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Alaska Oil and Gas Conservation Commission
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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-295 223115 500292377400 11 3/23/2024
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 6/12/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240612
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
MPI-06 50029228220000 197195 5/2/2024 READ Caliper Survey
MPI-09 50029229640000 200103 5/2/2024 READ Caliper Survey
PBU B-04A 50029200720100 210095 5/20/2024 HALLIBURTON RBT
PBU B-29B 50029215230200 217114 5/20/2024 HALLIBURTON RBT
PBU C-26A 50029208340100 198145 5/24/2024 HALLIBURTON RBT
PBU D-09A 50029203810100 199085 5/18/2024 HALLIBURTON RBT
PBU D-23A 50029207380100 196188 5/18/2024 HALLIBURTON RBT
PBU L-295 50029237740000 223115 5/25/2024 HALLIBURTON PPROF
Please include current contact information if different from above.
T38893
T38894
T38895
T38896
T38897
T38898
T38899
T38900PBU L-295 50029237740000 223115 5/25/2024 HALLIBURTON PPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.06.12 12:38:22 -08'00'
SCHRADER BLUFF OIL POOL, ORION DEV AREA
By Grace Christianson at 4:14 pm, Mar 04, 2024
Completed
2/19/2024
JSB
RBDMS JSB 031124
G
DSR-3/21/24
Drilling Manager
03/01/24
Monty M
Myers
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2024.03.01 14:24:19 -09'00'
Torin
Roschinger
(4662)
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:Date:
Csg Size/Wt/Grade:Supervisor:
Csg Setting Depth:TMD 2752 TVD
Mud Weight:ppg LOT / FIT Press =
LOT / FIT =Hole Depth =
Fluid Pumped=Bbls Volume Back =
Estimated Pump Output:Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Holding Enter Holding
0
2
4
6
8
0
2
4
6
8
10
15
20
25
30
40
50
60
75
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 1020304050607080
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
286268258256254252250248246244242
268826862684268326812680 2675 2672 2669 2666 2664
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
RDMO 01:00 2/19/24
STATE OF WISCONSIN RADIOACTIVE MATERIALS LICENSE 071-1234-01
SEALED SOURCE LEAK TEST CERTIFICATE
RAM ACCESSION NO. 199267
HALLIBURTON ENERGY SERVICES - SPERRY
LOCATION 0190 - PRUDHOE BAY - AK (LWD)
CONTACT PERSON CRAIG ZAWADZKI PHONE 907-670-5828
HALLIBURTON ENERGY SERVICES
SPERRY
SPERRY DRILLING SERVICES
2805 Spine Road
PRUDHOE BAY, AK 99734
UNITED STATES
LEAK TEST ANALYSIS
EQUIPMENT NO. 11111462 DEVICE/TOOL NUMBER
MODEL # CDC.CY13 MANUFACTURER
SOURCE SERIAL NO. 42271B MANUFACTURER S/N
ISOTOPE Cs-137 SOURCE ORIGINAL ACTIVITY 2000 mCi
74 GBq
ASSAY DATE 11/9/2007
DATE SOURCE WIPED 28 Aug 2023 REASON FOR TEST PERIODIC
ANALYSIS DATE 30 Aug 2023 ANALYTICAL METHOD Liquid Scintillation
Counting
GROSS SAMPLE COUNT 19.88 cpm INSTRUMENT Perkin Elmer Tri-Carb
3110TR
130414
BACKGROUND 19.88 cpm COUNTING EFFICIENCY 90%
NET SAMPLE COUNT 0 dpm MINIMUM DETECTABLE
ACTIVITY
1.19E-05 CI
0.44 Bq
SAMPLE ANALYSIS ACTIVITY 0 CI
0Bq
SOURCE PASSES TEST
PASS/FAIL CRITERION 0.005 CI
185 Bq
ACTION LEVEL 0.001 CI
37 Bq
ANALYST Vicky Berg
COMMENTS: _
STATE OF WISCONSIN RADIOACTIVE MATERIALS LICENSE 071-1234-01
SEALED SOURCE LEAK TEST CERTIFICATE
RAM ACCESSION NO. 199272
HALLIBURTON ENERGY SERVICES - SPERRY
LOCATION 0190 - PRUDHOE BAY - AK (LWD)
CONTACT PERSON CRAIG ZAWADZKI PHONE 907-670-5828
HALLIBURTON ENERGY SERVICES
SPERRY
SPERRY DRILLING SERVICES
2805 Spine Road
PRUDHOE BAY, AK 99734
UNITED STATES
LEAK TEST ANALYSIS
EQUIPMENT NO. 11509999 DEVICE/TOOL NUMBER
MODEL # LWD4133 MANUFACTURER
SOURCE SERIAL NO. S10-008 MANUFACTURER S/N
ISOTOPE Am-241Be SOURCE ORIGINAL ACTIVITY 8000 mCi
296 GBq
ASSAY DATE 1/2/2010
DATE SOURCE WIPED 26 Aug 2023 REASON FOR TEST PERIODIC
ANALYSIS DATE 30 Aug 2023 ANALYTICAL METHOD Liquid Scintillation
Counting
GROSS SAMPLE COUNT 19.88 cpm INSTRUMENT Perkin Elmer Tri-Carb
3110TR
130414
BACKGROUND 19.88 cpm COUNTING EFFICIENCY 90%
NET SAMPLE COUNT 0 dpm MINIMUM DETECTABLE
ACTIVITY
1.19E-05 CI
0.44 Bq
SAMPLE ANALYSIS ACTIVITY 0 CI
0Bq
SOURCE PASSES TEST
PASS/FAIL CRITERION 0.005 CI
185 Bq
ACTION LEVEL 0.001 CI
37 Bq
ANALYST Vicky Berg
COMMENTS: _
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:Brooks, Phoebe L (OGC)
To:James Lott - (C)
Cc:Regg, James B (OGC)
Subject:RE: Hilcorp Innovation 2-4-24 BOP Test Report.
Date:Thursday, February 22, 2024 10:04:57 AM
Attachments:Hilcorp Innovation 02-04-24 Revised.xlsx
Attached is a revised report changing the Start Date to 2/3/24 (based on the finish date and test
time). Please update your copy or let me know if you disagree.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the
Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or
disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it
to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: James Lott - (C) <jlott@hilcorp.com>
Sent: Sunday, February 4, 2024 6:37 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay
<doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Cc: Michael Menapace - (C) <Michael.Menapace@hilcorp.com>; Matthew Vanhoose - (C)
<mvanhoose@hilcorp.com>
Subject: Hilcorp Innovation 2-4-24 BOP Test Report.
James Lott
HILCORP Drilling Foreman
HILCORP INNOVATION Rig
PBU, North Slope Alaska
907-670-3094 (Office)
907-398-9069 (Cell)
Harmony 1006
jlott@hilcorp.com
jameslott352@yahoo.com
PBU L-295
PTD 2231150
J. Regg; 4/1/2024
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner:Rig No.:Innovation DATE:2/4/24
Rig Rep.:Rig Email:
Operator:
Operator Rep.:Op. Rep Email:
Well Name:PTD #2231150 Sundry #
Operation:Drilling:x Workover:Explor.:
Test:Initial:Weekly:Bi-Weekly:x Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1398
MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1 P
Permit On Location P Hazard Sec.P Lower Kelly 1 P
Standing Order Posted P Misc.NA Ball Type 2 P
Test Fluid Water Inside BOP 2 P
FSV Misc 0 NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0 NA Trip Tank P P
Annular Preventer 1 13 5/8" 5K P Pit Level Indicators P P
#1 Rams 1 2 7/8 x 5 1/2" 5K P Flow Indicator P P
#2 Rams 1 Blinds P Meth Gas Detector P P
#3 Rams 1 7" 5K NT H2S Gas Detector P P
#4 Rams 0 NA MS Misc 0 NA
#5 Rams 0 NA
#6 Rams 0 NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5K P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5K P System Pressure (psi)3000 P
Kill Line Valves 3 3-1/8" 5K P Pressure After Closure (psi)1450 P
Check Valve 0 NA 200 psi Attained (sec)29 P
BOP Misc 0 NA Full Pressure Attained (sec)112 P
Blind Switch Covers:All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 @ 2341 P
No. Valves 15 P ACC Misc 0 NA
Manual Chokes 1 P
Hydraulic Chokes 1 FP Control System Response Time:Time (sec)Test Result
CH Misc 0 NA Annular Preventer 11 P
#1 Rams 9 P
Coiled Tubing Only:#2 Rams 9 P
Inside Reel valves 0 NA #3 Rams 9 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:8.5 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 2/1/2024 18:00
Waived By
Test Start Date/Time:2/3/2024 17:30
(date)(time)Witness
Test Finish Date/Time:2/4/2024 2:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Austin McLeod
Hilcorp
Tested on 4.5" and 3.5" test jts. F/P on Hyd. Choke, rebuild choke and re-test - passed
Ethan Evans
Hilcorp
James Lott
PBU L-295
Test Pressure (psi):
nnovationtoolpusher@hilcorp.com
jlott@hilcorp.com
Form 10-424 (Revised 08/2022)2024-0204_BOP_Hilcorp_Innovation_PBU_L-295
J. Regg; 4/1/2024
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: 03/05/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: PBU L-295 +PB1 +PB2 +PB3
PTD: 223-115
API: 50-029-23774-00-00 (L-295)
50-029-23774-70-00 (L-295PB1)
50-029-23774-71-00 (L-295PB2)
50-029-23774-72-00 (L-295PB3)
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (12/15/2023 to 02/10/2024)
x ROP, BST-GR, RST-EWR, DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Surveys
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU L-295 LWD Subfolder:
PBU L-295 Geosteering Subfolder:
Please include current contact information if different from above.
