Shriver
From: Aras Worthington <Aras.Worthington@hilcorp.com>
Sent: Wednesday, November 22, 2023 3:09 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com>
Subject: PBU L-252 PTD #223-095
Mel,
As discussed via phone below is the current status and the proposed plan forward for this well:
The well is completed as permitted (see schematic as-drilled/completed below)
After setting the production packer the on-rig MITT passed to 3500 psi
The on-rig MITIA failed with apparent communication to the tubing (may be a one-way leak)
A CMIT-TxIA passed to 3500 psi
a. The passing CMIT proves that the production packer and 7” tieback seals have integrity
We propose to move the rig off of the well and proceed with an MITIA post-rig, exercising the sliding sleeve, attempting another MITIA,
and if that fails proceed with a Leak-Detect-Log (LDL) and planning of repair options before pre-producing this injector.
We will keep you informed as this progresses.
Thanks and Best Regards,
Aras Worthington
Sr. Operations Engineer, PE
Hilcorp North Slope
Aras.worthington@hilcorp.com
907-564-4763
907-440-7692 mobile
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN ORIN L-252
JBR 01/12/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
Manual (inside) choke on mud cross FP
Test Results
TEST DATA
Rig Rep:Matt VanhooseOperator:Hilcorp North Slope, LLC Operator Rep:James Lott
Rig Owner/Rig No.:Hilcorp Innovation PTD#:2230950 DATE:11/12/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopAGE231115163316
Inspector Adam Earl
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7.5
MASP:
1515
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 2 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8 P
#1 Rams 1 2 7/8 x 5 1/2 P
#2 Rams 1 Blinds P
#3 Rams 1 7" solid body P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8 FP
HCR Valves 2 3 1/8 P
Kill Line Valves 3 3 1/8 P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P2975
Pressure After Closure P1425
200 PSI Attained P25
Full Pressure Attained P106
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@2342
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P11
#1 Rams P8
#2 Rams P8
#3 Rams P9
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9 999
9
9
9
9FP
Manual (inside) choke
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN ORIN L-252
JBR 12/13/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:Test was performed with 5" DP. All LEL & H2S alarms tested. PVT visual and audible alarms tested. Theres 20 back up nitrogen bottles which
were checked and topped off during the rig move.
TEST DATA
Rig Rep:Joel StureOperator:Hilcorp North Slope, LLC Operator Rep:James Lott
Contractor/Rig No.:Hilcorp Innovation PTD#:2230950 DATE:11/2/2023
Well Class:DEV Inspection No:divJDH231102141102
Inspector Josh Hunt
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 0
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:13.652 P
Hole Size:12.25 P
Vent Line(s) Size:16 P
Vent Line(s) Length:212 P
Closest Ignition Source:81 P
Outlet from Rig Substructure:200 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:14 P
Knife Valve Open Time:6 P
Diverter Misc:0 NA
Systems Pressure:P2850
Pressure After Closure:P1950
200 psi Recharge Time:P39
Full Recharge Time:P117
Nitrogen Bottles (Number of):P6
Avg. Pressure:P2316
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil, Orion Development Area, PBU L-252
Hilcorp Alaska, LLC
Permit to Drill Number: 223-095
Surface Location: 2281' FSL, 4101' FEL, Sec 34, T12N, R11E, UM, AK
Bottomhole Location: 957' FSL, 1542' FWL, Sec 09, T11N, 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 October 2023.
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.10.19 11:44:57
-08'00'
19
October 30, 2023
Drilling Manager
10/13/23
Monty M
Myers
By Grace Christianson at 8:41 am, Oct 13, 2023
MGR18OCT2023
223-095 50-029-23768-00-00
* BOPE test to 3000 psi. Annular to 2500 psi.
* MIT-IA to 3500 psi. 24 hour notice for opportunity state to witness
* MIT-IA to 3500 psi within 7 days of stabilized injection.
* Variance to 20 AAC 25.412(b) - Approved for packer placement >200' above the
Orion oil pool. Packer to be placed within the top confining zones of the Orion oil pool.
