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Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
06/09/2025
Mr. Jack Lau
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 06/09/2025.
Dear Mr. Lau,
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 06/09/2025.
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 (4525)
DN: cn=Oliver Sternicki (4525)
Date: 2025.06.09 14:30:46 -
08'00'
Oliver Sternicki
(4525)
Hilcorp North Slope LLC.Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-offReport of Sundry Operations (10-404)06/09/2025Well NamePTD #API #Initial top of cement (ft)Vol. of cement pumped (gal)Final top of cement (ft)Cement top off date Corrosion inhibitor (gal)Corrosion inhibitor/ sealant dateF-10C21308650029204100365/29/25F-29B2111475002921627026.25/29/25F-33A20816350029226400145/29/25F-3619519650029226310035/29/25F-39190141500292210100175/29/25F-44A2051615002922130012.55/29/25F-47B21007950029222320215/29/25L-2512231065002923772001.8813/31/24117/29/24L-2532230485002923758004.1201.13/31/24127/29/24L-2542230305002923752003.8321.23/31/24137/29/24L-2922230255002923751003.3301.33/31/24147/29/24N-282141275002923524006.8504.711/19/242212/28/24N-302141245002923523003.5330.311/17/243.512/28/24PAVE1-122309450029237670019.910/27/24PWDW3-221908150029236340014.810/27/24S-40120607850029233130015.31130.511/15/24412/28/243.8321.23/31/247/29/24L-25422303050029237520013
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: 10/04/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241004
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BRU 214-13 50283201870000 222117 9/26/2024 AK E-LINE Perf
END 2-72 50029237810000 224016 8/26/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON RBT
MPI 2-16 50029218850000 188134 9/9/2024 AK E-LINE Perf
MPI 2-16 50029218850000 188134 9/20/2024 AK E-LINE Perf
MPU B-16 50029213840000 185149 9/28/2024 READ CaliperSurvey
MPU B-24 50029226420000 196009 8/20/2024 HALLIBURTON PERF
MPU B-28 50029235660000 216027 9/28/2024 HALLIBURTON TUBINGCUT
MPU I-01 50029220650000 190090 8/17/2024 HALLIBURTON PERF
MPU R-103 50029237990000 224114 9/20/2024 AK E-LINE Hoist
MRU M-02 50733203890000 187061 9/23/2024 AK E-LINE Perf
PBU 02-21B 50029207810200 211033 9/30/2024 HALLIBURTON RBT
PBU L2-10 50029217460000 187085 8/23/2024 HALLIBURTON RBT
PBU L-212 50029232520000 205030 9/24/2024 HALLIBURTON IPROF
PBU L-254 50029237520000 223030 9/20/2024 HALLIBURTON IPROF
PBU P1-17 50029223580000 193051 9/7/2024 HALLIBURTON RBT
PBU S-09A 50029207710100 214097 8/21/2024 HALLIBURTON RBT
PBU Z-235 50029237600000 223055 9/19/2024 HALLIBURTON IPROF
Please include current contact information if different from above.
T39619
T39620
T39620
T39620
T39621
T39621
T39622
T39623
T39624
T39625
T39626
T39627
T39628
T39629
T39630
T39631
T39632
T39633
T39634
PBU L-254 50029237520000 223030 9/20/2024 HALLIBURTON IPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.10.04 15:10:24 -08'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 12/18/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL : **REVISED DUE TO MISSING DATA**
WELL: PBU L-254
PTD: 223-030
API: 50-029-23752-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (06/10/2023 to 06/27/2023)
x EWR-M5, AGR, ABG, DGR, ADR, ALD, CTN, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU L-254 LWD Subfolders:
PBU L-254 Geosteering Subfolders:g
Please include current contact information if different from above.
Revised
PTD: 223-030
PBU L-254: T37883
PBU L-254 PB1: T37884
12/20/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.20
10:17:40 -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
WELL: PBU L-254PB1
PTD: 223-030
API: 50-029-23752-70-00
**REVISED DUE TO MISSING DATA**
FINAL LWD FORMATION EVALUATION LOGS (06/10/2023 to 06/24/2023)
x EWR-M5, AGR, ABG, DGR, ADR, ALD, CTN, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
PBU L-254PB1 LWD Subfolders:
Please include current contact information if different from above.
12/20/2023
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, December 5, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Bob Noble
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
L-254
PRUDHOE BAY UN ORIN L-254
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 12/05/2023
L-254
50-029-23752-00-00
223-030-0
W
SPT
4342
2230300 1500
359 359 359 359
285 476 463 458
INITAL P
Bob Noble
10/8/2023
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PRUDHOE BAY UN ORIN L-254
Inspection Date:
Tubing
OA
Packer Depth
296 1720 1656 1649IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitRCN231009090318
BBL Pumped:1.1 BBL Returned:1.1
Tuesday, December 5, 2023 Page 1 of 1
pre-produced WAG injector at time of test
"
By Grace Christianson at 3:21 pm, Oct 09, 2023
Completed
7/3/2023
JSB
RBDMS JSB 101123
GDSR-11/2/23
/ 323-381
Drilling Manager
10/09/23
Monty M
Myers
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.10.09 14:43:45 -08'00'
Torin
Roschinger
(4662)
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-254 Date:6/20/2023
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Amend/Carter
Csg Setting Depth:7235 TMD 4525 TVD
Mud Weight:9.2 ppg LOT / FIT Press =697 psi
LOT / FIT =12.16 ppg Hole Depth =7264 md
Fluid Pumped=1.4 Volume Back =1.3 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->240 ->00
->4104 ->8158
->6159 ->16 418
->8225 ->24 657
->10 286 ->30 830
->12 348 ->35 980
->14 418 ->40 1139
->16 483 ->45 1300
->18 547 ->50 1456
->20 615 ->60 1793
->22 677 ->70 2127
->24 697 ->80 2461
-> ->87 2695
-> ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0697 ->02695
->1670 ->12679
->2655 ->22667
->3643 ->32658
->4633 ->42653
->5625 ->52651
->6618 ->10 2650
->7610 ->15 2646
->8606 ->20 2646
->9601 ->25 2643
->10 596 ->30 2641
-> ->
-> ->
-> ->
2
4
6
8
10
12
14
16
18
20
2224
0
8
16
24
30
35
40
45
50
60
70
80
87
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
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Activity Date Ops Summary
6/8/2023 PJSM Stomp Sub over L-254 and level. Set outriggers, retract all stompers. Set Catwalk, level and shim. Install Diverter Tee to 13 5/8" adapter on well head. Set
remaining rig matts. Spot Pipe Shed, Mud Mod & Gen Mod, Released Cruz trucks at 02:30. PJSM Hook up steam, air & H2O. Install interconnects, Gas Buster, flow
line and mud line. Went to Gen power at 03:30. Set Enviro Vac, break shack & cutting box. Scope up derrick and R/D bridal lines. Start working on rig acceptance
check list.
6/9/2023 Continue working on Rig Acceptance Checklist. Change out Bell guide, die blocks and install new NC50 Saver Sub. Change out broken whip check on Kill Line in
Cellar. Troubleshoot cavitating lube pump. Load and process 5" NC50 DP in the shed. Service Top Drive and add more oil to TD lube pump to reduce cavitation.
Service Trip tank feed pump. Install knife valve and diverter sections, 80' from closes ignition source. Tighten bolts and install trip nipple flange and trip nipple with
additional airboots in place. Released Crane 17:00. Secure Stack. NOV Reps on location to service Centrifuges and Shakers. Install conductor valves. Install
Koomey lines from the Annular to the knife valve. Obtain RKB Ann 11.5' Knife 22.5" GL 26.68'. Take on 580 bbls 8.7 ppg Spud Mud. Process 5" D.P. in pipe shed.
Rig accepted at 18:30. PJSM Perform Annular closure 12 sec, knife 6 sec. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors
and return flow. Koomey draw drown Initial System 3,050 PSI, after System 2,225 PSI, 200 PSI increase 18 Sec, full charge 42 sec. Nitrogen 6 bottle average 2,350
PSI. 16 vent line 214', length F/ sub 199', ignition source 80'. Witnessed by AOGCC rep Sully Sullivan. SIMOPS Process 5" D.P. PJSM M/U wear ring pulled to 5"
D.P. BOLDS (2ea) Pull wear ring. L 14.25" ID 12.375" OD 13.25". Reinstall wear ring. RILDS. PJSM Cont to process 5" D.P. in pipe shed. 232 jnts and 20 jnts 5"
HWDP. Install Centrifuge #2 feed pump housing. PJSM Install long mouse hole. Build stands P/U 5" 19.5# S-135 NC50 D.P. and rack back in derrick 11 stands.
(22 jnts) Drift OD 3.125". PJSM Build stands P/U 5" 19.5# S-135 NC50 D.P. and rack back in derrick 105 stands. (210 jnts) Drift OD 3.125".
6/10/2023 Pickup 9 joints 5" NC-50 49# S-135 HWDP, racking back and rack back 6-1/2" Jar/HWDP combo using 2.75" Drift. PJSM for picking up Conductor Clean out BHA.
Pickup 12.25 Kymera (K5M633, SN# 5340167) with a 0.8399 TFA. Make up bit to a 1.5 degree Terraforce Motor torquing Bit to 52K. P/U NC50 Cross over and .
Hold Pre-Spud meeting for Drilling L-254 targeting the OBd Sands. RIH F/Surface -T/46' MD and tag up with 5K. Flood Lines and Pressure test to 3000 psi on
Surface Equipment - Good. Wash down F/46' - T/106' at 350gpm=320psi with a return flow of 37%. RPM=40k at 0.75K TQ. WOB=2-3K. ROT=41K. Drill 12-1/4"
Surface F/106' - T/ 220' at 350gpm=347psi. RPM=40K at 1-1.5K TQ. WOB 2-3K. Drilled Mostly thru sand until 210' before we started seeing large gravel at the
shakers. Washed a joint up F/220' - T/180' back down to 220'. Pulled out of the hole on elevators F/220' - T/Mud Motor. P/U 44k, S/O41K. PJSM Picking up BHA.
Bring to the floor Remaining MWD Assembly (GWD, DM, and TM). Continue M/U Directional BHA. MWD/GWD offset is 77.37 degrees, Motor/MWD offset is 312.9
degrees as confirmed by DSM, DD and MWD. Download to MWD and M/U remaining NM Flex Collars and HWDP. Wash down F/152' - T/220' MD, observing no
fill. Drill 12-1/4" Surface hole F/220' - T/283' MD beginning a 3deg/100' build KOP 220' MD targeting 220 deg Azi, Sliding at 100fph. 425gpm=822psi, RF=67%,
P/U=56k, S/O=58K. Jet flowline as needed and pump through bleeder at connections. Slide/ Rot 12.25" Surface Hole F/ 283' to 470' MD (463' TVD) Total 187'
(AROP. 46.8') 400 GPM, on 750 psi off 705 psi, F/O 52%, WOB 5-8k. ECD N/A. Max Gas 0u. P/U 60K, SLK 62K. Jet flowline, pump through bleeder at
connections. At 400' MD appears PWD annular pressure. Cont build 3/100 as per plan. failed. attempted a reset W/ no success. Drilled to 470' MD and tried
manual reset, failed. Decision was made to POOH. PJSM BROOH F/ 470' to 162' MD 400 gpm 655 psi 30 rpm Trq 1k F/O 45% P/U 62k SLK 62k ROT 61k.
Reduced flow to 300 gpm 425 psi at 280' MD. PJSM Rack back NM FC. P/U read tools. P/U to EWR-M5 and screens were clean. P/U 45k SLK 45k. PJSM L/D TM
collar & EWR-M5. P/U new/ spare 8" EWR-M5. M/U 8" TM collar and download tools. New BHA #2 length 723.02'. RIH F/ 98' to 470' MD. Washed last stand 5"
HWDP and encountered 12' of fill. 400 gpm 790 psi. Slide/ Rot 12.25" Surface Hole F/ 470' to 645' MD (641' TVD) Total 175' (AROP. 70') 400 GPM, on 945 psi off
815 psi, 40 RPM TRQ on 1.5k off 2.5k F/O 50%, WOB 5-8k. ECD 9.76 . Max Gas 0u. MW in/out 8.95 P/U 64k, SLK 66k ROT 66k Jet flowline, pump through
bleeder. Cont build 3/100 as per plan. Distance to WP04: 4.14', 2.17' Low 2.3' Left.