PTD: 223-115
T38593
T38594
T38595
T38596
T38593
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.06 08:24:51 -09'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
PBU L-295PB1 +PB2 +PB3 LWD Subfolders:
Please include current contact information if different from above.
T38594: PB1
T38595: PB2
T38596: PB3
SCHRADER BLUFF OIL POOL, ORION DEVELOPMENT AREA
Drilling Manager
02/09/24
Monty M
Myers
By Samantha Coldiron at 11:44 am, Feb 09, 2024
324-073
A.Dewhurst 09FEB24
10-407
Plan for determining Ugnu production contribution, including timing of such, to be submitted to
AOGCC and approved before putting the well on production.
BJM 2/9/24SJC for BWH 2/9/24
2/9/24
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.02.09 15:15:45
-09'00'
RBDMS JSB 021324
Change to Approved Permit
Well: L-295
PTD: 223-115
API: 50-029-23774-00-00
Well Name:L-295 Permit to Drill:223-115
API Number:50-029-23774-00-00
Estimated Start Date:February 9, 2024
Regulatory Contact:Joseph Lastufka 907-777-8400 (O) jo4472@hilcorp.com
First Call Engineer:Joseph Engel 907-777-8395 (O) jengel@hilcorp.com
Brief Well Summary:
L-295 (PTD# 223-115) was permitted to be a grassroots WAG injection well in the Schrader Bluff NB sand (Orion
Pool). Drilling began on 12/15/2023. Surface and Intermediate hole sections were drilled without issue.
While drilling the lateral, the BHA became stuck and was unable to be recovered. The BHA was cemented in place,
with a TOC of 13,263’ MD (TDPB1: 13,769’ MD). The well was sidetracked at 12,689’ MD. After crossing a fault,
the decision was made to drill up to reacquire the NB sand with a TDPB2 of 14,856’ MD, the well was sidetracked
at 14,290’ MD. After drilling ahead in the NB sand it was determined that PB2 had exited the Orion Pool into the
Ugnu MF and the decision was made to cement off the open hole junction of that plug back as approved by the
AOGCC, cement plug from 13,883 – 14,500’ MD (TDPB3: 18,486’ MD). The well was sidetracked at 13,620 with a
planned TD of ~ 20,100’ MD. An interpreted cross section of the lateral to current depth is attached.
Upon review of the plug backs, guidance from the AOGCC was given: “Due to the lack of isolation between the
authorized injection zone and the above lying Ugnu sands through the open L-295PB2 wellbore, injection of any
type is not authorized within the fault block that contains L-295PB2. This supersedes the guidance that was
provided on 31 January 2023 indicating water-only injection was allowed from the L-295 well into the fault block
that contains L-295PB2.”
Objective:
To prohibit injection into formations outside of the Orion Pool. Hilcorp proposes to change the approved permit
and well type of L-295 to become a producing well in the Schrader Bluff NB sand.
Current Status:
Drilling 6-1/8” Lateral in the Schrader Bluff NB Sand at ~ 18,800’ MD, Planned TD ~ 20,100’ MD. The following
operational steps are to circulate the hole clean, BROOH, LD BHA, and rig up to run lower completion.
Changes to Approved Program:
x Section 18:
o Lower Completion to be changed from slotted liner to 250ђ screen liner
o All other steps remain unchanged
x Section 19:
o Upper completion to be changed to a gas lifted completion, as per attached draft schematic
o State witnessed MIT-IA and form 10-426 no longer required
o Change the MITT and MITIA to MITT and CMIT-TxIA to 3500 psi (Live GLVs will be run with the
completion due to deviation, which will preclude performance of an MITIA as a casing test).
x Post Rig Well Work:
o Slickline – Pull B&R, Pull RHC plug
o Portable Testers – POP
Change to Approved Permit
Well: L-295
PTD: 223-115
API: 50-029-23774-00-00
Conditions of Production:
L-295 production is contingent on determination if there is any contribution of production from the Ugnu MF. If
significant Ugnu production is occurring, authorization for continued commingling will be required, similarly to the
requirements given for returning L-292 to production.
Hilcorp’s proposed methodology to determine the portion of the production associated with the Ugnu is by use of
geochemical marker analysis. Hilcorp has oil samples of Ugnu MF Sand and Schrader Bluff NB Sand to be used for
comparison.
Attachments –
Proposed Wellbore Schematic
L-295 Lateral Interpreted Cross Section
geochemical marker analysis.
_____________________________________________________________________________________
Revised By: JNL 2/8/2024
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-295
Last Completed: TBD
PTD: 223-115
JEWELRY DETAIL
No. MD Item ID
1 ~4,200 X Nipple 3.813”
2 4,554’ 4-1/2” x 1” GLM 3.833”
3 6,899’ 4-1/2” x 1” GLM 3.833”
4 8,454’ 4-1/2” x 1” GLM 3.833”
5 ~9,460’ 4-1/2” x 1” GLM 3.833”
6 ~9,520’ XD HES Sliding Sleeve 3.813”
7 ~9,580’ Baker Downhole Gauge Carrier 3.958”
8 ~9,640’ 4-1/2” HES AHR 7” x 4-1/2” Packer 3.865”
9 ~9,700’ X Nipple (@ bottom of 71 deg sail angle) 3.813”
10 ~10,490’ 4-1/2” WLEG 3.958”
11 ~10,470’ 7” x 5” Liner Hanger 3.958”
12 ~15,000’ 4-1/2” x 3-1/2” XO 2.992”
13 ~20,115’ 3-1/2” Shoe 2.992”
GENERAL WELL INFO
API: 50-029-23774-00-00
Completion Date: TBD
TD =20,115’(MD) / TD =4,049’(TVD)
4
20”
Orig. KB Elev.: 73.55’ / GL Elev.: 47.4’
7”
10&11
2
5
4
PB2
PB3 12
9-5/8”
3
1
2
3
PB1
Top of Cement
@ 13,263’
4-1/2”
x
3-1/2”
250
Micron
Screen
Liner
6
4-1/2”x3-1/2”
7
8
PBTD =20,115’(MD) / PBTD = 4,049’(TVD)
5
Lost BHA
w/ nuclear
source top
@ 13,660’,
Density =
13,689’
Neutron =
13,678’
9
12
4-1/2”
Cement @
13,883’ – 14,500’
13
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4”1st Lead – 320 sx / Tail – 399 sx
2nd Lead – 720 sx / tail - 260 sx
8-1/2” Tail – 382 sx
6-1/8” Uncemented Slotted Liner
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 110’ N/A
9-5/8” Surface 47 / L-80 / BTC 8.525” Surface 2,763’ 0.0732
9-5/8” Surface 40 / L-80 / BTC 8.679” 2,763’ 5,667’ 0.0758
7” Intermediate 29 / L-80 / BTC 6.184” Surface 10,623’ 0.0371
4-1/2” 250 Micron Screens 12.6 / L-80 / JFE Bear 3.958” 10,470’ 15,000’ 0.0152
3-1/2” 250 Micron Screens 9.2 / L-80 / JFE Bear 2.992” 15,000’ 20,115’ 0.00086
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / JFE-Bear 3.958” Surface 9,700’ 0.0152
4-1/2” Tubing 12.6# / 13Cr / VamTop 3.958” 9,700’ 10,470’ 0.0152
WELL INCLINATION DETAIL
KOP @ 151’
90° Hole Angle = 10,516’
PB1: 12,660’ – 13,769’
PB2: 13,595’ - 14,856’
PB3: 14,289’ – 18,486’
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CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:20240120 1337 Approval for Source Abandonment PTD: 223-115 (PBW L-295 Source Abandonment)
Date:Wednesday, January 24, 2024 10:37:47 AM
From: Monty Myers <mmyers@hilcorp.com>
Sent: Saturday, January 20, 2024 1:37 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; McLellan, Bryan J (OGC)
<bryan.mclellan@alaska.gov>; Clint Montague - (C) <cmontague@hilcorp.com>; Joseph Engel
<jengel@hilcorp.com>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>; Kevin Eastham <keastham@hilcorp.com>
Subject: Re: [EXTERNAL] Re: PTD: 223-115 (PBW L-295 Source Abandonment)
Thank you Mel.