A.Dewhurst 17OCT23
DSR-10/13/23JLC 10/19/2023
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.10.19 11:45:22 -08'00'10/19/23
10/19/23
RBDMS JSB 102323
343332
345
1098
1617
L-01
L-01A
L-02
L-02A
L-03L-03APB1
L-04
L-100
L-101 L-103
L-105
L-106
L-108
L-109
L-110
L-111
L-114
L-114A
L-115
L-116
L-117
L-118
L-119
L-120
L-121
L-121A
L-122 L-123
L-124
L-201
L-201PB2
L-204
L-205
L-205A
L-205L1
L-205L2
L-205PB1
L-210
L-211PB1
L-213
L-215L-218
L-220
L-221
L-222
L-50
L-51
NWE1-01
WKUP
L-253
L-254
L-252_wp01
HILCORP NORTH SLOPE
Greater Prudhoe Bay
AOR MAP
L-252 Injector (Proposed)
FEET
0 1,000 2,000 3,000
POSTED WELL DATA
Well Label
WELL SYMBOLSINJ Well (Water Flood)
P&A Oil/Gas
J&A
Plugback
Active Oil
Injector Location
Shut in Injector
REMARKSWell Symbols at top of Schrader Bluff OBd sand (targetof proposed L-252 well). Black dashed circles andlines = 1320' radius from heel to toe of proposed L-252lateral injector
September 5, 2023
PETRA 9/5/2023 4:07:08 PM
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Prudhoe Bay Unit
L-252
Drilling Program
Version 1
10/11/2023
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 Unit
L-252 SB WAG
Drilling Procedure
1.0 Well Summary
Well PBU L-252
Pad "L" Pad
Planned Completion Type 4-1/2” Injection Tubing
Target Reservoir(s)SB OBd Sand
Planned Well TD, MD / TVD 16,742' MD / 4,359' TVD
PBTD, MD / TVD 16,732' MD / 4,359' TVD
Surface Location (Governmental) 2281' FSL, 4101' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582817 Y= 5977998
Top of Productive Horizon
(Governmental)1263' FNL, 1557' FWL, Sec 4, T11N, R11E, UM, AK
TPH Location (NAD 27) X= 577962 Y= 5974402
BHL (Governmental) 957' FSL, 1542' FWL, Sec 9, T11N, R11E, UM, AK
BHL (NAD 27) X= 578055 Y= 5966063
AFE Number 231-00134
AFE Drilling Days 21 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1515
Maximum Anticipated Pressure
(Downhole/Reservoir) 1961
Work String 5" 19.5# S-135 NC 50
Innovation KB Elevation above
MSL: 47.3 ft + 26.5 ft = 73.80 ft
GL Elevation above MSL: 47.3 ft
BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams
Page 3
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay Unit
L-252 SB WAG
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 Unit
L-252 SB WAG
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 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 workday to mmyers@hilcorp.com,jengel@hilcorp.com,
nathan.sperry@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
x
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 Marshall Brown 601-613-0173 henry.brown@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 10/10/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-252
Last Completed: TBD
PTD: TBD
TD =16,742’(MD) / TD =4,359’ (TVD)
20”
Orig. KB Elev.: 73.8’ / GL Elev.: 47.3’
7”
3
7
9-5/8”
1
2
See
Slotted
Liner
Detail
7”x
4-1/2”
XO
PBTD = 16,740’(MD) / PBTD = 4,359’ (TVD)
9-5/8” ‘ES’
Cementer @
~2,278’
4-1/2”
5
4
6
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 2,260’ 0.0732
9-5/8” Surface 40 / L-80 / VAM 21 8.835 2,260’ 8,350’ 0.0758
7” Tieback 26 / L-80 / BTC 6.276 Surface 6,850’ 0.0383
7” Liner 26 / L-80 Hyd 563 6.276 6,850’ 8,350 0.0383
4-1/2” Liner 12.6 / L-80 / H563 3.958 8,350’ 16,742’ 0.0155
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 /JEF BEAR 3.958 Surface 8,350’ 0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 840 sx / Tail – 395 sx
Stg 2 – Lead – 679 sx / Tail – 268 sx
8-1/2” Cementless Slotted Liner
WELL INCLINATION DETAIL
KOP @ 150’
90° Hole Angle = @ 7,350’ 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: 50-029-23752-00-00
Completion Date: TBD
JEWELRY DETAIL
No. Top MD Item ID
1 3,000’ X Nipple 3.813”
2 6,880’ X Nipple w/ Sliding Sleeve and Jet Pump 3.813”
3 6’850’ 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve
4 6,940’ Production Packer
5 7,000’ X Nipple 3.813”
6 8,350’ WLEG – Bottom
7 16,740’ 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 Unit
L-252 SB WAG
Drilling Procedure
7.0 Drilling / Completion Summary
L-252 is a grassroots injector planned to be drilled in the SB OBd Sand. L-252 is part of a multi well
program targeting the Schrader Bluff sand on "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 SB OBd Sand. 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-252 is planned to be pre-produced
for 60 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 October 30, 2023, pending rig schedule.
Surface casing will be run to 8,350’ MD / 4,456’ 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)
Page 8
Prudhoe Bay Unit
L-252 SB WAG
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 L-252. 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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Prudhoe Bay Unit
L-252 SB WAG
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 ~7215’ MD. The production packer will be
~50’ MD above the X nipple (set at 68*) which puts it at ~7000’ MD / ~4163’ TVD. The surface casing shoe is
planned at ~8350’ MD / 4456’ TVD which means the planned packer depth is ~1350’ MD away. From a TVD
standpoint, the production tubing packer is ~293’ 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.