6/11/2023 Drill 12-1/4" Surface Hole F/645' - T/1,164' MD (Total: 519', AROP. : 87'). Predominantly sliding at 4deg/100', and rotating last 5' of stand. MW=9.1ppg (9.8ppg
ECD) with FV220. 450gpm=1240/1070psi on/off with 50% RF. TQ=2.8K/2.2K ft-lbs on/off at 40RPM with 5-12K WOB. P/U=67K, S/O=73K, ROTW=74K,. Last
Gyro Survey at 743.86' MD. Clean MWD Survey at 793.62' MD. No downhole losses observed and max Gas has been <28u. Drill 12-1/4" Surface Hole F/1,164' -
T/1,802' MD, 1,570' TVD (Total: 638', AROP. : 107'). MW=9.35ppg (10.8ppg ECD) with FV233. 450gpm=1411/1350psi on/off with 54% RF. TQ=4-5K/3-4K ft-lbs
on/off at 40RPM with 8-12K WOB. P/U=80K, S/O=68K, ROTW=72K. Backreaming full stands at 1,736' MD. Maintained the 4deg/100' build until 1,527'. Currently
rotating through our tangent maintaining a 52 degree inclination at an azimuth of 220 degrees. Completing maintenance slides as necessary. No downhole losses
observed and max gas has been <34u. Slide/ Rot 12.25" Surface Hole F/ 1,802' to 2,372' MD (1,894' TVD) Total 570' (AROP. 95') 375-450 GPM, on 1,025 psi off
1,000 psi, 60 RPM, TRQ on 5k, off 4.5k, F/O 56%, WOB 6-14k. ECD 10.1. Max Gas 3,835u. P/U 98K, SLK 72K, ROT 80K. Jet flowline as needed. BPF logged at
2,108' MD 1,737' TVD. At 2,175' MD encountered hydrates breaking out at surface. Reduced flow to 375 gpm and ROP 150 fph to control break out and shakers
running over. Slide as needed to hold tangent 51.93 deg inc 221.38 deg azi. Slide/ Rot 12.25" Surface Hole F/ 2,372' to 2,882' MD (2,215' TVD) Total 510' (AROP.
85') 375-450 GPM, on 1,420 psi off 1,310 psi, 60 RPM, TRQ on 4.6k, off 4.5k, F/O 49%, WOB 3-10k. ECD 10.47. MW in/out 9.6 ppg Max Gas 2,768u. P/U 101K,
SLK 74K, ROT 85K. Jet flowline as needed. Adjusting flow rates as needed to control hydrates breaking out at surface and shakers running over. Distance to
WP04: 8.33', 5.92' Low 5.86' Right.
6/12/2023 Drill 12-1/4" Surface Hole F/2,882' - T/3,521' MD 2,614" TVD (Total: 639', AROP. : 107'). MW=9.55ppg (10.7ppg ECD) with FV135. 375-450gpm=1520/1425psi
on/off with 59% RF. TQ=6.7K/6.5K ft-lbs on/off at 60RPM with 3-10K WOB. Max Gas=4,087u, BGG=700-1100u. P/U=111K, S/O=81K, ROTW=91K,. Drill to 2,945'
and encounter 200bph dynamic loss rate dropping off to 30bph dynamic, total losses 103bbls. Gas Spiked to 2,205u. Continued drilling ahead at 150fph reducing
the flow rate to 375gpm. losses ceased. Complete maintenance slides as needed. Drill 12-1/4" Surface Hole F/3,521' - T/3,920' MD 2,850' TVD (Total: 399', AROP.
: 67'). MW=9.6ppg (10.25ppg ECD) with FV105. 375-450gpm=1820/1710psi on/off with 54% RF. TQ=8.2K/7.5K ft-lbs on/off at 70RPM with 8-12K WOB. Max
Gas=4,485u, BGG=600-3000u. P/U=120K, S/O=80K, ROTW=93K,. Rotating Predominantly but completing maintenance slides as necessary to maintain the
52deg tangent. Backreaming Full stands. Observed visible oil at the shakers at 3,835'. Reduce flowrate as needed to maintain mud on Shakers. Slide/ Rot 12.25"
Surface Hole F/ 3,920' to 4,344' MD (3,114' TVD) Total 424' (AROP. 70.6') 375-475 GPM, on 1,720 psi off 1,580 psi, 80 RPM, TRQ on 10-10.5k, off 9k, F/O 60%,
WOB 8-20k. ECD 10.4. MW in/out 9.6 ppg Max Gas 3,929u. P/U 131K, SLK 82K, ROT 100K. Jet flowline as needed. Back ream 60'. Adjusting flow rates as
needed to control hydrates breaking out at surface and shakers running over. Slide/ Rot 12.25" Surface F/ 4,344' to 4,779' MD (3,388' TVD) Total 435 (AROP.
72.5') 475 GPM, on 1,740 psi off 1,615 psi, 80 RPM, TRQ on 10-14k, off 11-12k, F/O 60%, WOB 8-12k. ECD 10.59. MW in/out 9.5 ppg Max Gas 3,220u BGG
~1450u. P/U 145K, SLK 82K, ROT 106K. Jet flowline as needed. Back ream 60'. Distance to WP04: 0.60', 0.53' Low 0.47' Right.
50-029-23752-00-00API #:
Well Name:
Field:
County/State:
PBW L-254
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
6/10/2023Spud Date:
6/13/2023 Drill 12-1/4" Surface Hole F/4,779' - T/5,234' MD 3,681" TVD (Total: 455', AROP. : 76'). MW=9.5ppg (10.61ppg ECD) with FV115. 475-500gpm=2039/1790psi
on/off with 60% RF. TQ=12-16K/13-15K ft-lbs on/off at 80RPM with 8-14K WOB. Max Gas=3,228u, BGG=500-700u. P/U=153K, S/O=85K, ROTW=107K,. No
downhole losses observed. Completing maintenance slides as necessary. Backreaming full stands (60'). Have not needed to reduce flow rate to keep mud on the
shakers. Drill 12-1/4" Surface Hole F/5,234' - T/5,545' MD 3,863" TVD (Total: 311', AROP. : 89'). MW=9.5ppg (10.37ppg ECD) with FV95. 500-
525gpm=2010/1920psi on/off with 63% RF. TQ=12-14K/12-13K ft-lbs on/off at 80RPM with 6-10K WOB. Max Gas=2,881u, BGG=600-900u. P/U=159K, S/O=87K,
ROTW=118K,. Rig Service/SIMOPS - Pick up off bottom and troubleshoot overheating issues in Gen Room. Rotate and Reciprocate at 20RPM, 125gpm. Open
Louvers manually and troubleshoot automatic actuators. Allowed for Gen Room to cool before proceeding. Drill 12-1/4" Surface Hole F/5,545' - T/5,680' MD 3,942
TVD (Total: 135', AROP. : 90'). MW=9.5ppg (10.3ppg ECD) with FV90. 525gpm=1975/1902psi on/off with 61% RF. TQ=14-17K/12-14K ft-lbs on/off at 80RPM with
8-16K WOB. Max Gas=781u, BGG=700u. P/U=159K, S/O=87K, ROTW=119K,. Slide/ Rot 12.25" Surface F/ 5,680' to 5,970' MD (4,115' TVD) Total 290 (AROP.
83') 525 GPM, on 1,955 psi off 1,912 psi, 80 RPM, TRQ on 15k, off 14-15k, F/O 62%, WOB 8-12k. ECD 10.3. MW in/out 9.5 ppg Max Gas 934u BGG ~150u. P/U
165K, SLK 88K, ROT 118K. Jet flowline as needed. Back ream 60'. At 5,867' MD Started build/turn 4deg/100'. At 5,970' MD Mud pumps faulted out. Was able to
reset MP 1 diode and Circ at 3 bpm 380 psi. Attempted to reset diode 2 but was faulted out due to over heating in VFR house Set up air mover and found one of the
air conditioners was not running. Called out electrician and was able to reset the air. conditioner and cool down VFR room before proceeding. Was able to reset
diode for MP 2. Slide/ Rot 12.25" Surface F/ 5,970' to 6,025' MD (4,130' TVD) Total 30' 525 GPM, on 1,955 psi off 1,912 psi, 80 RPM, TRQ on 15k, off 14-15k, F/O
62%, WOB 8-12k. ECD 10.3. MW in/out 9.5 ppg Max Gas 314u BGG 34u. P/U 172K, SLK 89K, ROT 120K. Jet flowline as needed. Back ream 60'. Cont 4 deg/
100' Build/turn. Mud pumps started limiting power. Gen #1 shut down & Gen #2 was brought online. Gen #2 & #3 shut down due to overheating. Found a breaker
tripped for automatic actuators for the louvers to Gen 2 & 4. Brought Gen #4 online and shut down due to overheating. Lights out on rig. Had to get another batter.
from Mud Mod cold start and start Gen Mod cold start. Manually opened all louvers in gen room. Was able to get Gen #2 and #4 going. Staging pumps up to 535
gpm 1,877 psi. Called out mechanic to trouble shoot Gen #1 not starting, replaced fire valve. Mechanic working on Gen #3 due not going into high. idle. Drawworks
failed to power back up due to 800A breaker failed to close in Sub Drive house. Decision was made not to proceed drilling until third generator was available for a
back up. Slide/ Rot 12.25" Surface F/ 6,025' to 6,200' MD (4,231' TVD) Total 175' (AROP. 58.3') 525 GPM, on 2,010 psi off 1,970 psi, 80 RPM, TRQ on 14-16k, off
13-15k, F/O 61%, WOB 8-12k. ECD 10.38. MW in/out 9.5 ppg Max Gas 1,050u BGG 310u. P/U 174K, SLK 83K, ROT 120K. Jet flowline as needed. Back ream
60'. Cont 4 deg/ 100' Build/turn. Distance to WP04: 5.07', 4.76' High 1.76' Left.
6/14/2023 Drill 12-1/4" Surface Hole F/6,200' - T/6,527' MD 4,378' TVD (Total: 327', AROP. : 54'). MW=9.5ppg (10.41ppg ECD) with FV135. 500-525gpm=2112/2030psi
on/off with 61% RF. TQ=15-17K/14-16K ft-lbs on/off at 80RPM with 8-16K WOB. Max Gas=1,645u, BGG=250-500u. P/U=174K, S/O=83K, ROTW=117K,. Sliding
predominantly to maintain the 4deg/100' build. No losses observed downhole. Completed a 190 bbl dilution at 6,209' to aid in reducing mud temps. Drill 12-1/4"
Surface Hole F/6,527' - T/6,915' MD 4,477' TVD (Total: 388', AROP. : 65'). MW=9.5ppg (10.56ppg ECD) with FV115. 525gpm=2365/2190psi on/off with 65% RF.
TQ=12-16K/10-12K ft-lbs on/off at 80RPM with 8-10K WOB. Max Gas=1,380u, BGG=500-700u. P/U=175K, S/O=84K, ROTW=115K,. Drilled through fault #1 at
6,449' encountering a 42' DTS throw, transitioning us from the OBa to the OA Sands. No losses downhole observed. Slide/ Rot 12.25" Surface F/ 6,915' to TD
7,244' MD (4,525' TVD) Total 329' (AROP. 65.8') 525 GPM, on 2,365 psi off 2,190 psi, 80 RPM, TRQ on 14-16k, off 12-14k, F/O 64%, WOB 8-12k. ECD 10.58.
MW in/out 9.6/9.7 ppg Max Gas 1,955u BGG 630u. P/U 172K, SLK 82K, ROT 117K. End 4 deg/100 at 7,084' MD. Build 3 deg/00 F/ 7,100' to 7,244' MD called by
Geo and 9.625" Csg tally. Obtain final survey at 7,192.15' MD 4,523.21' TVD 85.82 deg Inc 180.97 deg Azi. Monitor well 10 min, Some surface hydrates breaking
out, fell ~2 in stack after 10 min. PJSM Perform clean up cycle. BROOH F/ 7,244' to 7,143' MD Circ 0.5 BU per stand. 525 GPM, 2,100 psi, 80 RPM, TRQ 15-16k,
F/O 54%, ECD 10.4. MW in/out 9.6/9.7 ppg Max Gas 2,755u BGG 1,400u. P/U 172K, SLK 82K, ROT 115K. PJSM Perform clean up cycle. BROOH F/ 7,173 to
6,593' MD Circ 0.5 BU per stand. 525 GPM, 2,060 psi, 80 RPM, TRQ 16-19k, F/O 53%, ECD 10.22. MW in/out 9.6/9.7 ppg Max Gas 2,178u BGG 725u. P/U
180K, SLK 84K, ROT 117K. Circ & Cond. ROT/REC F/ 7,016' to 6,953' MD 525 GPM, 2,060 psi, 80 RPM, TRQ 16-19k, F/O 53%, ECD 10.22. MW in/out 9.6/9.7
ppg Max Gas 993u BGG 725u. P/U 180K, SLK 84K, ROT 117K. Pumped 40 bbl Nut Plug 300 Vid sweep. Back on time W/ 10% increase. Total 3.5 BU. Monitor
well 10 min. Hydrates breaking out at surface, fluid down to Annular after 10 min, no flow. TIH on elevators F/ 6,953' to 7,244' MD. Washed down last stand, no fill.
525 gpm 2,060 psi P/U 183k SLK 81k. PJSM BROOH F/ 7,244' to 6,615' MD. 525 GPM, 1,960 psi, 80 RPM, TRQ 16-19k, F/O 56%, ECD 10.2. MW in/out 9.5/9.6
ppg Max Gas 2,330u BGG 1700u. P/U 180K, SLK 84K, ROT 117K. Projected to TD distance to WP04: 5.57', 1.68' Low 5.37' Right.