Noted and understood. I have been informed by Halliburton that the NRC also agrees and has
approved the plan.
Monty M Myers
Drilling Manager
907.777.8431 (O)
907.538.1168 (C)
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Saturday, January 20, 2024 1:01:08 PM
To: Monty Myers <mmyers@hilcorp.com>
Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; McLellan, Bryan J (OGC)
<bryan.mclellan@alaska.gov>; Clint Montague - (C) <cmontague@hilcorp.com>; Joseph Engel
<jengel@hilcorp.com>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>; Kevin Eastham <keastham@hilcorp.com>
Subject: [EXTERNAL] Re: PTD: 223-115 (PBW L-295 Source Abandonment)
Monty,
AOGCC agrees with your plan as described below.
As discussed, NRC to be notified and agreed to your plan.
Mel Rixse
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.
On Jan 20, 2024, at 9:13 AM, Monty Myers <mmyers@hilcorp.com> wrote:
Good morning Mel,
We encountered some issues while drilling the lateral on PBW L-295 at 13,769’ and
became stuck with the lateral drilling BHA that has nuclear sources. Below is the history
of the operations, the plan forward and the BHA tally with the nukes. We have a total
of approximately 110’ of fish in the hole and about 20’ of steel above the first nuclear
source. We plan to have at least 500’ measured depth of cement above the fish and OH
sidetrack even further back to avoid the fish and maintain at least 100’ of separation
from the fish while re-drilling.
Previous operations L-295:
On Jan 8, 2024’ at approximately 01:30 while making a connection drilling the 6-1/8”
production hole the drill string became stuck. While attempting to work the BHA free
the jars ceased working after 108 jar hits. Circulation was re-established with some
momentary rotation available, but no movement with the drill string. On Jan 10 at
01:30 a 15% HCL pill was pumped, spotted, an allowed to soak in the annulus in an
attempt to loosen the formation/concretion. The drill string was continued to be
worked at 15:30 and we were able to work pipe free and start pulling out of the hole.
Once out of the hole it was observed the jars had a significant wash, and everything
below the TM collar (1.5’ of the TM was recovered) was left downhole.
Baker Hughes was consulted and mobilized to assist with the fishing operations. Below
is a description of the fishing attempts made.
First fishing attempt with carbide shoe and grapple- washed down to fish @13,659’ and dress off T/13,660’. We were unable to make further progress andwash down over fish to engage grapple.
2nd BHA- RIH with 6 1/8” rough junk mill to TOF @ 13,659’ and mill/dress off TOFT/13,664’.
3rd BHA- RIH with 5 ¾” cut lip overshot and grapple attempting to get over fish
with no success. Observed damage to cut lip guide at surface.
4th BHA- RIH with Rotary shoe and inner junk mill. Varied parameters attempting
to wash over fish and redress fish. Observed at surface no internal indication on
shoe or inner junk mill we had gotten over fish. Appears we are beside the fish(likely low side) and unable to engage.
5th BHA- RIH with cut lip guide, inner junk mill and added 6 1/8” stab to center
wash pipe. Made multiple attempts to wash over and engage fish to redress withno success.
Plan Forward:
RIH with 3 ½” CMT stinger on 4” DP to TOF and place a 500’ cement plug with red dye
on top of lost down hole tools with radioactive sources. We are lateral at 90° F/10,500’
T/13,660’.
RIH with cement stinger to TOF @ 13,660’. Rig up Haliburton cementers andpump 25 BBLS (30% excess) 15.8 PPG CMT to the shoe. Continue pumping
placing 30’ or .7 bbls on back side.
R/D cementing equipment
Pump out of hole displacing cement on the backside BBL in per BBL pulled
pumping 2 BPM, pulling 60 FPM for a max 46 stks a std (35 stands calc x 1.3excess), until all cement is placed in hole putting projected TOC @ 13,160’ (thisis based on 30% excess).
POOH racking back 2 stands (~120’) and drop wiper ball and Circulate hole clean.
WOC for 12 hrs. RIH and tag TOC with 5-10K Down. POOH and L/D 3 ½” CMT
stinger
PU Lateral drilling BHA and RIH to OH sidetrack point and time drill to go aroundBHA and maintain a minimum of 100’ offset to side of fish.
<image001.png>
Please let me know if you have any questions about our past or future operations with
this well.
Thank you!
Monty M Myers
Drilling Manager
907.538.1168
The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage 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 phonenumber 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 toensure 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.
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 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:Clint Montague - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Christopher Yearout - (C); James Lott - (C)
Subject:Hilcorp Innovation 1-23-24 BOPE test
Date:Wednesday, January 24, 2024 7:48:40 AM
Attachments:Hilcorp Innovation 1-23-24.xlsx
Some people who received this message don't often get email from cmontague@hilcorp.com. Learn why this is
important
Attached is the BOPE test form for Innovation on 1-23-24.
Please contact me if there are any questions. Thanks.
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 the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
3%8/
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSub m itt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:Innovation DATE: 1/23/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #22231150 Sundry #
Operation: Drilling: x Workover: Explor.:
Test: Initial: Weekly: Bi-Weekly: x Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1398
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 2P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13 5/8" 5K P Pit Level Indicators PP
#1 Rams 1 2 7/8 x 5 1/2" 5K FP Flow Indicator PP
#2 Rams 1 Blinds P Meth Gas Detector PP
#3 Rams 1 7" 5K NT H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5K FP Time/Pressure Test Result
HCR Valves 2 3-1/8" 5K FP System Pressure (psi)3000 P
Kill Line Valves 2 3-1/8" 5K FP Pressure After Closure (psi)1450 P
Check Valve 0NA200 psi Attained (sec)32 P
BOP Misc 0NAFull Pressure Attained (sec)113 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 6 @ 2333 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 11 P
#1 Rams 9 P
Coiled Tubing Only:#2 Rams 9 P
Inside Reel valves 0NA #3 Rams 9 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:4 Test Time:11.0 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1/21/24 05:50
Waived By
Test Start Date/Time:1/22/2024 13:30
(date) (time)Witness
Test Finish Date/Time:1/23/2024 0:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Brian Bixby
Hilcorp
Tested on 4.5" and 3.5" test jts. F/P on inside kill; function and retested -pass. F/P on HCR choke; rebuild and retest - pass.
F/P on inside choke; removed, cleaned inspected and re-greased retested - pass. F/P on UPR's; changed out and retested -
pass.
Joel Sture
Hilcorp North Slope LLC
Clinton Montague
PBU L-295
Test Pressure (psi):
nnovationtoolpusher@hilcorp.com
cmontague@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0123_BOP_Hilcorp_Innovation_PBU_L-295
9
99
99
9
99
9
9
9
9
9
9
9
9
- 5HJJ
FP
FP
FP
FP
F/P on inside kill F/P on HCR choke
F/P on inside choke F/P on UPR's
Drilling Manager
01/22/24
Monty M
Myers
324-028
By Grace Christianson at 9:54 am, Jan 23, 2024
Plug back w/ source to be included in final well schematic on 10-407 completion report.
DSR-1/26/24
(Final completion report)
Schrader Bluff Oil
SFD
MGR23FEB24
10-407
SFD 1/23/2024
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Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.02.26 14:28:00 -09'00'02/26/24
RBDMS JSB 022724
Well Prognosis
Well: PBU L-295
Date: 1/22/2024
Well Name:PBU L-295 API Number:50-029-23774-00-00
Current Status:Abandon sources /
Sidetrack
Estimated Start Date:1/20/2024 Rig:Innovation
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:TBD
Regulatory Contact:Joe Lastufka 777-8400 Permit to Drill Number:223-115
First Call Engineer:Monty Myers (907) 538-1168 (M)
Second Call Engineer
AFE Number:
Brief Well Summary –
PBU L-295 encountered some issues while drilling the lateral at 13,769’ and became stuck with the lateral
drilling BHA that has nuclear sources. Below is the history of the operations, the plan forward and the BHA tally
with the nukes. We have a total of approximately 110’ of fish in the hole and about 20’ of steel above the first
nuclear source. We plan to have at least 500’ measured depth of cement above the fish and OH sidetrack even
further back to avoid the fish and maintain at least 100’ of separation from the fish while re-drilling.