Variance request to 20 AAC 25.412(b)
Production packer (in this case the 7" liner hanger) approved to be greater than 200' above top of perforations but
required to be placed in the upper confining zone of the Schrader Bluff Oil Pool - Orion - mgr
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Prudhoe Bay Unit
L-252 SB WAG
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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Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-252 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-252 SB WAG
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-252 SB WAG
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
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Prudhoe Bay Unit
L-252 SB WAG
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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Prudhoe Bay Unit
L-252 SB WAG
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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Prudhoe Bay Unit
L-252 SB WAG
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 Unit
L-252 SB WAG
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-252 SB WAG
Drilling Procedure
12.5 Float equipment and Stage tool equipment drawings:
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Prudhoe Bay Unit
L-252 SB WAG
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-252 SB WAG
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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Prudhoe Bay Unit
L-252 SB WAG
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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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 (8,350'-1,000'-2,500') x 0.0558 bpf x 1.3 351.7 1973.1
Total Lead 351.7 1973.1 839.6
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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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
=617.5 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
8350
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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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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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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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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: melvin.rixse@alaska.gov
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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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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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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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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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16.4 Confirm with OE whether or not this is required. Ensure to run enough liner to provide for
setting the liner hanger at ~ 8,200’ 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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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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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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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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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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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
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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
* State to witness MIT-IA to 3500 psi after 10 days of stabilized injection.
Page 41
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 42
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 43
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
21.0 Wellhead Schematic
Page 44
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
22.0 Days Vs Depth
Click or tap here to enter text.
Page 45
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
23.0 Formation Tops & Information
Page 46
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
Page 47
Prudhoe Bay Unit
L-252 SB WAG
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 Unit
L-252 SB WAG
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 Unit
L-252 SB WAG
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 Unit
L-252 SB WAG
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 Unit
L-252 SB WAG
Drilling Procedure
25.0 Innovation Rig Layout
Page 52
Prudhoe Bay Unit
L-252 SB WAG
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 Unit
L-252 SB WAG
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
28.0 Casing Design
Page 55
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 56
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Prudhoe Bay Unit
L-252 SB WAG
Drilling Procedure
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-12000
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-8250
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West(-)/East(+) (1500 usft/in)
L-252 wp01 tgt5
L-252 wp01 tgt4
L-252 wp01 tgt3
L-252 wp01 tgt2
L-252 wp01 tgt1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
250
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4359
L-252 wp02
Start Dir 3º/100' : 300' MD, 300'TVD
End Dir : 2486.99' MD, 2045.12' TVD
Start Dir 4º/100' : 6416.39' MD, 3907.36'TVD
End Dir : 8082.48' MD, 4435.73' TVD
Start Dir 2º/100' : 8232.48' MD, 4448.8'TVD
Begin Geosteering
Total Depth : 16741.77' MD, 4358.8' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4456.64 4382.84 8350.00 9-5/8 9 5/8" x 12 1/4"
4358.80 4285.00 16741.77 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: L
Well: Plan: L-252
Wellbore: L-252
Plan: L-252 wp02
WELL DETAILS: Plan: L-252
47.30
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5977997.98
582816.53 70° 20' 59.5339 N 149° 19' 39.4860 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-252, True North
Vertical (TVD) Reference:L-252 as built RKB @ 73.80usft (Original Well Elev)
Measured Depth Reference:L-252 as built RKB @ 73.80usft (Original Well Elev)
Calculation Method:Minimum Curvature
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
223-095
X
PRUDHOE BAY
SCHRADER BLUF OIL POOL
PBU L-252
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n
i
t
o
r
i
n
g
w
i
l
l
b
e
r
e
q
u
i
r
e
d
.
33
I
s
p
r
e
s
e
n
c
e
o
f
H
2
S
g
a
s
p
r
o
b
a
b
l
e
Ye
s
34
M
e
c
h
a
n
i
c
a
l
c
o
n
d
i
t
i
o
n
o
f
w
e
l
l
s
w
i
t
h
i
n
A
O
R
v
e
r
i
f
i
e
d
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
No
P
B
U
L
-
P
a
d
i
s
H
2
S
b
e
a
r
i
n
g
.
M
a
x
r
e
a
d
i
n
g
a
t
L
-
2
0
4
(
2
0
2
1
)
i
s
3
0
0
p
p
m
35
P
e
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
i
d
e
m
e
a
s
u
r
e
s
Ye
s
N
o
r
m
a
l
p
r
e
s
s
u
r
e
s
e
x
p
e
c
t
e
d
;
M
P
D
w
i
l
l
m
i
t
i
g
a
t
e
a
n
y
a
b
n
o
r
m
a
l
p
r
e
s
s
u
r
e
s
e
n
c
o
u
n
t
e
r
e
d
.
36
D
a
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
e
s
s
u
r
e
z
o
n
e
s
NA
37
S
e
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
38
S
e
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
C
o
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
AD
D
Da
t
e
10
/
1
7
/
2
0
2
3
Ap
p
r
MG
R
Da
t
e
10
/
1
8
/
2
0
2
3
Ap
p
r
AD
D
Da
t
e
10
/
1
7
/
2
0
2
3
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
i
n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
JL
C
1
0
/
1
9
/
2
0
2
3