6/15/2023 Backream F/6,615' - T/3,394' MD. Lost 24 bbls. Pulling speed reduced to 25fpm through the build and 30-40fpm through the tangent. MW=9.55ppg (10.58ppg
ECD) with FV70. Max Gas 2328u. Backream F/3,394' - T/1,484' MD. No losses observed. MW=9.55ppg (10.22ppg ECD) with FV74 at 475-525gpm. TQ=6-19K ft-
lbs at 30-80RPM. Max Gas=1,619. P/U=88K, S/O=65K, ROTW=78K. Reduced pulling speed down to 15fpm F/3,107' - T/3,011' MD, 525gpm, 80RPM. Maintained
backreaming at 25fpm F/3,011' - T/2,165' MD, 525gpm, 80RPM. Reduced Backreaming to 2-20fpm F/2,165' - T/1,484' at 475gpm, 30-50RPM as hole dictates.
Tight spot at 2,024'. BROOH F/ 1,484' to 920' MD 475 gpm 1,065 psi 40 rpm Trq 5-6k F/O 54% Max Gas 839u BGG 210u. ECD 10.15 MW in/ou 9.5/9.65 Pull
speed 20-30 fpm. F/ 920 to 723 MD encountered high Trq and over pull. BROOH 375 gpm 680 psi ECD 10.5-11.01, 20-30 rpm increased working trq stall up to
14.5k. Pull speed 1-5 ft min. Using trq stall and working up to 20k over pull. Was able to slack down immediately and regain string Wt and free Trq (2-3K). No
packing off, heavy hole unloading at shakers. (clay/sand/gravel) P/U 80k SLK 63k ROT 71k No losses. Cont BROOH BHA F/ 723 to 87 MD. BROOH 350 gpm 520
psi ECD 10.5, 10 rpm trq stall set to 14.5k. Pull speed 1-12 ft min. At 540 MD Trq started coming down to 5-11K W/ 10 rpm. Heavy returns at shakers. At 407 MD
was able to pull remaining BHA on elevators W/O issue. L/D NM FC. Read MWD tools. PJSM Cont read MWD tools. Stage 51 Solid Body Centralizers on rig floor.
L/D TM, EWR, DM and GWD collars. Drain Motor and break bit. No indication of balled up BHA. L/D Motor. Bit Grade PDC 1-3-CT-S-X-I-WT-TD Cone 2-2-WT-A-E-
I-NO-TD. Clean and clear rig floor. PJSM P/U 5" D.P. M/U wear ring running tool. Drain stack. Engage puller, BOLDS (2) Pull wear ring. L/D wear ring and running
tool. PJSM Remove 5" Hydraulic elevators and install 9.625" 250T side door elevators. P/U M/U 320T Volant to TD. Chain off swivel. P/U M/U Power Tongs. Check
handling Equip W/ mandrel. Verify 195 jnts in shed. SIMOPS Pump through flow line, remove inspection cover and clear gravel F/ flowline. Clean both. MP suction
manifolds of gravel. Monitor well on TT, static. PJSM P/U M/U Shoe Jnt and FC (BakerLoc). Pump through and check floats, good. HES drop by pass. Cont MU
BFA (BakeLoc) (Shoe track BTC) 124' MD. Cont RIH W/ 9.625" 40# L-80 TXPBTC F/ 163' to 331' MD. Trq TXP 20,960k. Install Solid Body Centralizers as per
tally. P/U 44k SLK 45k.
6/16/2023 PJSM - Run 9-5/8" TXP 40# L-80 Casing at 20-30fpm, F/331' - T/2,242' CSG MD Torquing T/20,960ft-lbs. Filling pipe every 5 joints and breaking circulation every
10 joints. Installing Centralizers as per tally. P/U=107K, S/O=72K. Losses 46 bbls. RIH T/1,049' CSG MD and encountered a tight spot, worked pipe. 2-3.5bpm=80-
100psi. 8-10K ft-lbs TQ stall at 5-10 RPM. No overpulls, setting down 20K. Worked through the tight spot F/1,049 - T/1,151'. No issues after, ran mostly on
Elevators T/2,242'. RIH F/2,242' - T/2,426' CSG MD. Rotate and Reciprocate: staged up to 7bpm with out losses downhole, pumped 1x string volume. observed
fine sands at shakers upon BU. 8.5K ft-lbs TQ at 5rpm. 300gpm=190psi, RF=41%. P/U=119K, S/O=80K. Run 9-5/8" TXP 40# L-80 Casing at 30-40fpm on
elevators, F/2,426' - T/4,620' CSG MD Torquing T/20,960ft-lbs. P/U=208K, S/O= 90K. Losses 36bbls. Filling every 5 joints and breaking circulation every 10 joints.
RIH 9.625" 40# L-80 TXPBTC F/ 4,620' to 5,909' MD. AT 4,957' MD install ES Cementer (BakerLoc) and HES inspected shear pins. Installed 9.625" Solid Body
Centralizers as per tally. Fill every 5 jnt, top off 10 jnts. Trq 47# TXPBTC 23,820 ft/lb. P/U 305K SLK 118K. Calc 24, Act 6.5 lost 17.5 bbls. Run speed 40 fpm. Max
Gas 969u. Wash Down F/ 5,909' to 5,992' MD (2 jnts) Circ DS volume. Staging pumps up to 7 bpm 290 psi RF 43% Max Gas 1,533u. Attempted rotation W/ 15.5k
stall, unable. P/U 305k SLK 115k. No losses. RIH 9.625" 40# L-80 TXPBTC F/ 5,992' to 6,884' MD. Fill every 5 jnt, top off 10 jnts. Trq 47# TXPBTC 23,820 ft/lb.
P/U N/A 380+K SLK 109K. Calc 14, Act 6.9 lost 7.1 bbls. Run speed 40 fpm. Max Gas 519u. RIH 9.625" 40# L-80 TXPBTC F/ 6,884' to 7,236' MD. P/U Jnt 177
(Last) & washed down ~20' staging pumps up to 3 bpm 380 psi was able P/U break over at 350k and P/U 305k SLK 110k. Cont washing down staging up to 4 bpm
320 psi set Trq limit to 18.5k attempted to ROT/REC string several times getting. hung up at 15.2' elevator height, pulled up to 30K over with no success. Decision
was made not to tag bottom. Fill every 5 jnt, top off 10 jnts. Trq 47# TXPBTC 23,820 ft/lb. Calc 13, Act 5 lost 8 bbls. Run speed 40 fpm. Max Gas 457u. 18 jnts left
and 1 SB Centralizer. ROT/ REC Condition mud to <20YP. F/ 7,236' to 7,226' MD. Staged up to 7 bpm 260 psi F/O 35% Max Gas 635u Trq stall set at 18.5k 4
RPM on up stroke, 1 rpm down stroke. No losses. SIMOPS: R/D Power Tongs, remove 9.625" elevators and bale ext. Prep pits for cement job. P/U 264k SLK 130K.
YP 20. PJSM Set slips and break out Volant. Clean and inspect cup. M/U Volant. R/U HP lines and 1502. s to Volant swivel. Blow down TD. Circ through cement
lines W/ MP 1 staging up to 7 bpm 520 psi. PJSM HES Fill lines W/ 5 bbls H2O. PT lines 833 psi low & 4,069 psi high kick outs, good. Pump 60 bbls 10 ppg
Tuned Spacer W/ 4# Red Dye & 5# Pol-E-Flake in 1st 10 bbls 3.6 bpm 256 psi. ROT/ REC F/ 7,236' to 7,226' MD.
6/17/2023 Pump 1st Stage Cement Job: Finish Pumping 60 bbls of 10.0ppg Tuned Spacer (#4 Red Dye and Pol-E-Flake) at 3.6bpm=273 psi, Release from Volant and Drop
Bypass Bottom Plug, 288 bbls of 12.0ppg Lead Cement (EconoCem Type I/II, 2,347 Yield, 688sxs, Cement wet @ 06:01) at 4.1bpm=321psi. 82 bbls of 15.8ppg
Tail Cement (HalCem Type I/II, 1.155 yield, 400 sxs) at 3.6bpm=571psi. Release from Volant and Drop Shutoff Plug. HES Pump 20 bbls H2O (clear Lines) at
6.2bpm=450psi. Rig Displaced with 337 bbls (5,435 strokes) of 9.7ppg Spud Mud at 7bpm, ICP=301psi, FCP=642psi. HES Pumped 80 bbls of 9.4ppg Tuned
Spacer (17.39 Yield) at 4bpm=648psi. Rig Displaced with 98.3 bbls of Spud Mud and bumped plug at 435.4 bbls Rig Total (1.3 bbls over calculated) at 5bpm
decreasing to 3bpm last 10 bbls. ICP=854psi, FCP=998psi. Hold 1,535psi (5 min), Bleed off psi and check Floats - Good. Rig Pumped up to 3,855psi not able to
shift ES Cementer. Rigged up to Test pump and pressured to 4,200psi and ES cementer opened up. CIP @ 09:31. Parked in Tension up at 168K. Lost 66.2 bbls
during displacement. Circulated through ES cementer staging pumps up to 5bpm=841psi, RF=27%. Dumped 60 bbls of Spacer, estimated 80 bbls of Cement and
193 bbls of contaminated Mud. Increased Flow rate to 10bpm (periodically) 794psi, to remove any channeling and contaminated mud from the annulus. Circulated a
total of 7x BU before shutting down to drain stack. Stage pumps up to 7bpm=625 psi and ramping pumps up to 10bpm= to further clean out clabbered up mud.
Continue pumping Black water as necessary. Disconnect knife valve and Drain/flushed stack 3x with black water. Max Gas = 48units. Continue to clean Cellar/Rig
Floor/Pits for 2nd stage cement job. Pumped 35 bbl Hi-Vis sweep with Walnut. Sweep was observed on time with a 50% increase in cuttings. No losses. PJSM for
Cementing 2nd Stage: Attempted to break out of the Volant, Saver sub breaking out instead of Volant. Troubleshoot with PWB Casing Hands. Check air pressure
increased F/ 30 psi to 75 psi and was able to release from Volant. Made up and broke out 2X times to ensure able to release from csg. Pump 2nd Stage Cement Job
as Follows: HES pumped 5 bbls H2O, 60 bbls of 10.0ppg (1.25 yield) tuned Spacer (4# Red dye and 5# Pol-E-Flake) at 4bpm=321psi. 443 bbls of 10.7 ppg Lead
ArcticCem Type I/II (2.855 yield, 870 sxs) at 5bpm (ICP=365psi. FCP=351psi) 56 bbls of 15.8 ppg. Tail HalCem Type I/II at 3.4bpm (ICP=430psi, FCP=400psi).
Release from Volant and drop Closing Plug. HES pump 20 bbls of H2O (clear lines) at 8bpm=745psi. Rig Displaced with 146.2 bbls of 9.7ppg spud mud bumping
closing plug as Calc. (Calc 166.2 bbls Act 166.2 bbls)6 bpm (ICP=287psi, FCP=717psi). last 10 bbls slowed to 4 bpm (ICP 588 psi FCP 598 psi). ES Cementer
shifted closed at 1,846psi Cont to Press up & hold 2,119 psi. Bled off check closure, good. CIP at 22:53. Dumped 60 bbls of spacer, 33 bbls of contaminated mud,
and an estimated 343 bbls of Cement. No losses. PJSM Blow down surface lines. R/D HES lines and HP lines to Volant. L/D Volant. Drain and fill stack W/ Black
H2O. Disconnect Knife Valve. PJSM Finish flushing stack W/ Black H2O & cycle Annular. R/D 16" Diverter sections W/ crane on location 01:00 and released at
02:30. Remove diverter stands and rig matts. Vac out 9.625 Csg. Lift Stack and center casing as Vault Rep. Set 9.625" emergency slips W/ 45k. Assist Vault Rep
cut 9.625" Csg. Cut Jnt 28.75'.Set stack on speed head. P/U 5" D.P. and M/U Johnny Whacker. Flush Stack 15 bpm 30 rpm. L/D Johnny Whacker and 5" D.P.
Blow down lines.4 bolt Stack to Tee. Pull master bushing and riser. Install air boot protector. SIMOPS Clean Pits. PJSM Drain stack Break bolts on diverter and
wellhead. R/D Knife Valve. Remove bell nipple and rack back stack. Remove diverter tee F/ wellhead. Remove slip lock head F/ conductor. SIMOPS Cont working in
pits. PJSM Install studs on annular. R/U and P/.U RCD Head.