Previous operations L-295:
On Jan 8, 2024’ at approximately 01:30 while making a connection drilling the 6-1/8” production hole the drill
string became stuck. While attempting to work the BHA free the jars ceased working after 108 jar
hits. Circulation was re-established with some momentary rotation available, but no movement with the drill
string. On Jan 10 at 01:30 a 15% HCL pill was pumped, spotted, an allowed to soak in the annulus in an attempt
to loosen the formation/concretion. The drill string was continued to be worked at 15:30 and we were able to
work pipe free and start pulling out of the hole. Once out of the hole it was observed the jars had a significant
wash, and everything below the TM collar (1.5’ of the TM was recovered) was left downhole.
Baker Hughes was consulted and mobilized to assist with the fishing operations. Below is a description of the
fishing attempts made.
x First fishing attempt with carbide shoe and grapple- washed down to fish @ 13,659’ and dress off
T/13,660’. We were unable to make further progress and wash down over fish to engage grapple.
x 2nd BHA- RIH with 6 1/8” rough junk mill to TOF @ 13,659’ and mill/dress off TOF T/13,664’.
x 3rd BHA- RIH with 5 ¾” cut lip overshot and grapple attempting to get over fish with no success.
Observed damage to cut lip guide at surface.
x 4th BHA- RIH with Rotary shoe and inner junk mill. Varied parameters attempting to wash over fish and
redress fish. Observed at surface no internal indication on shoe or inner junk mill we had gotten over
fish. Appears we are beside the fish (likely low side) and unable to engage.
x 5th BHA- RIH with cut lip guide, inner junk mill and added 6 1/8” stab to center wash pipe. Made
multiple attempts to wash over and engage fish to redress with no success.
Plan Forward:
RIH with 3 ½” CMT stinger on 4” DP to TOF and place a 500’ cement plug with red dye on top of lost down hole
tools with radioactive sources. We are lateral at 90° F/10,500’ T/13,660’.
x RIH with cement stinger to TOF @ 13,660’. Rig up Haliburton cementers and pump 25 BBLS (30%
excess) 15.8 PPG CMT to the shoe. Continue pumping placing 30’ or .7 bbls on back side.
x R/D cementing equipment
Abandon sources /
Well Prognosis
Well: PBU L-295
Date: 1/22/2024
x Pump out of hole displacing cement on the backside BBL in per BBL pulled pumping 2 BPM, pulling 60
FPM for a max 46 stks a std (35 stands calc x 1.3 excess), until all cement is placed in hole putting
projected TOC @ 13,160’ (this is based on 30% excess).
x POOH racking back 2 stands (~120’) and drop wiper ball and Circulate hole clean.
x WOC for 12 hrs. RIH and tag TOC @ 13,263’ with 10K stacked weight down. POOH and L/D 3 ½” CMT
stinger
x PU Lateral drilling BHA and RIH to OH sidetrack point and time drill to go around BHA and maintain a
minimum of 100’ offset to side of fish.
Attachments
1.Actual Schematic
2.Proposed Schematic
Well Prognosis
Well: PBU L-295
Date: 1/22/2024
x Pump out of hole displacing cement on the backside BBL in per BBL pulled pumping 2 BPM, pulling 60
FPM for a max 46 stks a std (35 stands calc x 1.3 excess), until all cement is placed in hole putting
projected TOC @ 13,160’ (this is based on 30% excess).
x POOH racking back 2 stands (~120’) and drop wiper ball and Circulate hole clean.
x WOC for 12 hrs. RIH and tag TOC @ 13,263’ with 10K stacked weight down. POOH and L/D 3 ½” CMT
stinger
x PU Lateral drilling BHA and RIH to OH sidetrack point and time drill to go around BHA and maintain a
minimum of 100’ offset to side of fish.
Attachments
1.Actual Schematic
2.Proposed Schematic
_____________________________________________________________________________________
Revised By: JNL 1/22/2024
LOST BHA SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-295
Last Completed: TBD
PTD: 223-115
JEWELRY DETAIL
No. MD Item ID
1 13,660’
Lost BHA with Nuclear Source Density
Source at 13,689’, Neutron Source at
13,678’
GENERAL WELL INFO
API: 50-029-23774-00-00
Completion Date: TBD
TD =13,769’(MD) / TD =4,101’(TVD)
4
20”
Orig. KB Elev.: 73.55’ / GL Elev.: 47.4’
7”
5
9-5/8”
2
3
9-5/8” ‘ES’
Cementer
@ 2,781’
PBTD =13,263’(MD) / PBTD = 4,123’(TVD)
Lost BHA w/
nuclear source
top @ 13,660’,
Density Source
= 13,689’
Neutron Source
= 13,678’
Top of Cement
@ 13,263’
1
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4”1st Lead – 326 sx / Tail – 400 sx
2nd Lead –720 sx / tail - 260 sx
8-1/2” Tail – 382 sx
6-1/8” Open Hole
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 110’ N/A
9-5/8” Surface 47 / L-80 / BTC 8.525” Surface 2,763’ 0.0732
9-5/8” Surface 40 / L-80 / BTC 8.679” 2,763’ 5,667’ 0.0758
7” Intermediate 29 / L-80 / BTC 6.184” Surface 10,623’ 0.0371
TUBING DETAIL
WELL INCLINATION DETAIL
KOP @ 151’
90° Hole Angle = @ 10,516’
_____________________________________________________________________________________
Revised By: JNL 1/22/2024
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-295
Last Completed: TBD
PTD: TBD
JEWELRY DETAIL
No. MD Item ID
1 ~5,100’ X Nipple 3.813”
2 ~9380’ X Nipple 3.813”
3 ~9,440’ 4-1/2” HES TNT 7” x 4-1/2” Packer 3.856”
4 ~9,500’ X Nipple (@ bottom of 71 deg sail angle) 3.813”
5 ~9,850’ 4-1/2” WLEG 3.958”
6 ~9,850’ 7” x 5” Liner Hanger 4.170”
7 ~9,900’ 5” x 4-1/2” XO 3.900”
8 ~15,000’ 4-1/2” x 3-1/2” XO 2.992”
9 ~20,115’ 3-1/2” Shoe
GENERAL WELL INFO
API: 50-029-23774-00-00
Completion Date: TBD
TD = 20,115 (MD) / TD =4,049’(TVD)
4
20”
Orig. KB Elev.: 73.9’ / GL Elev.: 47.4’
7”
25
4
9
9-5/8”
3
1
2
3
Top of Cement
@ 13,263’
4-1/2”
x
3-1/2”
Slotted
Liner
PBTD =20,115’(MD) / PBTD = 4,049’(TVD)
PB1: 12,660’–
13,769’
5,6
Lost BHA
w/ nuclear
source top
@ 13,660’,
Density =
13,689’
Neutron =
13,678’
7
12
4-1/2”
8
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4”1st Lead – 326 sx / Tail – 400 sx
2nd Lead – 720 sx / tail - 260 sx
8-1/2” Tail – 382 sx
6-1/8” Uncemented Slotted Liner
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 110’ N/A
9-5/8” Surface 47 / L-80 / BTC 8.525” Surface 2,500’ 0.0732
9-5/8” Surface 40 / L-80 / BTC 8.679” 2,500’ 5,000’ 0.0758
7” Intermediate 29 / L-80 / BTC 6.184” Surface 10,000’ 0.0371
4-1/2” Liner 12.6 / L-80 / H563 3.958” 9,850’ 15,000’ 0.0152
3-1/2” Liner 9.2 / L-80 / H563 2.992” 15,000’ 20,115’ 0.0152
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / JFE-Bear 3.958” Surface 9,850’ 0.0152
WELL INCLINATION DETAIL
KOP @ 151’
90° Hole Angle = @ 10,516’
PB1: 12,660’ – 13,789’
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
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From:Clint Montague - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Subject:Hilcorp Innovation 1-13-24
Date:Monday, January 15, 2024 10:14:28 AM
Attachments:Hilcorp Innovation 1-13-24.xlsx
Some people who received this message don't often get email from cmontague@hilcorp.com. Learn why this is
important
Attached is the BOPE test form for Hilcorp Innovation rig conducted 1-13-24 on well PBU L-295. Let
me know if you have any questions.
Thanks
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 the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
3%8/
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:Innovation DATE: 1/13/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2231150 Sundry #
Operation: Drilling: x Workover: Explor.:
Test: Initial: Weekly: Bi-Weekly: x Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1398
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 2P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13 5/8" 5K P Pit Level Indicators PP
#1 Rams 1 2 7/8 x 5 1/2" 5K FP Flow Indicator PP
#2 Rams 1 Blinds P Meth Gas Detector PP
#3 Rams 1 7" 5K NT H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5K P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5K P System Pressure (psi)3000 P
Kill Line Valves 2 3-1/8" 5K P Pressure After Closure (psi)1400 P
Check Valve 0NA200 psi Attained (sec)32 P
BOP Misc 0NAFull Pressure Attained (sec)113 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 6 @ 2350 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1FP Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 11 P
#1 Rams 9 P
Coiled Tubing Only:#2 Rams 9 P
Inside Reel valves 0NA #3 Rams 10 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:2 Test Time:4.5 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1/10/24 18:16
Waived By
Test Start Date/Time:1/13/2024 0:30
(date) (time)Witness
Test Finish Date/Time:1/13/2024 5:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Austin McLeod
Hilcorp
Tested on 4 1/2" and 3 1/2" test jts. FP on UPR (4-1/2" TJ) low test: functioned, reflooded and purged air - good. FP on Hydraulic
choke, adjusted timing on valve actuator and flushed through - good.
Matt Vanhoose
Hilcorp North Slope
Clinton Montague
PBU L-295
Test Pressure (psi):
nnovationtoolpusher@hilcorp.com
cmontague@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0113_BOP_Hilcorp_Innovation_PBU_L-295
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FP on UPR FP on Hydraulic
choke
FP
FP
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:James Lott - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Joel Sture - (C); Christopher Yearout - (C)
Subject:Hilcorp Innovation BOP Test Report
Date:Wednesday, January 3, 2024 8:35:39 AM
Attachments:Hilcorp Innovation 1-2-24.xlsx
James Lott
HILCORP Drilling Foreman
HILCORP INNOVATION Rig
PBU, North Slope Alaska
907-670-3094 (Office)
907-398-9069 (Cell)
Harmony 1006
jlott@hilcorp.com
jameslott352@yahoo.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
3%8/
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSub m it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:Innovation DATE: 1/2/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #22231150 Sundry #
Operation: Drilling: x Workover: Explor.:
Test: Initial: Weekly: Bi-Weekly: x Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1398
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 2P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13 5/8" 5K P Pit Level Indicators PP
#1 Rams 1 2 7/8 x 5 1/2" 5K P Flow Indicator PP
#2 Rams 1 Blinds P Meth Gas Detector PP
#3 Rams 1 7" 5K NT H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5K P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5K P System Pressure (psi)3000 P
Kill Line Valves 3 3-1/8" 5K P Pressure After Closure (psi)1450 P
Check Valve 0NA200 psi Attained (sec)26 P
BOP Misc 0NAFull Pressure Attained (sec)109 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 6 @ 2350 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 11 P
#1 Rams 9 P
Coiled Tubing Only:#2 Rams 9 P
Inside Reel valves 0NA #3 Rams 10 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:3.5 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 12/31, 0700
Waived By
Test Start Date/Time:1/2/2024 6:00
(date) (time)Witness
Test Finish Date/Time:1/2/2024 9:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Bob Noble
Hilcorp
Tested on 4 1/2" and 3 1/2" test jts.
Joel Sture
Hilcorp North Slope LLC
James Lott
PBU L-295
Test Pressure (psi):
nnovationtoolpusher@hilcorp.com
jlott@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0102_BOP_Hilcorp_Innovation_PBU_L-295
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STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN ORIN L-295
JBR 03/01/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
4", 5" & 7" joints. TPR replaced for pass. Manual kill greased for pass.
Test Results
TEST DATA
Rig Rep:Sture/SerafineOperator:Hilcorp North Slope, LLC Operator Rep:Montague/Yearout
Rig Owner/Rig No.:Hilcorp Innovation PTD#:2231150 DATE:12/23/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSAM231223183809
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7
MASP:
1398
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"x5-1/2"FP
#2 Rams 1 Blinds P
#3 Rams 1 7"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 2 3-1/8"FP
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1450
200 PSI Attained P29
Full Pressure Attained P113
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@2341
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P15
#1 Rams P9
#2 Rams P9
#3 Rams P9
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Steve Dambacher - (C)
To:Regg, James B (OGC); AOGCC.Inspector@alaska.gov
Cc:Brooks, Phoebe L (OGC); Michael Menapace - (C); Mark Brouillet - (C); Steve Dambacher - (C)
Subject:Innovation Rig / Diverter Test L-295, 12/16/2023
Date:Sunday, December 17, 2023 3:29:56 AM
Attachments:Diverter Test Innovation Rig L-295 12-16-23.xlsx
Gas alarm test results Innovation Rig L-295 12-16-23.pdf
Please reply all. Thank you…
Steve Dambacher
Hilcorp night DSM – Innovation Rig
Office: 907-776-7945
Cell: 907-398-4270
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
3%8/
37'
Date: 12/16/2023 Development: X Exploratory:
Drlg Contractor: Rig No. Innovation AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.: 2231150 Rig Phone:
Rig Email:
MMISCELLANEOUS:DIVERTER SYSTEM:
Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P
Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P
Warning Sign P Misc: NA No Threaded Connections? P
24 hr Notice: P Vent line Below Diverter? P
AACCUMULATOR SYSTEM:Diverter Size: 13 5/8 in.
Systems Pressure: 2950 psig P Hole Size: 12 1/4 in.
Pressure After Closure: 2150 psig P Vent Line(s) Size: 16 in. P
200 psi Recharge Time: 19 Seconds P Vent Line(s) Length: 219 ft. P
Full Recharge Time:57 Seconds P Closest Ignition Source: 76 ft. P
Nitrogen Bottles (Number of): 6 Outlet from Rig Substructure: 203 ft. P
Avg. Pressure: 2333 psig P
Accumulator Misc: NA
Vent Line(s) Anchored: P
MMUD SYSTEM:Visual Alarm Turns Targeted / Long Radius: NA
Trip Tank: P P Divert Valve(s) Full Opening: P
Mud Pits: P P Valve(s) Auto & Simultaneous:
Flow Monitor: P P Annular Closed Time: 11 sec P
Mud System Misc: 0 NA Knife Valve Open Time: 6 sec P
Diverter Misc: NA
GGAS DETECTORS:Visual Alarm
Methane: P P
Hydrogen Sulfide: P P
Gas Detectors Misc: 0 NA
Total Test Time: 1 hrs Non-Compliance Items: 0
Remarks:
Submit to:
mark.brouillet@hilcorp.com
TTEST DATA
Matt Vanhoose
phoebe.brooks@alaska.gov
Hilcorp
Tested w/ 5" drill pipe.
0
Mark Brouillet
0
670-3094
TTEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
PBU L-295
SSTATE OF ALASK A
AALASK A OIL AND GAS CONSERVATION COMMISSION
DDi verter Sys t ems In sp ectio n Report
GGENERAL INFORMATION
WaivedParker
**All Diverter repo rts are du e to t he agency w i th in 5 days of test in g*
Form 10-425 (Revised 05/2021)2023-1216_Diverter_Hilcorp_Innovation_PBU_L-295
+LOFRUS
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Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L-295
Hilcorp Alaska, LLC
Permit to Drill Number: 223-115
Surface Location: 2297' FSL, 4038' FEL, Sec 34, T12N, R11E, UM, AK
Bottomhole Location: 1279' FNL, 799' FEL, Sec 19, T12N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie Chmielowski.
Commissioner
DATED this 13 day of December 2023.
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2023.12.13 15:27:40
-09'00'
4-1/2"x3-1/2"
Drilling Manager
12/01/23
Monty M
Myers
By Grace Christianson at 2:28 pm, Dec 01, 2023
50-029-23774-00-00
260 sx
764 sx
223-115
T12N
A.Dewhurst 13DEC23
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing tests and FIT digital data to AOGCC immediately upon performing FIT.
* LWD gamma-ray and resistivity data to AOGCC promptly to confirm required location
for TOC on 8-1/2" OH x 7" annulus.
* 24 hour notice to AOGCC to witness MIT-IA to 3500 psi.
* Variance to 2 AAC 25.412 (b) approved for tubing injection packer to be set greater than 200' MD from
top of slotted liner. Packer to be placed within the SB oil pool.