6/18/2023 Pickup RCD Head and set on Annular and torque nuts. Move Stack to Pedestal. Wellhead rep dressed 9-5/8" Stump and set wellhead. PT void to 500/3750psi
5/10mins - Good. SIMOPS Clean pits for new mud, P/U Split bushings and RCD riser. P/U 5" DP joint to install Test plug. Test plug not seating in wellhead,
observed the wellhead to not be level. Removed the wellhead and found the stump cut to not be plumb - recut wellhead. Wellhead reps re-dressed stump and
reinstalled wellhead. PT Void to 500/3750psi for 5/10mins - good. N/U BOPE. Torque DSA to Stack. Install drip pan and secure stack with chains. Attach Kill and
Choke Lines. Install Koomey lines and pressure up. R/U MPD 4" hard Lines. Load test joints in Shed. Bring Side Entry sub to floor and necessary XO's. Install trip
nipple. Air 20" boots. Install drip pan and drain lines. SIMOPS: Clean and Inspect MP#2 Liners and Swabs. Install API 140 on Shakers. PJSM P/U 2 ea 5" FOSV &
4" Dart. M/U 5" FOSV to 4" Dart and side entry sub. Stage 4.5", 5" & 7" test jnts in pipe shed. Prep for flooding lines. Flood lines. Tighten grey lock for MPD, small
leak. Pressure up and function valves to fluid pack. Found Super Choke stuck at 85% open while flushing and unable to function choke. Isolated choke leg. Perform
Shell test to 3,000 psi, good. Called mechanic to trouble shot Super Choke. PJSM Perform BOPE test W/ 4.5" & 5" to 250 PSI low and 3,000 PSI high for 5 Min.
Tested Choke Manifold 9, 12-13, 5" Dart, 4" Dart, 2 ea 5" TIW, Upper and lower IBOP, Mez Kill, HCR Kill & Choke, manual Kill & Choke, Use 4.5" & 5" for UPRs
(2.875" X 5.5" VBRs), Use 4.5" Annular. Test H2S 10-20 ppm,. LEL 20-40%, Koomey draw drown initial System 3,100 PSI, Manifold 1,525 PSI, Annular 1,225 PSI,
after System 1,500 PSI, Man 1,500 PSI, Annular 1,200 PSI. 200 PSI increase 29 Sec, full charge 104 sec. Nitrogen 6 bottle average 2,333 PSI. Closing times Ann
12 sec, UPR & Blinds 9/9 sec, LPR 9 sec,. HCR Choke & Kill 1/1 sec. Used H2O for test. Witnessed waived by AOGCC Rep Austin McLeod. SIMOPS Rebuild
Super Choke due to seized disks. Cont testing BOPE. Test LPR (7" Sold) 4" TIW, Choke Manifold valves 1-8, 10 & 11, Manual and HCR Choke, Blind Rams,
Super & Manual Choke 2,000 psi, Checked PVT sensors and return flow. PVT high/ low level alarms. PJSM R/D test Equip. Break down pump in sub and head pin.
Pull test plug. Blow down lines. PJSM M/U running tool and wear ring (38" Ln 10.75" OD 9" ID) RIH RILDS. L/D 5" Jnt and running tool. PJSM P/U M/U 8.5" Smith
XR-CPS Tri Cone RR (3X18 1X16 TFA 0.9419) & 6.75" TerraForce 6:7 - 6 stg 1.5 deg Motor.
6/19/2023 P/U M/U remaining BHA with 5" HWDP out of the derrick T/591' MD. P/U=47K, S/O=46K. Single in the hole with 5" NC50 19.5# S-135 DP F/591' - T/1,291'.
P/U=64K S/O=55K. RIH on Elevators F/1,291' - T/2,179' P/U=82K, S/O=61K. Wash down F/2,179' - T/2,277' DP MD, tagging up on ES Cementer. Drill Closing
Plug and ES Cementer. ream through 2x with pumps on and 1x with no pumps - Good. 400gpm=675psi, RF=43%, 30RPM=4.5-6K ft-lbs TQ with 2-6K WOB.
P/U=97K, S/O=67K, ROTW=77K. RIH on Elevators with 5" DP out of the derrick F/2,279' - T/7,012'. P/U=121K, S/O=66K. Washed down F/7,012' - T/7,074'.
observing no stringers. Circulated 1.5x BU and overboarded 50 bbls of contaminated mud. Had clean returns to the shakers and shutdown for CSG test.
400gpm=1150psi with RF=40%. 30RPM=16-19K ft-lbs TQ, P/U=202K, S/O=66K, ROTW=110K. PJSM - R/U for CSG Test. M/U Top drive, Flood Kill/Choke lines
to purge air. Shut UPR's increasing pressure and bleed off to purge air. Test 9-5/8" 47/40# casing T/2,695psi (MP#1) for 30 mins (Charted). lost 49 psi first 15m
and 5psi last 15m. Pumped 5.0 bbls, bled back 5.0 bbls. R/D test Equip. Wash down F/7,074' - T/7,111' tagging baffle adapter on depth. Drill shoe track F/7,111' -
T/7,150', tagging Float collar on depth. Reduced Pump rate to 166gpm dealing with contaminated mud. overboarded 77bbls. 435gpm=1050psi, RF=41%,
30RPM=18-20K ft-lbs TQ with 6-8K WOB. P/U=203K, S/O=75K ROTW=110K. Drill shoe track F/ 7,150' to 7,236' MD Tagged FC (7,150' MD) & Shoe (7,235' MD)
on depth. Worked through 3X EA with and without rotation, no issue. Overboard 80 bbls clabber at 7,463' MD & 280 bbls at 7,236' MD. 435 gpm 990 psi 30 rpm
Trq 18-19k WOB 6-8k ROP 50-75, P/U 195k SLK 78k ROT 112k. Displace on the fly, drilling F/ 7,236' to 7,264' MD including 20' of new hole. Pump 40 bbl 300 vis
sweep chased by 9.2 ppg BaraDril N. Displaced 436 bbls to cutting box. 400 gpm 770 psi 30-40 rpm Trq 16k WOB 6-8k ROP 30-50, Max Gas 112u. P/U 183k
SLK 86k ROT 118k. Perform SPR's. Monitor well 10 min, static. PJSM Rack back 1 stand to 7,196' MD M/U to string and R/U for FIT. PJSM Break Circ and pump
through Choke, Kill and manifold. Close UPR's. Perform FIT to 12.1 EMW 697 psi for 10 min, final 596 psi. Pumped 1.4 bbls bled 1.3 bbls. Bleed off pressure and
open UPR's. Blow down choke, kill and manifold. R/D test Equip. PJSM Monitor well 10 min, static. POOH on elevators F/ 7,196' to 6,751' MD. No swabbing. Pump
25 bbl 10.3 ppg dry job. Cont POOH on elevators F/ 6,751' to 591' MD. P/U 187 SLK 92k. Lost 6 bbls. PJSM L/D 10 jnts 5" HWDP and rack back 4 stands of 5"
HWDP including jars. P/U drain motor. Break and L/D 8.5" Bit and Motor. Bit Grade 1-1-WT-A-E-IN-NO-BHA Clean and clear rig floor.
6/20/2023 PJSM - P/U 8.5" TK66 PDC/NRP and torque to GEO-Pilot with 14Kft-lbs. M/U Directional Assembly (ADR, PWD, DM, ALD, CTN and TM Collars), download MWD
and insert Sources (clearing rig floor). Shallow Pulse Test MWD - Good. RIH with HWDP, NM Flex and Jars T/430'. P/U 5" 19.5# NC50 S-135 Drill Pipe from the
shed F/430' - T/1,701' MD. P/U=60K, S/O=58K. POOH on elevators racking back stands in the derrick F/1,701' - T/430'. Run in the hole P/U 5" Drill Pipe from the
shed F/430' - T/2,655' MD. At 2,655', completed a break in procedure on the GEO-Pilot. Increasing RPM's in increments of 10 RPM up to 60RPM while increasing
flow rate F/125gpm - T/400gpm. Continue running in the hole on elevators with 5" drill pipe out of the shed F/2,655' - T/6700', filled pipe at 2,500' and 5,010'.
P/U=169K, S/O=83K. Continue running in the hole on elevators with 5" drill pipe out of the shed from 6700' to 7,167', P/U=172K, S/O=84K. Pull trip nipple and
install MPD bearing. Flood lines and PT 250/1200 - good. Cut and slip drilling line. Service rig: grease crown, blocks, TD, RLA, spinners, link tilt. Check oil on TD
adn rotary table. Wash down from 7167' to 7264'. Drill 8.5" hole from 7264' to 7320' (total 56', AROP. 37 fph) at 400 gpm, 1070 psi, 80 rpms, 16Kft-lbs, WOB 4-6K,
ECD 10.07 ppg EMW with 9.2 ppg mud. P/U 172K, S/O 84K, ROT 113K. Max gas 26u. Drill 8.5" hole from 7320' to 7930' (total 610', AROP. 102 fph) at 450 gpm,
1410 psi, 120 rpms, 16-18Kft-lbs, WOB 8-11K, ECD 10.42 ppg EMW with 9.3 ppg mud. Max gas 2872u. P/U 169K, S/O 75K, ROT 110K. Back ream full stands,
MPD chokes open. 5 concretions have been drilled so far for a total of 7 (1.1% of the lateral). No faults have been crossed so far. Total footage in OBd-1 = 6', OBd-2
= 36', OBd-3 = 334', OBd-4 255'. Distance to WP4 13.75', 7.41 High, 11.59' Right.
6/21/2023 Drilled the 8.5" Lateral F/7,930' - T/8,630' MD 4,526' TVD (Total:700', AROP. :117'). 500GPM=1730/1690psi on/off, Beyond RF=465GPM MW=9.3ppg w/10.53ppg
ECD, 120RPM=17K/15.5K ft-lbs on/off, 10-14k WOB. Max gas=2653u. P/U=174K, S/O=69K, ROTW=108K. Drilled across the fault at 8,226' with a 41' DTS,
Moving us from the OBd Sands to the OBc Clays. Target 87deg inclination to get back down to OBd Sands. Survey taken at 8,558' showed the close approach to L-
121 had a 0.13SF, which put us 19.11' away at the closest point. Drilled the 8.5" Lateral F/8,630' - T/9,225MD 4,502' TVD(Total: 595', AROP. :100').
500GPM=1282/1250psi on/off, Beyond RF=465GPM MW=9.35ppg w/10.7ppg ECD, 120RPM=12K/11-12K ft-lbs on/off, 10-14k WOB. Max gas=2021u.
P/U=184K, S/O=80K, ROTW=111K. Drilled T/8,819' and began the 3deg/100' build for the 110 degree inclination trajectory for the appraisal plugback. Drilled the
8.5" appraisal Lateral F/9,225' - T/9,316' (Total: 91', AROP. :15fph). Adjust parameters to attempt and mitigate Geo-Pilot housing at 300-500 gpm, 850-1970 psi, 80-
110 rpms, 10-11Kft-lbs, WOB 10-15K, ECD 10.7 ppg, MW 9.3 ppg, max gas 573u. P/U 172K, S/O 83K, ROTW 110K. MPD chokes open. Pump bit balling sweep
with 20 ppb Nut plug at 9,255' with little to minimal increase in ROP. Drill 8.5" appraisal Lat F/9,316' - T/9,690' (Total: 374', AROP. : 62fph). 450gpm, 1730psi, 100
rpms, 9-10Kft-lbs, WOB 14-18K, ECD 10.62 ppg, MW 9.25 ppg, max gas 2051u. P/U 164K, S/O 84K, ROTW 104K. MPD chokes open. Backream full stands.
Adjust parameters as needed to attempt to mitigate housing roll. 17 concretions have been drilled so far for a total of 59 (3.0% of the lateral). 1 fault has been
crossed so far: 8226. Distance to WP4: 63.08', 58.53' high, 23.52' left.
6/22/2023 Drill 8.5" appraisal lat F/9,690' - T/9,933' (Total: 243', AROP. : 40fph). 525gpm, 1490psi, 100 rpms, 9.5Kft-lbs, WOB 16-18K, ECD 10.71 ppg, MW 9.3 ppg, max
gas 1810u. P/U 132K, S/O 77K, ROTW 101K. MPD chokes open. Backream full stands. Adjust parameters as needed to attempt to mitigate housing roll. Drill 8.5"
appraisal lat F/9,933' - T/10,346' (Total: 413', AROP. : 69fph). 500-550gpm, 2240psi, 100-120 rpms, 9.5Kft-lbs, WOB 6-14K, ECD 11.25 ppg, MW 9.3 ppg, max
gas 1504u. P/U 130K, S/O 78K, ROTW 95K. MPD chokes open. Backream full stands. Cont. to adjust parameters to attempt and mitigate Geo-Pilot housing roll.