318 sx
DSR-12/5/23MGR13DEC2023*&:
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2023.12.13 15:28:03 -09'00'12/13/23
12/13/23
212019
2829
33-29E
I-100I-100PB1
L-123
L-211
L-211PB1
NWE2-01
NWE4-01
NWEILEEN-1
L-240
L-292
L-293 L-295_wp05
L-246PB1
HILCORP NORTH SLOPE
Greater Prudhoe Bay
AOR MAP
L-295 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
Temporarily Abandoned
Plugback
Active Oil
Injector Location
Shut in Injector
REMARKS
Well Symbols at top of Schrader Bluff NB sand (targetof proposed L-295 well). Black dashed circles andlines = 1320' radius from heel to toe of proposed L-295lateral injector.
October 5, 2023
PETRA 10/5/2023 10:37:05 AM
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Prudhoe Bay West
(PBU) L-295
Permit to Drill Application
Version 1
11/27/2023
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 & Cement 7” Intermediate Casing .................................................................................. 32
17.0 Drill 6-1/8” Hole Section .......................................................................................................... 37
18.0 Run 4-1/2” x 3-1/2” Injection Liner......................................................................................... 42
19.0 Run Upper Completion/ Post Rig Work ................................................................................. 48
20.0 Innovation Rig Diverter Schematic ......................................................................................... 52
21.0 Innovation Rig BOP Schematic ............................................................................................... 53
22.0 Wellhead Schematic ................................................................................................................. 54
23.0 Days Vs Depth .......................................................................................................................... 55
24.0 Formation Tops & Information............................................................................................... 56
25.0 Anticipated Drilling Hazards .................................................................................................. 58
26.0 Innovation Rig Layout ............................................................................................................. 64
27.0 FIT Procedure .......................................................................................................................... 65
28.0 Innovation Rig Choke Manifold Schematic ............................................................................ 66
29.0 Casing Design ........................................................................................................................... 67
30.0 MASP ....................................................................................................................................... 68
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 70
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 71
Page 2
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU L-295
Pad Prudhoe Bay L Pad
Planned Completion Type 4-1/2” Injection
Target Reservoir(s) Schrader Bluff NB Sand
Planned Well TD, MD / TVD 20,044’ MD / 4,049’ TVD
PBTD, MD / TVD 20,033’ MD / 4,049’ TVD
Surface Location (Governmental) 2297' FSL, 4038' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582,879.3, Y=5,978,015
Top of Productive Horizon
(Governmental)1176' FNL, 1373' FWL, Sec 28, T12N, R11E, UM, AK
TPH Location (NAD 27) X=577,640, Y=5,985,045
BHL (Governmental) 127' FNL, 799' FEL, Sec 19, T12N, R11E, UM, AK
BHL (NAD 27) X= 570,106, Y= 5,991,299
AFE Drilling Days 35
AFE Completion Days 3
Maximum Anticipated Surface
Pressure (intermediate) 1398 psi
Maximum Anticipated Surface
Pressure (production) 1398 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 1810 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft +47.2ft =73.9ft
GL Elevation above MSL: 47.4 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
L-293 S
Page 3
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.750”10.625”40 L-80 BTC 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 BTC 6,870 4,750 1,086
8-1/2” 7” 6.276 6.151 7.875 26 L-80 BTC 7240 5410 604
6-1/8”4-1/2” 3.958 3.833 5.2 12.6 L-80 H563 8,430 7,500 288
3-1/2” 2.992 2.867 4.25 9.2 L-80 H563 10,160 10,540 207
Tubing 4-1/2” 3.958 3.833 5 12.6 L-80 JFE BEAR 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Intermediate
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
Production 4”3.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Aras Worthington 907.440.7692 aras.worthington@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Natalie Brent 907.564.4313 nbrent@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-295 is a grassroots injector planned to be drilled in the Schrader Bluff NB sands. L-295 is part of a
multi-well program targeting the Schrader Bluff sand on PBU L-pad
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set below the SV1. 8-1/2” intermediate
hole will be drilled into the top of the Schrader Bluff NB sand, with 7” casing ran and cemented. A 6-1/8”
lateral section will be drilled. A 4-1/2” x 3-1/2” slotted liner will be run in the open hole section, followed
by 4-1/2” injection tubing. This well will not be pre-produced prior to being on injection.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately December 13, 2023, pending rig schedule.
Surface casing will be run to 5,300’ MD / 2,626’ TVD and cemented to surface via a two stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” to section TD, Run and cement 7” casing
6. Drill 6-1/8” lateral to well TD
7. Run 4-1/2” liner
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface & Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
p
This well will not be pre-produced prior to being on injection.
Page 8
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-295. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
Page 9
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states:
“A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates
pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure
that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the
maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured
depth above the top of the perforations, unless the commission approves a different placement depth as the
commission considers appropriate given the thickness and depth of the confining zone.”
In order to effectively produce this fault block, the current wellplan has the intermediate casing shoe landing at
the NB production interval at 90 degrees inclination. The production packer is planned to be set ~ 680’ MD above
the liner top packer, ~ 800’ MD above the 7” casing shoe to allow for spacing of the x nipple beneath it at a pump
downable depth at 75* inclination. The intermediate casing shoe is planned at ~10,240’ MD / 4113’ TVD which
means the planned packer depth is ~800’ MD away. From a TVD standpoint, the production tubing packer is
~143’ TVD from the intermediate casing shoe. With the intermediate casing set in the Schrader Bluff sand, and
the injection packer set inside the intermediate casing, injection fluids will be confined to the Schrader bluff
sands.
10,000 4,099 -mgr
Page 10
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2” & 6-1/8”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-295 will utilize a 20” conductor on L-pad. Ensure to review attached surface plat and make
sure rig is over appropriate conductor.
9.2 Ensure PTD, COAs, and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
x Cold mud temps are necessary to mitigate hydrate breakout
9.10 Ensure 5” liners in mud pumps.
x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
Page 12
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x N/U 20” x 13-5/8” DSA
x N/U 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC with 24 hour notice to witness. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
Page 13
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
Page 14
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD below the SV1 sand. Confirm this setting depth with the
Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in
DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still
meeting tangent hold target.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at
base of perm and at TD.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
x Gas hydrates have been seen at L-Pad
Page 15
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.5+ (For Hydrates/Free Gas based on offset
wells)
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Page 16
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
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. Observe well for flow.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No wireline logging program planned.
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Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” BTC x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.75” on the location prior to running.
x Top 2,500’ of casing 47# drift 8.525”
x Actual depth to be dependent upon base of permafrost and stage tool
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is coreclty 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.
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L-293 SB Injector
Drilling Procedure
12.5 Float Equipment and Stage tool equipment drawings
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Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x Bowspring Centralizers only
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~ 1,000’ above shoe
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.
9-5/8” 47# L-80 BTC Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”Make Up to Triangle
9-5/8” 40# L-80 BTC Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”Make Up to Triangle
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L-293 SB Injector
Drilling Procedure
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Drilling Procedure
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Drilling Procedure
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, actual depth based upon base of permafrost)
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.
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.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Centralizers 1/jt for 5 joints above and below stage tool.
x Confirm stage tool depth compatibility with cancellation plug, inclination sensitive
12.10 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
x Actual length of 47# may change due to depth of permafrost as drilled
x Ensure drifted to 8.525”
12.11 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary. Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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L-293 SB Injector
Drilling Procedure
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Casing (5,300'-1,000'-2,500') x 0.0558 bpf x 1.3 130.5 732.3
Total Lead 130.5 732.3 311.6
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
Le
a
d
Ta
i
l
108.8 610 260
5000
- mgr
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Prudhoe Bay West
L-293 SB Injector
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 continu
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:
x 2500’ x 0.0732 bpf + (5,300’-120’-2500’) x .0758 bpf =
x = 386.3 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
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.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mixed
Water 13.92 gal/sk 4.95 gal/sk
5000
363.4 -mgr
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Drilling Procedure
13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.15 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher
pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or
cement returns to surface and volume pumped to see the returns. Circulate until YP < 20
again in preparation for the 2nd stage of the cement job.
x Ensure the free fall stage tool opening plug is available. This is the back-up option to open
the stage tool if the plugs are not bumped.
13.16 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
13.17 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
13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.19 Fill surface lines with water and pressure test.
13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.21 Mix and pump cmt per below recipe for the 2
nd stage.
13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. Cement will continue to be pumped until
clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd Stage):
13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.25 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.26 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.
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 3 316.4 1775.0
Total Lead 345.0 1935.5 672.0
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
Le
a
d
Ta
i
l
Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 11.0 lb/gal 15.8 lb/gal
Yield 2.535 ft3/sk 1.16 ft3/sk
Mixed
Water 12.2 gal/sk 5.06 gal/sk
763.8 -mgr
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L-293 SB Injector
Drilling Procedure
13.27 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.
13.28 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.
13.29 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.
Cement displacement volume to 2500' MD 2500' X 0.0732 = 183 bbls -mgr
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Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 Give AOGCC 24hr notice of BOPE test, for test witness.
14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.3 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve.
14.4 RU MPD RCD and related equipment
14.5 Run 5” BOP test plug
14.6 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 4-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.7 RD BOP test equipment
14.8 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.9 Mix 9.5 ppg spud mud to be used in intermediate hole
14.10 Set wearbushing in wellhead.
14.11 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.12 Ensure 5” liners in mud pumps.
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Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 P/U 8-1/2” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the intermediate hole section.
15.2 TIH to TOC above the shoetrack. Note depth TOC tagged on morning report.
15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and
volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin
17-001.
15.4 Drill out shoe track and 20’ of new formation.
15.5 CBU and condition mud for FIT.
15.6 Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 11.5 ppg provides >25 bbls based on 9.5ppg MW, 8.46 ppg PP (swab kick at 8.46 ppg BHP).
15.7 Drill 8-1/2” hole section to section TD in the Schrader NB sand. Confirm this setting depth with
the Geologist and Drilling Engineer while drilling the well.
x Efforts should be made to minimize dog legs. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Well control procedures
x Flow rates, hole cleaning, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen.
x Slow in/out of slips and while tripping to keep swab and surge pressures low.
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a ~9.5 by
TD.
Email casing test and digital data to AOGCC immediately upon completion of FIT. email: melvin.rixse@alaska.gov
Page 30
Prudhoe Bay West
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Drilling Procedure
x Intermediate Hole AC:
x There are two exploration wells that have been P&A’d that have CF <1.0. The
risk posed by these wells is damage to the drill bit, requiring a BHA trip
x NWEILEEN-1 @ 8234’ MD
x NWEILEEN-2 @ 6,600’ MD
15.8 8-1/2” 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 same ppg as
surface TD MW and ensure we TD with 9.5+ ppg.
Depth Interval MW (ppg)
Surface shoe - TD 9.5+
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
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Prudhoe Bay West
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Drilling Procedure
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
15.9 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
15.10 RIH to bottom, proceed to BROOH to surface casing shoe
x Pump at full drill rate and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
15.11 CBU at casing shoe
15.12 TOOH and LD BHA
15.13 No wireline logging program planned
LWD gamma ray and resistivity data to AOGCC promptly to confirm required location for TOC on
8-1/2" OH x 7" annulus.
-mgr
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L-293 SB Injector
Drilling Procedure
16.0 Run & Cement 7” Intermediate Casing
16.1 R/U and pull wearbushing.
16.2 R/U 7” casing running equipment (CRT & Tongs)
x Ensure 7” BTC x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Plan to land the 7” casing on a mandrel hanger.
16.3 P/U shoe joint, visually verify no debris inside joint.
16.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
7” Float Shoe
1 joint – 7”, 2 Centralizers 10’ from each end w/ stop rings
1 joint –7”, 1 Centralizer mid joint w/ stop ring
1 joint – 7”, 1 Centralizer mid joint with stop ring
7” Float Collar
16.5 Continue running 7” intermediate casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 500’ MD above Schrader Bluff
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
7” 29# L-80 BTC Make-Up Torques:
Casing OD Minimum Optimum Maximum
7”Make Up to Triangle
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Drilling Procedure
Page 34
Prudhoe Bay West
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Drilling Procedure
16.6 Continue running 7” casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
16.8 Slow in and out of slips.
16.9 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
16.10 Lower casing to setting depth. Confirm measurements.
16.11 Have emergency slips staged along with necessary equipment for the operation.
16.12 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
16.13 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
16.14 Document efficiency of all possible displacement pumps prior to cement job.
16.15 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
16.16 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
16.17 Fill surface lines with water and pressure test.
16.18 Pump 60 bbls 11 ppg tuned spacer.
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Drilling Procedure
16.19 Mix and pump cmt per below recipe.
16.20 Cement volume based on annular volume + open hole excess (40%). Job will consist of tail,
TOC brought to 500’ above Ugnu LA (Note: TOC may be adjusted if formations are found to
be wet or hydrocarbon bearing.)
x Prognosed Ugnu LA: 8,568’ MD, Planned TOC: 8,068’ MD
x The two previous 3 string SB wells on L pad (L-292, L-293) had approved TOC 500’ MD
above the Ugnu LA, uppermost significant oil
Estimated Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
16.21 After pumping cement, drop top plug and displace cement with mud out of mud pits.
x Displacement: (10,240’-120’) * .0383 = 387.3bbl
16.22 Monitor returns closely while displacing cement. Adjust pump rate if necessary.
16.23 Land top plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats.
If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds
compressive strength.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
8.5" OH x 7" (10,240 - 8,068)' x 0.0226 bpf x 1.4 = 68.7 385.4
7" Shoetrack 120' x 0.0372 bpf = 4.5 25.2
Total Tail 73.2 410.7 354.0
Ta
i
l
Tail Slurry
System HalCem
Density 15.8 lb/gal
Yield 1.16 ft3/sk
Mixed
Water 5.06 gal/sk
378.4 -mgr
318
10,000
d TOC 500’ MDpg p(
above the Ugnu LA, uppermost significant oil
368.265.5
22 sx
61 296 sx
10,000
343
- mgr
Page 36
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
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.
Page 37
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
17.0 Drill 6-1/8” Hole Section
17.1 MU 6-1/8” Cleanout BHA (Milltooth Bit & 1.22° PDM)
17.2 TIH w/ 6-1/8” cleanout BHA to float collar with 4” dp
17.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and
volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin
17-001.
17.4 Drill out shoe track and 20’ of new formation.
17.5 CBU and condition mud for FIT.
17.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.8 ppg FIT is the minimum
required to drill ahead
x 9.8 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5ppg BHP)
17.7 POOH and LD cleanout BHA
17.8 PU 6-1/8” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 4” 14# XT39
x Run a ported float in the production hole section.
17.9 6-1/8” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
Email casing test and FIT digital data to AOGCC immediately upon completion of FIT. email: melvin.rixse@alaska.gov
Page 38
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total
Solids
MBT HPHT Hardness
Production 8.9-9.5 15-25 -
ALAP
15 - 30 4-6 <10% <8 <11.0 <100
System Formulation:
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 – 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
17.10 TIH with 6-1/8” directional assembly to bottom
17.11 Install MPD RCD
17.12 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
x Density may change based upon TD of surface hole section
Page 39
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
17.13 Begin drilling 6-1/8” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 150-250 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in NB sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff NB Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 6-1/8” Lateral A/C:
x There are no wells with CF < 1.0
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV and rotation (120+ RPM). Pump tandem sweeps if
needed
17
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Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
17.14 Monitor the returned fluids carefully while displacing to brine.
15.19 BROOH with the drilling assembly to the 7” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 7” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
17.20
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Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
x Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
Page 42
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
18.0 Run 4-1/2” x 3-1/2” Injection Liner
18.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner, the following well control response procedure will be followed:
x P/U & M/U the 4” safety joint (with 3-1/2” crossover installed on bottom, TIW valve in open
position on top, 3-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 3-1/2” liner.
x Ensure 4-1/2” XO and safety joint available on floor as well
x Slack off and with 4” DP across the BOP, shut in ram or annular on 4” DP. Close TIW.
x Proceed with well kill operations.
18.2 R/U 3-1/2” liner running equipment.
x Ensure 3-1/2” 9.2# W563 x HT38 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info
18.3 Run ~5000’ of 3-1/2” Slotted Liner
18.4 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 12.6# W563 x HT38 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
18.5 Run 4-1/2” x 3-1/2” 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” & 3-1/2” liner connections.
Page 43
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Well: L-295 Approx Depth
Description
Liner Top Hanger/Packer Assembly (7" x 5")10,090' md
5" x 4-1/2" XO 10,140' md
4-1/2" WH563 w/ 10' slots in middle of joint every ~500'10,190' md - 15,000' md
4-1/2" WH563 x 3-1/2" WH563 XO ~15,000' md
3-1/2" H563 w/ 10' slots in middle of joint every ~500'15,000' md - 20,040' md
3-1/2" Shoe 20,040' md
10,000' MD is the 7" casing shoe.
Recalculate! - mgr
Page 44
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Page 45
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Page 46
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
18.6 Ensure to run enough liner to provide for setting the liner hanger at ~ 10,090 MD
x Confirm set depth with completion engineer.