Drill 8.5" appraisal lat F/10,346' - T/10,364' (Total: 18', AROP. : 36 fph). 350 gpm, 1289 psi, 100 rpms, 9.5Kft-lbs, WOB 6-14K, ECD 10.68 ppg, MW 9.35 ppg, max
gas 362u. P/U 130K, S/O 78K, ROTW 95K. MPD chokes open. Backream full stands. Conduct hard reset on Geo-Pilot with toolface not responding correctly - turn
GP rpms' on. Drill 8.5" appraisal lat F/10,364' - T/10,451' (Total: 87', AROP. : 15 fph). 350-400 gpm, 1282 psi, 100 rpms, 9-11Kft-lbs, WOB 6-14K, ECD 11.1 ppg,
MW 9.35 ppg, max gas 641u. P/U 130K, S/O 78K, ROTW 95K. MPD chokes open. Backream full stands. At 10,400' discuss the lack of ability to drop angle with
Eng, Geo, Halliburton. Decision to drill 30' to see if we can get minimum 3.5/100 drop to achieve goal of getting density/porosity tools across NB without penetrating
Ugnu. With no housing roll able to obtain ~4/100 DLS over ~50'. Pumped 50 bbls 20 ppb Nutplug and 1 ppg Desco sweep at 10,447'. in an attempt to mitigate Geo-
Pilot housing roll. Drill 8.5" appraisal lat F/10,451' - T/10,500' (Total: 49', AROP. : 49 fph). 500 gpm, 2140 psi, 120 rpms, 9.5Kft-lbs, WOB 8-13K, ECD 11.25 ppg,
MW 9.3 ppg, max gas 778u. P/U 130K, S/O 77K, ROTW 95K. MPD chokes open. Backream full stands. At 10,487' unable to mitigate housing roll. Pump 50 bbls
40 ppb Nut Plug 1 ppb Desco sweep. Increase rotary to 120 rpms with no success. Drill ahead to 10,500 unsuccessfully trying to mitigate housing roll. CBU x2,
racking back two stands to 10,410' at 500 gpm, 2050 psi, 100 rpms, 8.5Kft-lbs, ECD 10.96 ppg, max gas 808u, P/U 127K, S/O 72K, ROTW 127K. Obtain SPR's.
Monitor well with MPD chokes - slight pressure loss. BROOH from 10,410' to 8785' at 500 gpm, 2020 psi, 120 rpms, 7-10Kft0lbs, max gas 313u. ECD 10.97 ppg
EMW. P/U 134K, S/O 72K, ROTW 105K. 19 concretions have been drilled so far for a total of 66 (2.0% of the lateral). 1 fault has been crossed so far: 8226'.
Distance to WP4: 340.04', 337.03' high, 45.12' left.
6/23/2023 BROOH from 8,785' to 7,231' at 500 gpm, 2020 psi, 120 rpms, 6-8Kft0lbs, max gas 530u. ECD 10.57 ppg EMW. P/U 134K, S/O 97K, ROTW 108K. Puliing speed
20-35 fpm. No losses. Slow Rotary to 60 RPM @ 7,351'. See 9K Drag pulling Bit into Csg shoe. Pump tandem Seeps and circulate casing clean while
Rotate/Reciprocate pipe from 7,231' to 7,182' MD. 500 GPM, 1900 PSI, 80 RPM, 5.5K Trq. PUW 137K, SOW 97K, ROTW 110K, No Losses. Monitor well for 10
min via Beyond Chokes. Pull MPD Bearing and install Trip Nipple. TOOH on elevators from 7,231' to 6,872'. PUW 137K, SOW 97K. Calculated Hole Fill. Service
Rig. Grease Crown and Blocks. Simops: Pump 25 bbls 11.1 ppg Dry Job. C/O Elevators and instal 5" Hyd Elevators. Grease and inspect Top Drive, Spinners, Iron
Roughneck, Upper/Lower IBOP, inspect hyd elevators. Continue to TOH on elevators from 6872' to 430'. PUW 137, SOW 97K. laying down 28 joints of drill pipe.
Monitor well, static. Rack back 3 stands HWDP/Jars, Collars. L/D stabilizer. Pull sources, upload MWD. Cont. to L/D BHA. Geo-Pilot housing appears locked up,
cutters in tact with flat edges. Bit grade 2-1-BT-N-X-IN-DL-DTF. Clean and clear rig floor. R/U sensator and M/U tongs. M/U BHA: Bit, NRP, Geo-Pilot, MWD. Plug
in and download. Shallow pulse test and install sources. Cont. RIH with drill collars, HWDP and Jars out of derrick to 430'. RIH from 430' to 6794' picking up 28
joints of drill pipe. Fill pipe every ~2500', break in Geo-Pilot first fill. P/U 144K, S/O 90K. 19 concretions have been drilled so far for a total of 66 (2.0% of the lateral).
1 fault has been crossed so far: 8226'.Distance to WP4: 340.04', 337.03' high, 45.12' left.
6/24/2023 Monitor well, Pull and L/D Trip Nipple and install MPD Bearing. Service Rig, Grease and inspect crown sheaves, service iron roughneck, grease and inspect Top
Drive, check Top Drive gear oil, good. Fill pipe @ 2 bpm while servicing rig. TIH on elevators with 5" DP out of Derrick from 6,794' to 10,410' with no issues. PUW
150K, SOW 96K. Calc Disp 82 bbls, Act 81.4 bbls, Loss .6 bbls. Wash to bottom to 10,500' with no fill. Drill 8.5" appraisal lat F/10,500' - T/10,621' (4,108 TVD)
(Total: 121', AROP. : 60.5 fph). 450 gpm, 1870 psi, 120 rpms, 12.5Kft-lbs, WOB 10-12K, ECD 11.1 ppg, MW 9.35 ppg, max gas 842u. P/U 146K, S/O 69K, ROTW
94K. MPD chokes open. Backream full stands. BROOH from 10,621' to Side OHST depth of 8845'. At 450 gpm, 1680 psi, 120 rpms, 7-10Kft-lbs, ECD 10.68 ppg
with 9.4 ppg mud. Max gas 492u. P/U 131K, S/O 82K, ROTW 91K. Pulling 20-35 fpm as hole dictates. Sidetrack wellbore from 8845' to 8944'. Control drill at 30fph
gradually increasing to 100 fph with 4/100' drop rate at 450 gpm, 1621 psi, 120 rpms, 7-9Kft-lbs, WOB 1-3K, P/U 138K, S/O 74K, ROTW 98K. Pumped out of hole
to 8819', RIH to 8894' with no pumps/rotary and obtain survey to ensure in new. hole. Perform 580 bbls whole mud dilution at 8944' due to rising MBT's. Drill 8.5"
lateral F/8944' - T/9263' (Total: 319', AROP. : 106fph). 500 gpm, 1768 psi, 120 rpms, 9-11Kft-lbs, WOB 6-12K, ECD 10.4 ppg, MW 9.25 ppg, max gas 2134u. P/U
141K, S/O 85K, ROTW 110K. MPD chokes open. Backream 1/2 stands. Drill 8.5" lateral F/9263' - T/10,091' (Total: 828', AROP. : 138fph). 525 gpm, 2150 psi, 120
rpms, 9Kft-lbs, WOB 5-9K, ECD 10.77 ppg, MW 9.25 ppg, max gas 1950u. P/U 137K, S/O 85K, ROTW 108K. MPD chokes open. Backream 1/2 stands. 21
concretions have been drilled so far for a total of 69 (2.5% of the lateral). 1 fault has been crossed so far: 8226'. 1 plug back (8845'-10621'). Distance to WP4:
25.23', 9.32' low, 23.44' left.
6/25/2023 Drill 8.5" lateral F/10,091' - T/10,855' (Total: 764', AROP. : 127fph). 550 gpm, 2380 psi, 120 rpms, 12Kft-lbs, WOB 10-13K, ECD 11.22 ppg, MW 9.25 ppg, max
gas 2238u. P/U 139K, S/O 77K, ROTW 107K. MPD chokes open. Backream 1/2 stands. Undulating in OBd sands. Drill 8.5" lateral F/10,855' - T/11,460' (Total:
605', AROP. : 101fph). 550 gpm, 2556 psi, 120 rpms, 10-12Kft-lbs, WOB 10-13K, ECD 11.42 ppg, MW 9.25 ppg, max gas 2455u. P/U 142K, S/O 76K, ROTW
103K. MPD chokes open. Backream 1/2 stands. Undulating in OBd sands. Drilled out the top of the OBd sands at 11,328', reacquired OBd at 11,510'. Drill 8.5"
lateral F/11,460' - T/12,061' (Total: 601', AROP. : 100fph). 550 gpm, 2638 psi, 120 rpms, 11-12Kft-lbs, WOB 10-15K, ECD 11.62 ppg, MW 9.4 ppg, max gas
2053u. P/U 143K, S/O 77K, ROTW 103K. MPD chokes open. Backream 1/2 stands. Undulating in OBd sands. Drill 8.5" lateral F/12,061' - T/12,731' (Total: 670',
AROP. : 112fph). 550 gpm, 2710 psi, 120 rpms, 11-14Kft-lbs, WOB 5-12K, ECD 11.77 ppg, MW 9.4 ppg, max gas 2560u. P/U 141K, S/O 66K, ROTW 102K. MPD
chokes open. Backream 1/2 stands. Undulating in OBd sands. 39 concretions have been drilled so far for a total of 143 (2.6% of the lateral). Distance to
WP4:44.06', 43.42' low, 7.47' left.
6/26/2023 Drill 8.5" lateral F/12,731' - T/13,213' (Total: 482', AROP. : 121fph). 525 gpm, 2700 psi, 120 rpms, 12-14Kft-lbs, WOB 13-15K, ECD 11.91 ppg, MW 9.35 ppg, max
gas 2725u. P/U 142K, S/O 61K, ROTW 97K. MPD chokes open. Backream 1/2 stands. Undulating in OBd sands. Service Rig: Observe washout on mud pump 1
pod 1. Rack back stand. Prep to C/O pod. Observe washout on mud pump 1 pod 1. Rack back stand. C/O pod while circulating and reciprocating pipe at 289 gpm,
1100 psi. Service rig: Finish C/O pod #1, MP #1. Drill 8.5" lateral F/13,213' - T/13,456' (Total: 243', AROP. : 122fph). 525 gpm, 2727 psi, 120 rpms, 11-14Kft-lbs,
WOB 8-14K, ECD 11.61 ppg, MW 9.3 ppg, max gas 2190u. P/U 142K, S/O 58K, ROTW 98K. MPD chokes open. Backream 1/2 stands. Undulating in OBd sands.
Drill 8.5" lateral F/13,456' - T/14,095' (Total: 639', AROP. : 107fph). 525 gpm, 2861 psi, 120 rpms, 13-16Kft-lbs, WOB 8-14K, ECD 11.33 ppg, MW 9.3 ppg, max
gas 2746u. P/U 142K, S/O 58K, ROTW 101K. MPD chokes open. Backream 1/2 stands. Undulating in OBd sands. Drill 8.5" lateral F/14,095' - T/14,797' (Total:
702', AROP. : 117fph). 550 gpm, 2940 psi, 120 rpms, 15-18Kft-lbs, WOB 10-13K, ECD 11.79 ppg, MW 9.3 ppg, max gas 2410u. P/U 154K, S/O 40K, ROTW
100K. MPD chokes open. Backream 1/2 stands. Undulating in OBd sands. 57 concretions have been drilled so far for a total of 193 (2.6% of the lateral). Distance to
WP4: 45.86', 40.65' low, 21.23' left.
6/27/2023 Drill 8.5" lateral from 14,797' to TD at 15,425' (Total: 628', AROP. : 105fph). 525 gpm, 2790 psi, 120 rpms, 17Kft-lbs, WOB 9-12K, ECD 11.87 ppg, MW 9.25 ppg,
max gas 2140u. P/U 150K, S/O 44K, ROTW 100K. MPD chokes open. Backream full stands. Undulating in OBd sands. Obtain final survey. Rack back stand.
Pump tandem sweeps (on time, 25% increase) and circulate hole clean 4xBU. rack back stand once every BU after sweep is out of hole. 525 gpm, 2658 psi, 120
rpm, 14Kft-lbs, ECD 11.87 ppg with 9.4 ppg mud. Max gas 428u. P/U 150K, S/O 44K, ROT 100K. Wash and ream to 15370'. Pump SAPP train 3x SAPP pills with
20 bbls Quickdril between, and displace to 9.2 ppg Quickdril at 470 gpm, 2252 psi, 100 rpms, 20Kft-lbs, max gas 192u, ECD 11.61 Reciprocating pipe. Monitor
well with MPD, 2 psi built in 5 minutes. Drop 2.4" drift. BROOH from 15370' to 13889' at 450 gpm, 1540 psi, 120 rpms 20Kft-lbs, max gas 341u, ECD 11.85 ppg
with 9.3ppg mud. P/U 164K, S/O 54K, ROT105K. 15-20 bph loss rate. Cont. to BROOH from 13889' to 11725' at 450 gpm, 1420 psi, 120rpms 14-16Kft-lbs, max
gas 1165u, ECD 10.6 ppg with 9.3ppg mud. P/U 158K, S/O 69K, ROT105K.8-12 bph loss rate. Pulling 10-30 fpm as hole dictates. Slow pulling speed from 12,180'
to 11,950' to 1-5 fpm due to erratic tq and slight packoffs. 57 concretions were drilled for a total footage of 193 (2.4% of the lateral). Distance to WP4: 68.63', 67.3'
low, 13.49' left.