18.7 Ensure hanger/pkr will not be set in a 7” 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 7” connection.
18.8 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
18.7 M/U Baker SLZXP liner top packer to 4-1/2” liner.
18.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
18.9 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 4” DP/HWDP has been drifted
18.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
18.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
18.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
18.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
18.14 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
18.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
18.16 Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
Page 47
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
18.17 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
18.18 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
18.19 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
18.20 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
18.21 PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
18.22 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
Page 48
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
19.0 Run Upper Completion/ Post Rig Work
19.1 RU to run 4-1/2”, 12.6#, L-80 JFEBear tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, JFEBear 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.
x Draft Running Order:
Well: L-295 Approx Depth
Description
4-1/2” Tbg Hanger 0'
XO Pup Joint to 4-1/2" JFE Bear
4-1/2” L-80 JFE Bear
Spaceout Pups (As Needed): 2 ft, 4ft, 6ft, 8ft etc.
4-1/2” L-80 JFE Bear
Pup Joint - 4-1/2” JFE Bear b x p, ~10’
X Nip (ID=3.813”), 4-1/2” JFE Bear b x p 5100' md
Pup Joint - 4-1/2” JFE Bear b x p, ~10’
4-1/2” L-80 JFE Bear
Pup Joint and XO - 4-1/2”JFE Bear, ~10’
X Nip (ID=3.813”), 4-1/2” JFE Bear b x p 9380' md
Pup Joint and XO - 4-1/2”JFE Bear, ~10’
Full Joint - 4-1/2" JFE Bear b x p, 40’
Pup Joint - 4-1/2” JFE Bear b x P, ~10’
7”x4-1/2” L-80 HES TNT Packer JFE Bear Box x JFE Bear pin 9440' md
Pup Joint and XO - 4-1/2”JFE Bear, ~10’
Full Joint - 4-1/2" JFE Bear b x p, 40’
Pup Joint and XO - 4-1/2”JFE Bear, ~10’
X Nip (ID=3.813”), L-80 4-1/2” JFE Bear b x p (With RHC Body Installed)9500' md
Pup Joint and XO - 4-1/2”JFE Bear, ~10’
4-1/2” L-80 JFE Bear
4-1/2" L-80 JFE Bear WLEG 9850' md
Page 49
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Page 50
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
19.2 PU, MU and RH with the following 4-1/2” injection completion jewelry (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 1x X Nipple
x 1x X Nipple w/ sliding sleeve
x 1x Production Packer
x 1x X Nipple
x XXX joints, 4-1/2”, 12.6#, L-80, JFEBear
x X1 WLEG, set as close to 7” x 4-1/2” liner xo as possible
19.3 PU and MU the 4-1/2” tubing hanger.
19.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
19.5 Land the tubing hanger and RILDS. Lay down the landing joint.
19.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
19.7 NU the tubing head adapter and NU the tree.
19.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
19.9 Pull the plug off tool and BPV.
19.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel
freeze protect for both tubing and IA to 2,500’ MD.
19.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
19.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
i. AOGCC must be notified with opportunity to witness this test
ii. 10-426 form to be filled out and sent to AOGCC after completion, reviewed by
completion engineer
19.13 Bleed both the IA and tubing to 0 psi.
19.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
19.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
24 hour notice for state to witness. - mgr
Page 51
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
19.16 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
2. Fullbore
a. Shear hydraulic toe port
3. Coil
a. Shift injection sleeves open
4. Well Tie in
5. Put well on injection
a. AOGCC witnessed MIT-IA once injection is stable
No GLVs in this PTD. - mgr
24 hour notice to AOGCC.
Slotted liner. No sliding sleeves. - mgr
- mgr
Page 52
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
20.0 Innovation Rig Diverter Schematic
Page 53
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
21.0 Innovation Rig BOP Schematic
Page 54
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
22.0 Wellhead Schematic
Page 55
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
23.0 Days Vs Depth
Page 56
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
24.0 Formation Tops & Information
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Page 57
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Page 58
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
25.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs.
PBU L-pad has a history of H2S ony
wells in all reservoirs.
Page 59
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 60
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs.
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.
Abnormal Pressures and Temperatures:
Page 61
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Gas Cut Mud
Gas cut mud as been seen on L pad, ensure sufficient MW is used during hole section. Ensure gas
detectors are always functioning. Watch swab effect.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Casing Running
Casing running issue have been noted on L pad, gravels, stability wood chunks, etc. Watch casing run,
and ensure to condition hole prior to running casing, ex: backream trouble intervals.
8-1/2” Section specific A/C:
x There are two exploration wells that have been P&A’d that have CF <1.0. The risk posed by
these wells is damage to the drill bit, requiring a BHA trip
x NWEILEEN-1 @ 8234’ MD
x NWEILEEN-2 @ 6,600’ MD
Page 62
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
6-1/8” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole.
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs.
4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 63
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
6-1/8” Lateral A/C:
x There are no wells with a CF <1.0
p
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Page 64
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
26.0 Innovation Rig Layout
Page 65
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 66
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
28.0 Innovation Rig Choke Manifold Schematic
Page 67
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
29.0 Casing Design
Page 68
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
30.0 MASP
Page 69
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
Page 70
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 71
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Built) (NAD 27)
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West(-)/East(+) (2000 usft/in)
L-295 wp03 CP1
L-295 wp01 CP6
L-295 wp01 CP5
L-295 wp01 CP4
L-295 wp01 CP3
L-295 wp01 CP2
9 5/8" x 12 1/4"
7" x 8 1/2"
4 1/2" x 6 1/8"
5 0 0
1 2 5 0
1 5 0 0
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4049
L-295 wp06
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 4.5º/100' : 450' MD, 449.63'TVD
End Dir : 1897.33' MD, 1521.61' TVD
Fault (25' - 30' DTSE throw)
Start Dir 4º/100' : 9532.04' MD, 3999.66'TVD
End Dir : 10089.43' MD, 4106.05' TVD
Start Dir 3º/100' : 10239.43' MD, 4113.9'TVD
Begin Geosteering lateral
Total Depth : 20044.41' MD, 4048.9' TVD
CASING DETAILS
TVD TVDSS MD Size Name
2626.04 2552.14 5300.00 9-5/8 9 5/8" x 12 1/4"
4113.89 4039.99 10239.33 7 7" x 8 1/2"
4048.90 3975.00 20044.31 4-1/2 4 1/2" x 6 1/8"
Project: Prudhoe Bay
Site: L
Well: Plan: L-295
Wellbore: L-295
Plan: L-295 wp06
WELL DETAILS: Plan: L-295
47.40
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
5978015.01 582879.31 70° 20' 59.6946 N 149° 19' 37.6457 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-295, True North
Vertical (TVD) Reference:L-295 As-Built @ 73.90usft
Measured Depth Reference:L-295 As-Built @ 73.90usft
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.
PRUDHOE BAY
X
SCHRADER BLUFF OIL POOL
PBU L-295
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L
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F
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-
6
4
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3
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g
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d
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4
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5
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NA
6
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7
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8
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Ye
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9
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p
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Ye
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10
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Ye
s
11
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12
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13
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d
a
y
w
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Ye
s
A
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2
6
B
14
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l
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w
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p
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m
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(
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15
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l
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w
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1
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4
m
i
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a
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d
(
F
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l
y
)
No
16
P
r
e
-
p
r
o
d
u
c
e
d
i
n
j
e
c
t
o
r
:
d
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a
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s
(
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NA
17
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18
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19
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20
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21
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22
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23
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24
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25
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26
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27
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.
28
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.
29
B
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P
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s
,
d
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30
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31
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32
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.
33
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p
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c
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2
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p
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s
34
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c
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a
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c
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c
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d
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t
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f
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f
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p
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2
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4
(
2
0
2
1
)
35
P
e
r
m
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t
c
a
n
b
e
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s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
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m
e
a
s
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r
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s
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s
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o
r
m
a
l
p
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s
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g
r
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d
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n
t
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d
.
M
P
D
t
o
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t
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l
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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
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k
l
y
p
r
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g
r
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s
s
r
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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
12
/
1
3
/
2
0
2
3
Ap
p
r
MG
R
Da
t
e
12
/
1
3
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2
0
2
3
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p
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AD
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Da
t
e
12
/
1
2
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2
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2
3
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m
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s
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r
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Ge
o
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Co
m
m
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t
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En
g
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Co
m
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s
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Pu
b
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Co
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m
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r
Da
t
e
*&
:
JL
C
1
2
/
1
3
/
2
0
2
3