6/28/2023 Cont. to BROOH from 11725' to 9901' at 450 gpm, 1275 psi, 120rpms 12-15Kft-lbs, max gas 1215u, ECD 10.3 ppg with 9.35 ppg mud. P/U 156K, S/O 76K,
ROT106K. 8-10 bph loss rate. Pulling 10-30 fpm as hole dictates. Slow pulling speed from 11725' to 10285' to 2-15 fpm due to erratic tq and packoffs. Cont. to
BROOH from 9901' to 8731' at 425 gpm, 1106 psi, 120rpms 14-18Kft-lbs, max gas 375u, ECD 10.2 ppg with 9.35 ppg mud. P/U 158K, S/O 66K, ROT103K.Pulling
2-15 fpm as hole dictates. At 8821', RIH to 8937' and obtain survey to ensure in motherbore - good. Cont. to BROOH from 8731' to 7230' at 425-475 gpm, 1376 psi,
120rpms 14-16Kft-lbs, max gas 698u, ECD 10.2 ppg with 9.35 ppg mud. P/U 178K, S/O 70K, ROT103K.Pulling 2-15 fpm as hole dictates. Slow rotary to 40 rpms
as BHA comes through shoe. With drill collars at shoe observe packoff and Tq stall (limiter set at 21Kft-lbs). Work pipe and establish rotary, stage up to 80 rpms
and flow to 475 gpm. Pump high vis sweep (10% increase) and circulate 2 x BU at 500 gpm, 1370 psi, 100 rpms, 14Kft-lbs, reciprocating pipe. ECD 9.92, max gas
95u. Monitor well with MPD, 3 psi build in 5 minutes. Service rig: grease corwn sheaves, top drive. Check gear oil in TD. Service and inspect iron roughneck. Pull
MPD bearing, set trip nipple. POOH from 7,230' to 6,751' with no indication of swabbing. Pump 25 bbls dry job with corrosion inhibitor. POOH laying down drill pipe
from 6,751' to 3267'. P/U 137K, S/O 97K. Calculated displacement 33.6 bbls, actual 36 bbls. 57 concretions were drilled for a total footage of 193 (2.4% of the
lateral). Distance to WP4: 68.63', 67.3' low, 13.49' left.
6/29/2023 Continue POOH laying down 5" NC-50 drill pipe from 3267' - T/ 430' MD (BHA). Monitor well @ BHA (static). P/U 65K, S/O 62K. 6 bbl loss for total trip. POOH
laying down BHA F/ 430' - T/ surface. L/D 7x 5" HWDP w/ SLB Jars. L/D NM Flex DC's and float subs. Retrieve 2.39" OD steel drift from float sub. Remove
corrosion ring from Flex DC. PJSM, Remove and secure sources without issue. Download recorded data from MWD. Remove MWD pulser. B/O and L/D MWD /
LWD, Geo Pilot, NRP and BIt. Bit graded 2,2,CT,S,X,IN,WT,TD. 8-3/8" IBS showed significant wear on gauge. Demob BHA components from rig floor. R/D 5" DP
handling equpment. Mobilize casing equipment to rig floor. Load 4.5" liner jewelry in order and prep pipeshed for running pipe. M/U TIW XO and stage. Install 75T
"YT" 4.5" elevators. R/U 4.5" power tongs. RIH with 4-1/2", 12.6#, L-80, W563 liner with slotted joints to 5,945'. P/U 86K, S/O 63K. Cont. to RIH with 4-1/2", 12.6#,
L-80, W563 liner, Tq to 3800 ft-lbs from 5845' to 8050'. R/D 4-1/2" pipe handling equipment, R/U 7" equipment. RIH with 7", 26#, L-80, W563 liner from 8050' to
8912'. Tq to 9400 ft-lbs P/U 111K, S/O 70K. R/D 7" pipe handling equipment, R/U 5" equi. P/U Baker SLZXP liner top to 8945'. Calc displacement 47 bbls, Actual
26.4 bbls. Clean and clear floor of Parker TRS tongs, pipe handling equipment. Prep floor for drill pipe. RIH with 4-1/2" injection liner conveyed on drill pipe from
8945' to 10,028'. Pump 10 bbls through SLZXP on first stand, P/U 119K, S/O 75K. Cont. to RIH with 4-1/2" injection liner conveyed on drill pipe from 10,028' to
15,283'. P/U168K, S/O75K. Calc. disp 46 bbls, act 39 bbls. Drop 1-1/8" phenolic ball.Set liner in tension.Pump ball down at 4 bpm, 460 psi, slow to 2 bpm 220 psi
at 900 strokes. Ball on seat at 1415 strokes (1751 calc). Pressure up to 2100 psi, set 30K down to set hanger. Cont. to pressure up to 2700 psi and observe
nuetrilize. Pressure up to 3950 psi and observe ball seat shear. Pick up 5' to expose dog sub. P/U 129K, S/O 95K. Slack off and observe dog sub set liner top 4'
high. Establish rotary, 20 rpm and set. 60K down x 3 with dog sub. Pick up to neutral wt. Rig up and pressure test liner top to 1500 psi for 10 minutes - good. Rig
down testing equipment. Clean and clear rig floor. Prep to lay down drill pipe.
Activity Date Ops Summary
6/30/2023 POOH laying down drill pipe from 6356' to 696', cull out pipe for CAT IV inspecetion. Calc dipslacement 45 bbls, actual 52 bbls. Service rig, grease and inspect
blocks, TD, overhead spinners and FH-80. Monitor well on trip tank, static. Cont. POOH laying down drill pipe, L/D Liner running tool. Calculated disp. 8.4 bbls,
actual 3.9 bbls. Clean and clear rig floor, prep to RIH. RIH with excess drill pipe from derrick to 2162'. P/U 69K, S/O 65K. Cut and slip drilling line. POOH laying
down drill pipe from 2162' to surface. Drain stack. BOLDS. Pull wear bushing. R/U to RIH with tie-back string. R/U pipe handling equipment. Rig up Parker TRS
power tongs. Clean and clear rig floor. M/U Baker Bullet seal assembly. RIH with 7", 26#, L-80, BTC casing as per tally from surface to 2332'. P/U 72K, S/O 65K.
M/U 10 joints to diamond, average TQ=7K. Calculated 15.6 bbls, Actual 10.9 bbls. Cont. RIH with 7", 26#, L-80, BTC casing as per tally from 2332' to no-go at
6358', observing slight drag (1-3K) as seals engage. P/U 160K, S/O 99K. Calculated displacement 43 bbls, Actual 39 bbls. Space out 0.98' off no-go with 9.63' and
3.05' pup joint, followed by full joint. M/U hanger and land tie-back string. R/U to displace to corrosion inhibited brine.
7/1/2023 Reduce annular psi to 450 psi. R/U to reverse circulate 4.5"x7" OA back thru 4.5" tbg. Psi up 200 psi on OA and strip up observing psi dump @ ~8' to locate seals
(P/U +1'). Reverse circulate 353 bbls 9.2 CI brine @ 5bm, 360 ICP / 240 FCP. LRS pump 64 bbls diesel @ 4 bpm, 420 circ psi. 290 psi OA SICP. Strip down and
landout 7" tieback (64k on hanger). P/U 168k, S/O 99k. RILDS. Set packoff and test void 500/5000 psi w/ 5/10 min hold (test good). R/U and test OA 1500 psi w/ 30
min hold (good). Chart and record same. Initial 1575 psi, 15 min 1523 psi, Final 1500 psi. 2 bbl In/Out. R/D test equipment. Mobilize casing equpment to floor and
prep pipshed. Stage Tec wire spool on floor and R/U overhead sheaves. Secure same. Stg 150 cannon clamps on floor w/ pins. Bring job box to floor and hookup
svc lines for install equipment. M/U XO w/ FOSV. Grease and inspect crown sheaves, blocks, TDS, Drawworks and pipeskate. Verify ID, OD on handling equipment
and pwr tongs. Finish rigging up spooler and staging clamps on floor. 215 jts 4.5" JFEBear in shed. M/U cut full mule jt. Dump test Tq Turn @ 5600 ft/lbs (good).
RIH with 4.5" JFEBear, 12.6#, L-80 tubing from surface to 2129' MD. Bakerlok jt between "X" nipple and Packer above. Tq turn connection 5.6k ft/lbs. Install cannon
collar clamps first 10 jts from gauge carrier then every other one. Terminated Tek wire to carrier and tested same (good). Test every 2000' to surface. 50 fpm max
running speed. Cont. to RIH with 4.5" JFEBear, 12.6#, L-80 tubing from 2129' to 6444' MD. Tq turn connection 5.6k ft/lbs. Install cannon collar clamps every other
one joint. Test Tek wire every 2000' to surface. 50 fpm max running speed. Calc displ 25.2 bbls, actual 20.9 bbls. Cont. to RIH with 4.5" JFEBear, 12.6#, L-80
tubing from 6444' to 7232' MD, lightly tagging XO with 3K. Tq turn connection 5.6k ft/lbs. Install cannon collar clamps every other one joint. Test Tek wire every
2000' to surface. 50 fpm max running speed. Space out 2.02' off no-go. M/U space out pups, full joint, hanger. Terminate Tek wire and feed through hanger. Test
Tek wire. Land Hanger, RILDS. P/U 96K, S/O 67K. total of 88 cannon clamps ran. Drop 1-7/8" ball and rod and allow to fall. Clean and clear rig floor of Parker TRS
equipment, Centrilift equipment. Un-hang sheave in derrick. Rig up test equipment, flood lines. Close blinds and pressure up on tubing to set packer to 3600 psi,
observe 0 psi on IA until at pressure. Observe slight bobble at ~2000 psi, indicating packer set. At full pressure observe IA pressure increase to 100 psi quickly,
then continue to build as tubing pressure falls. In ~3 minutes tubing pressure fell to 3074 psi with IA pressure increasing to 309 psi. Bleed off pressure. Pressure up
on tubing to 500 psi with IA open, observe pressure fall with slight flow. Line up to IA with tubing open to choke line. Pressure up to 200 psi with slight drop in
pressure and eventually flow out tubing. M/U landing joint and head pin to eliminate surface leaks.
7/2/2023 Psi up IA 1500 psi and observe steady flow out of tubing ~1/4 bpm. Monitor flow @ hanger (static which eliminates swedgelok and hanger seals as potential leak
points). Flow indicates leak downhole. Discuss options with completions engineer. Combo MIT Tbg/IA to 3500 psi w/ 30 min hold (test good). Initial 3612 psi, 15 min
3580 psi, Final 3567 psi. Pumped 2 bbls, bled back 2 bbls. Test confirms ball and rod on seat without leak and packer set with no leaks. Mobilize slickline. Sym
Ops - Clean pits, load and process 5" DP in shed. EAM's on TDS. Charge compensator on TDS. Inspect guide rails for wear on MP#2. Slickline on location @
12:30 hrs. PJSM, Rig up slickline sheaves and dress 3.8" sliding sleeve up setting tool.to close HES "XD" SSD. RIH and engage sliding sleeve @ 6293' SLM.
Work sleeve up to ensure closed position. Release and POOH. Rig up and psi up on tubing to 500 psi w/ 90 psi on IA. Inconclusive. Continue to psi up tbg to 1000
psi w/ 360 psi IA. SITP @ 1000 psi, SICP (IA) 360 psi. Tubing psi continued dropping from 1000 psi to 737 psi over 10 min with IA psi increasing from 360 to 500
and continually rising over 10 min indicating communication between tubing and IA. Decision made to cycle sleeve via slickline and attempt retest. Dress slickline
with down shift opening tool and RIH. Engage sleeve @ 6293' SLM and shift open. POOH,Redress slickline to shift sleeve closed. RIH to 6,293' and shift sliding
sleeve closed. POOH, tool indicate sliding sleeve shifted close. Close blind rams, flood lines pressure up on tubing at 1/2 bpm. At 500 psi IA pressure 80 psi, shut in
with tubing at 1016 psi IA at 250 psi. After six minutes observe tubing pressure fall to 573 psi and IA pressure increase to 420 psi. Bleed off pressure. SimOps: R/D
slickline. Set BPV. P/U stack washing tool 'Johnny whacker' and flush BOP. Flush and blow down surface lines. Pull bushings, remove riser, install casing
bushings. R/D MPD equipment and valves, hole fill lines. Hook up bridge cranes and righ down chain binders.
7/3/2023 Cont. to N/D BOPE: disconnect choke and kill lines. N/D DSA. Rack BOPE stack back and secure. 4-bolt Beyond. Remove DSA. Clean ring groove and tubing
hanger. Install tree and torque. Remove master valve and spin 90 degrees, re-install. Perform final check on Tek Wire - good. PT tubing hanger void 500/5000 psi -
good. PT tree 250/5000 psi - good. Rig released 06:00.
50-029-23752-00-00API #:
Well Name:
Field:
County/State:
PBW L-254
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
ACTIVITYDATE SUMMARY
7/3/2023
Set 4" CTSHBPV. S/B for N/D. Install SBMS. Install CTS plug. Route 1/4" CCL
through THA. N/U tree Terminate CCL. Test void to 500/5000 psi 10 min each.
Passed. S/B for tree test. Pull CTS plug, pull 4" CTSHBPV.
7/4/2023
***WELL S/I ON ARRIVAL*** (New well post)
POLLARD #60 RIG UP
***CONTINUE ON 7/5/23 WSR***
7/4/2023
T/I/O=0/0/0. Post I-Rig. Install New 51/8" x 7 1/16" CIW upper tree,Torque flanges to
API specs. PT against MV 500 psi low & 5000 psi high (PASSED). *** Job
Complete*** Final WHP's=0/0/0.
7/5/2023
T/I/O 0/0/0 Temp S/I (TFS unit 4 assist S-Line with MIT-T) ***MIT-T FAILED***
Pumped 1 bbl of DSL down TBG to reach Max applied pressure of 2500 psi. Target
Pressure= 2250. 1st 15 Min TBG lost 1158 psi. 2nd 15 Min TBG lost 13 psi.
***********WSR Continued on 7/6/2023********
7/5/2023
***CONTINUED FROM 7/4/23 WSR*** (New well post)
SET 3.81" XX-PLUG AT 6,293' MD
T-BIRD PERFORMED PASSING MIT-T TO 2426 psi
PULLED 3.81" XX-PLUG FROM 6,293' MD
RAN 4-1/2" 42BO TO XD-SSD AT 6,293' MD (shifted open)
RAN 4-1/2" 42BO TO XD-SSD AT 6,293' MD (shifted closed)
SET 4-1/2" ISO SLEEVE AT 6,923' MD
T-BIRD ATTEMPTED MIT-T (IA tracked instantly)
PULLED 4-1/2" ISO SLEEVE FROM 6,923' MD
ATTEMPT TO SET D&D HOLE FINDER (unable to shear pin)
PULLED RHC-M PLUG AT 6,536' MD
***CONTINUE ON 7/6/23 WSR***
7/6/2023
**********WSR Continued From 7/5/2023*************** (TFS unit 4 assist S-Line with
Pressure test) Pumped 6 bbl of DSL down TBG to reach Max applied pressure of
2500 psi. Target Pressure= 2250. 1st 15 Min TBG lost 1149 psi and IA gained 777
psi. 2nd 15 Min TBG lost 11 and IA gained 6. Well left in S-Line control.
Final WHPS 0/0/0
7/6/2023
T/I/O= 90/0/0 Temp= S/I (TFS Unit 4 Conduct CMIT TxIA) CMIT TxIA
****PASSED**** to 2504/2438 psi. Max applied pressure=2500. Target Pressure=
2250. Pumped 1.3 bbls of DSL down TBG to Reach max applied pressure of 2500.
1st 15 Min TBG/IA lost 8/9 psi. 2nd 15 Min TBG/IA lost 8/5 psi. TBG/IA lost 16/14 psi
in a 30 Min test. Bled back~ 1.5 bbls.
Tags Hung, DSO notified of well status upon departure. Final WHPS=0/0/0
7/6/2023
***CONTINUED FROM 7/5/23 WSR*** (New well post)
SET 3.81" XX-PLUG AT 6,537' MD
T-BIRD ATTEMPTED PRESSURE TEST (IA tracked)
***WELL S/I ON DEPARTURE***
7/8/2023
T/I/O=0/0/0 Temp=S/I (TFS Unit 4 Assist E-Line with LDL) Pumped a total of 7 bbls
of DSL down TBG to assist E-Line with LDL. Returns were taken to surface open top
tank. E-Line in control of well upon TFS departure. Final Whps=0/0/0.
7/8/2023
***WELL S/I ON ARRIVAL***
IN HOLE w/ 42BO TO SHIFT SLEEVE AT 6292' MD
***CONTINUED ON 7/9/23 WSR***
Daily Report of Well Operations
PBU L-254
Daily Report of Well Operations
PBU L-254
7/8/2023
***WELL WAS S/I UPON ARRIVAL***
JOB SCOPE ( HOIST READ LOGGING ACOUSTIC LOGGING TOOLS)
CONTACT DSO TO INITIATE PERMIT
RIG UP YJ E LINE
CONNECT TO READ LOGGNG TOOLS STAB ON RIH
PT PCE 300 PSI LOW 3000PSI HIGH
RIH W/2X WB 1 11/16"READ ACOUSTIC LOGGING TOOLS W/ SPINNER
LOG UP SUSPECTED HOLE FOUND AT 6368'
LOG OUT OF HOLE
BLEED DOWN WELL CLOSE SWAB AND SSV, BLEED OFF LUBE RIG DOWN
RTN TO PRUDHOE BAY
7/9/2023
T/I/O 0/0/0 Temp S/I (TFS unit 4 assist S-Line with Freeze protect on IA and TBG)
Pumped 44 bbls of DSL down IA for freeze protect followed by 38 bbls of DSL down
the TBG for a freeze protect. Tags hung and Mastercard given to DSO.
Final WHPS 1210/961/0
7/9/2023
***CONTINUED FROM 7/8/23 WSR*** (New well post)
SHIFTED XD-SSD OPEN AT 6,292' MD
EQ & PULLED 3.81" XX PLUG AT 6,536' MD
TB PUMPED 44BBL IA FP
SHIFTED XD-SSD CLOSED AT 6,292' MD
TB LEFT ON LOCATION PUMPING TBG FP
***WELL S/I ON DEPARTURE***
7/10/2023
CTU 9 - 1.75" CT - .156" WT - Job Scope = Set WellTec Expandable Metal Packers
Travel to L-254, MIRU, Install MM Bypass for NCS tools. Change Packoffs/Inspect
Injector. Trim 50' of Coil.
***Continue Job Log on 7/11/23***
7/11/2023
CTU 9 - 1.75" CT - .156" WT - Job Scope = Set WellTec Expandable Metal Packers
MU HES GR/CCL logging tools w/3.680" DJN Drift. Log from 9500-8000. POOH and
tie in -17' correction. RIH with YJ CBP. Correct depth at flag. Set plug at 9,100'.
POOH. L/D YJ CBP. M/U 3.80" drift run. RIH and drift down to 9,000'. POOH, L/D
Drift BHA. Perform Weekly BOP Test
***Continue on 7/12/23***
7/12/2023
CTU 9 - 1.75" CT - .156" WT - Job Scope = Set WellTec Expandable Metal Packers,
Mill Retainer, CBP
Complete 7-Day BOP Test, RIH w/NCS Treatment Packer. Can't get down with NCS
tool. Locator sub tagging tubing joints every 40 feet. POOH to Swap to NS 1-trip
Retainer. Set Retainer @ 8675'. Work through pressure setting sequence for Well-
Tec mechanical packers. Pressure leak off at 4750 psi. Cannot build pressure after
that. Unsting from retainer. LD Setting tools. 1/2" ball recovered. PU YJ milling
assembly. Tag cement retainer 8797 ctmd. Mill and push to 9112' ctmd. POOH to
inspect burn shoe.
***Job continued 7/13/23***
Daily Report of Well Operations
PBU L-254
7/13/2023
CTU 9 - 1.75" CT - .156" WT - Job Scope = Set WellTec Expandable Metal Packers,
Mill Retainer, CBP ***Job continued from 7/12/23***
Continue OOH to inspect burn shoe. Recovered some of the retainer pieces. MU new
burn shoe and RIH. Tag plug at 9110 ctmd. Attempt milling with no headway. POOH.
5 Slip pieces and Body lock ring recovered. RIH with exact same YJ Venturi Burn
Shoe. Stack down 12k. No motor work. POOH, Recover Entire Retainer. RIH with
Venturi Burn Shoe again, More carbide on interior wall of shoe. Tagged CBP 9115
ctmd. Attempted to mill through with no success. POOH. Recovered more slip
segments, pieces of cement retainer and some composite pieces. MU YJ burn shoe
w/ venturi and run again.
***Job Continued 7/14/23***
7/14/2023
CTU 9 - 1.75" CT - .156" WT - Job Scope = Set WellTec Expandable Metal Packers,
Mill Retainer, CBP ***Job continued from 7/13/23***
Continue in hole w/ YJ milling assembly and 3.7" burn shoe. Tag the plug 9116 ctmd,
begin milling. Plug broke free, push down to 13110'. CT Encountered Lockup.
POOH to check basket. Minimal CBP debris in Venturi basket #4. Change
Packoffs/Inspect Injector Chains. RIH with YJ 5-Blade Junk mill and Tempress tool.
Tag plug at 13,133 ctmd, work on pushing plug to TD.
***Job Continued on 7/15/23***
7/15/2023
CTU 9 - 1.75" CT - .156" WT - Job Scope = Set WellTec Expandable Metal Packers,
Mill Retainer, CBP ***Job continued from 7/14/23***
Continue to push plug with YJ milling assembly and Tempress w/ 3.68" mill.
Encounter ~500 psi pressure drop wile pushing plug to TD. POOH, find Rupture Disc
blown. Remove Circ Sub. RBIH with Same 5 blade junk mil 3.68" OD. 13,400 start
loosing weight and had to start agitating at 13,600' to make progress.
***Job continued on 7/16/23***
7/16/2023
CTU 9 - 1.75" CT - .156" WT - Job Scope = Set WellTec Expandable Metal Packers,
Mill Retainer, CBP ***Job continued from 7/15/23***
Continue in hole with YJ milling assembly and Tempress w/ 3.68" mill agitating to
bottom. Push CBP to PBTD 15300' CTM. FP TBG w/50 bbls diesel. RDMO.
***Job Completed***
7/16/2023
***WELL S/I ON ARRIVAL***
BRUSH w/ 4-1/2" BLB, 3.805" G-RING, BRUSH SSD 6308' SLM, TIGHT SPOT @
6452' SLM & X-NIPS @ 6525' & 6552' SLM
RIH 4-1/2" X-LINE 3.81" x 2.31" NIP-REDUCER (slec, secondary lock, lih 37") cont
on next day
***WSR CONT ON 7-17-23***
7/17/2023 TFS U-3 (Assist Slickline). Travel to location *Job continues to 7-18-23*
7/17/2023
T/I/O=250/75/0 (Assist Slickline) TFS U-3. Pumped 3.3 bbls Crude down TBG and
IA to reach test pressure of 3500 max applied For a ***PASSING*** CMIT TxIA
initial pressure= 3411/3408/8 Starting pressure 3502/3500/12 1st 15 min
3494/3491/10 2nd 15 min 3489/3483/10 Tags hung Well left in SL control upon
departure
Daily Report of Well Operations
PBU L-254
7/17/2023
*** WELL SI ON ARRIVAL ***
INITIAL T/I/O = 200/0/0
PT PCE 300 PSI LOW, 3000 PSI HIGH
SET NS PATCH FROM 6356' - 6376' ME-ME. CCL - MID ELEMENT = 10.5', CCL
STOP 6345.5'
TOP OF PATCH AT 6353', BOTTOM AT 6381'
LINE WT 1255/890 LB, 58 SEC TO SET W/ SLOW BURN, GOOD INDICATION.
ELINE COMPLETE.
FINAL T/I/O = 0/0/0
*** WELL SI ON DEPARTURE, DSO NOTIFIED *** READY FOR
SLICKLINE/FULLBORE
7/17/2023
***WSR CONT FROM 7-16-23***
SET 3.81" x 2.31" NIP REDUCER ( lih 37") @ 6537' MD
SET 2.31" XX-PLUG (4 x 3/16" ports, lih 24") IN NIP-REDCER @ 6537' MD
RAN 4-1/2" 42BO SHIFT SLEEVE CLOSED @ 6293' MD
PERFORM PASSING 3,500 psi CMIT-TxIA
PULL 2.31" XX PLUG FROM 6,558' SLM (6,537' MD)
***WELL S/I ON DEPARTURE***
7/17/2023
***WELL S/I ON ARRIVAL***
SET 2.31" XX-PLUG (4 x 1/8" ports, lih 24") IN NIP-REDUCER @ 6537' MD (hung
tag on master)
*** WELL LEFT S/I***
7/18/2023
*Job continues from 7-17-23*
T/I/O=100/0/0 (Assist slickline w/ MIT-T & MIT-IA) TFS U3. Pumped 1.5 BBLS of
crude down the TBG to assist slickline in setting plug and confirming set. Pumped .2
BBLS of crude down the TBG for an MIT-T MAP 3500 psi. Reached test pressure at
3509 psi. First 15 minutes TBG lost 47 psi. Second 15 minutes TBG lost 20 psi.
***PASSED***. Bleed back TBG to 2000 psi for MIT-IA. Pumped 1.4 BBLS of crude
down the IA for an MIT-IA MAP 3500 psi. Reached test pressure at 3497 psi. First 15
minutes IA lost 36 psi. Second 15 minutes IA lost 9 psi. ***PASSED***. Bled down
both strings TBG and IA took back 2.9 bbls.
FWHPS= 342/349/0. SV/SSV/WV=C MV=O I/O=OTG
7/19/2023
T/I/O=50/278/0 State witness Brian Bixby (NEW WELL POST) Pump 0.8 bbls DSL
into TBG to pressure to 2000 PSI, Line up to IA, Pump 1.7 bbls into IA to reach test
pressure.
*****MIT-IA PASSED To 3659 PSI.**** (3700 MAX, 3500 Target) Loss of 97 psi 1st
15 min, Loss of 22 psi 2nd 15 min for a total loss of 119 psi durning 30 min test. Bled
back 1.7 bbls. FWHP=50/380/0 Casing valves OTG
7/19/2023
***WELL S/I ON ARRIVAL***
RAN 42BO(self releasing key) TO XD SSD AT 6,293' MD OPEN SLEEVE (verified
communication)
PULLED 2.31 XX-PLUG FROM 4-1/2" NIP REDUCER @ 6537' MD
RAN 3.81" LOCK / CHAMPION 4.5" 13A JET PUMP (secondary lock, no eq sub)
(sn# BP1017, lih 70" (2 sets std packing stack, 37-1/4" center to center of stack)
***WSR CONT ON 7-20-23***
7/20/2023
LRS Test Unit 6, Begin WSR on 7/20/23. New Well POP w/ Jet Pump, IL L-254, OL L-
254 FL, Unit Move, RU, SB. Cont WSR on 7/21/23.
Daily Report of Well Operations
PBU L-254
7/20/2023
***WSR CONT FROM 7-19-23***
SET 3.81" LOCK / CHAMPION 4.5" 13A JET PUMP IN SSD @ 6293' MD (sn#
BP1017, lih 70", no_eq sub) (2 sets std packing stack, 37-1/4" center to center of
stack, sec lock (hung tag on master)
RAN 4-1/2" CHECK SET (sheared)
***JOB COMPLETE, WELL LEFT S/I***
7/21/2023
LRS Test Unit 6, Continue WSR from 7/20/23. New Well POP w/ Jet Pump, IL L-254,
OL L-254 FL, Continue RU, Begin SB, POP/Flow Well, Cont WSR on 7/22/23.
7/22/2023
LRS Test Unit 6, Continue WSR from 7/21/23. New Well POP w/ Jet Pump, IL L-254,
OL L-254 FL, Continue to Flow Well, 12h PBWT, Cont WSR on 7/23/23.
7/23/2023
LRS Test Unit 6, Continue WSR from 7/22/23. New Well POP w/ Jet Pump, IL L-254,
OL L-254 FL, Finish 12h PBWT, BD, Begin RD, Cont WSR on 7/24/23.
7/24/2023
LRS Test Unit 6, Continue WSR from 7/23/23. New Well POP w/ Jet Pump, IL L-254,
OL L-254 FL, Finish RD, End WSR on 7/24/23.Job Complete
8/12/2023
***WELL FLOWING ON ARRIVAL***(jet pump c/o)
DRIFT W/ 3.80" GAUGE RING TO 4-1/2" JET PUMP @ 6,293' MD
PULL 4-1/2" JET PUMP @ 6,293' MD
***LDFN, CONT WSR ON 8-13-23***
8/13/2023
***CONT WSR FROM 8-12-23***(c/o jet pump w/ gauges)
SET 4-1/2" JET PUMP IN XD-SS @ 6,293' MD (3.81 x-lock, sec lkdwn installed, 13A
ratio, flow through sub w/ sbhps gauges, oal 121")
***WELL LEFT S/I ON DEPARTURE***
*******PROGRAM GAUGES 15 SEC SAMPLES FOR 720 DAYS, BATTERY
CONNECT TIME 08:43 AM ON 8/13/23******
***SBHPS SN: 79566 & 79569***
9/30/2023
T/I/O=564/527/0 Assist S-Line (NEW WELL) Load IA w/ 55 bbls 1% KCL, Freeze
protect w/ 62 bbls DSL, S-Line set sleeve, MIT-IA Pumped 1.5 bbls dsl to reach max
applied pressure 2507 psi. 15 min loss 83 psi. 30 min loss 28 psi. Bled back 1.5 bbls
to starting pressure. Pumped 51 bbls dsl down TBG for FP.
FWHP=871/671/0
9/30/2023
****WELL S/I ON ARRIVAL****
DRIFTED w/ 3.80" GAUGE RING TO JET PUMP AT 6,293' MD
PULLED 4 1/2" JET PUMP AT 6,293' MD
LRS LOADED IA WITH 55BBLS CISW & 62BLS DSL FP.
CLOSED XD SLIDING SLEEVE AT 6,293' MD w/ 42 BO
LRS PERFORMED 2500PSI MIT-IA
LEFT LRS ON LOCATION TO PUMP TBG FP AFTER MIT-IA
***WELL S/I ON DEPARTURE***
10/5/2023
T/I/O = 340/180/180. Temp = 110°. IA FL (pre AOGCC). IA FL @ surface.
SV = C. WV, SSV, MV = O. IA, OA = OTG. 23:30
10/8/2023
T/I/O =359/296/285 (MIT-IA) AOGCC MIT-IA - PASSED to 1649 psi. Target 1548
psi. Max applied = 1720 psi. Pumped 1.1 bbls diesel down IA to achieve test
pressure. 1st 15 min. IA lost 64 psi. 2nd 15 min. IA lost 7 psi. Total loss in 30 min. =
71 psi. Bled IAP back to 100 psi. Bled back ~ 1.1 bbls. Witnessed by State Rep Bob
Nobel and Hilcorp Rep Andy Ogg. DSO notified of well status. Well on injection, IA
and OA = OTG. Tag hung on IA valve. RDMO FWHP's =359/100/247
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
117
56
X Yes No X Yes No 5.6
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns ?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns ?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Float Shoe
RKB
10 3/4
526 20422
SE
C
O
N
D
S
T
A
G
E
MP1
22:53
Cement Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.6
Shoe @ 7235 FC @ Top of Liner7,150.83
Floats Held
40 869
343 526
Spud Mud
CASING RECORD
County State Alaska Supv.S Barber/ O Amend
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-254 Date Run 16-Jun-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC OSP 1.75 7,235.00 7,233.25
25.40
Csg Wt. On Hook:245,000 Type Float Collar:Conventional No. Hrs to Run:21.5
9.7 5
2119
10
10.7 443 5.2
94
998
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 4# Red Dye & 5# Pol-E-Flak 60
15.8
598
3.4
9.7 6 166.2/166.2
535.3/533.3
1535
80
MP 1
15.8 82
Bump press
Calculated
Bump Plug?
y
9:31 6/17/2023 2,278
2277.62
7,234.357,244.00
CEMENTING REPORT
Csg Wt. On Slips:45,000
Spud Mud
Tuned Spacer 4# Red Dye & 5# Pol-E-Flake
870 2.85
Stage Collar @
60
Bump press
100
343
ES Cementer Closure OK
56
12 288
26.68 RKB to CHF
Type of Shoe:Conventional Casing Crew:Parker Wellbore
No. Jts. Delivered 195 No. Jts. Run 177 18
Length Measurements W/O
Threads
Ftg. Delivered 7,995.00 Ftg. Run 7,234.00 Ftg. Returned 761.00
Ftg. Cut Jt.28.75 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.6
ArcticCem Type I/II
Type
Jnt 1 2 ea BS & 4 ea SR 10' from end, 1 ea BS & 2 ea SR jnt 2 & 3. Every jnt F/ 4-25, every other F/ jnt 27-61, 1 ea
116-120, 1 ea ES pups, 1 ea jnt 122-126, 56 total solid bow spring.
9.625 CSG 9 5/8 40.0 L-80 BTC Tenaris 81.03 7,233.25 7,152.22
Float Collar 10 3/4 BTC Innovex 1.39 7,152.22 7,150.83
9.625 CSG 9 5/8 40.0 L-80 BTC Tenaris 39.08 7,150.83 7,111.75
Baffle Adapter 10 3/4 BTC Halliburton 1.40 7,111.75 7,110.35
9.625 CSG 9 5/8 40.0 L-80 TXP BTC Tenaris 4,811.79 7,110.35 2,298.56
Pup 9 5/8 40.0 L-80 TXP BTC 18.11 2,298.56 2,280.45
ES Cementer 11 3/4 TXP BTC Halliburton 2.83 2,280.45 2,277.62
Pup 9 5/8 40.0 L-80 TXP BTC 17.55 2,277.62 2,260.07
9.625 CSG 9 5/8 47.0 L-80 TXP BTC Tenaris 2,234.67 2,260.07
EconCem Type I/II 688 2.35
HalCem Typ I/II 400 1.16
4.4
HalCem Type I/II 270 1.16
6/17/2023 Surface
Spud Mud
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, September 12, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Brian Bixby
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
L-254
PRUDHOE BAY UNIT L-254
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 09/12/2023
L-254
50-029-23752-00-00
223-030-0
N
SPT
4342
2230300 3500
2000 2368 2304 2250
0 0 0 0
OTHER P
Brian Bixby
7/19/2023
MITIA as per SUNDRY 323-381
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PRUDHOE BAY UNIT L-254
Inspection Date:
Tubing
OA
Packer Depth
461 3659 3572 3550IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitBDB230720033038
BBL Pumped:1.7 BBL Returned:1.7
Tuesday, September 12, 2023 Page 1 of 1
Tbg patch
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: 07/27/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: PBU L-254
PTD: 223-030
API: 50-029-23752-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (06/10/2023 to 06/27/2023)
x EWR-M5, AGR, ABG, DGR, ADR, ALD, CTN, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU L-254 LWD Subfolders:
PBU L-254 Geosteering Subfolders:g
Please include current contact information if different from above.
PTD: 223-030
PBU L-254: T37883
PBU L-254 PB1: T37884
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.28
14:34:20 -08'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
WELL: PBU L-254PB1
PTD: 223-030
API: 50-029-23752-70-00
FINAL LWD FORMATION EVALUATION LOGS (06/10/2023 to 06/24/2023)
x EWR-M5, AGR, ABG, DGR, ADR, ALD, CTN, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
PBU L-254PB1 LWD Subfolders:
Please include current contact information if different from above.
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2023.07.28
14:33:51 -08'00'
SCHRADER BLUFF, UNDEFINED OIL SCHRADER BLUFF, UNDEFINED OIL
By Grace Christianson at 2:51 pm, Jul 10, 2023
323-381
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.07.10 13:29:46 -08'00'
Torin
Roschinger
(4662)
State to witness MIT-IA to 3500 psi. 24 hour notice.
MDG 7/12/2023
MGR11JUL23 DSR-7/12/23
10-404
GCW 07/13/2023
07/13/23
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.13
19:06:17 -05'00'
RBDMS JSB 071823
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
Well Name:L-254i API Number: 50-029-23752-00
Current Status:Pre-Produced Injector Rig:SL, EL, CT, FB, WT
Estimated Start Date:7/3/2023 Estimated Duration: 30 days
Sundry #N/A Date Approval Rec’vd:N/A
Regulatory Contact:Abbie Barker PTD Number:223-030
First Call Engineer:Josh Stephens 970-779-1200 (Cell)
AFE:231-00024.05.02
Current Bottom Hole Pressure:
Max Bottom Hole Pressure:
Max. Proposed Surface Pressure:
Kill Weight Fluid
Min ID:
Unknown
1958psi @ 4,350’ TVD
1523psi
8.7ppg
3.813” at 2,900’ MD
(Based on typical SB pressure)
(Based on .1psi/ft gas gradient)
Brief Well Summary:
L-254i will be a pre produced Shrader Bluff injector. The AOGCC has granted 30 days of pre-production which
we plan to do via Jet Pump completion. The objective of this pre-production period is to do a proof of concept
for future jet pump completions in Schrader development.The iRig was unable to get a passing MIT-T or MIT-
IA, but did get a passing CMIT-TxIA indicating the packer was set and holding. Post rig diagnostics done by SL
indicate the leak is below the sliding sleeve, an LDL ran on EL confirmed the leak in the middle of the gauge
carrier at 6,368’.
Objective: Pull ball and rod, Set TTP, Run LDL, set Welltec expandable metal packers,Set TBG Patch (Sundry
approval required), install Jet Pump, flow well back via test separator.
Procedure:
Slickline:
1.MIRU SL, set TTP in SSD and MIT-T. –Completed 7/5/23 MIT-T passed
2.Set isolation sleeve over SSD and MIT-T – Completed 7/5/23 – MIT-T Failed
3.Pull isolation sleeve and run D&D hole finder – Attempted D&D 7/6.
4.Pull B&R/RHC plug body and set XX plug at 6,537’. – Completed 7/6/23.
Fullbore:
1. Perform CMIT-TxIA to 2,500psi to confirm plug set
2. A/EL by pumping down the TBG taking returns from the IA
E-Line:
1. MIRU EL, MU Read acoustic LDL tools with ILS
2. RIH to top of TTP for baseline pass
a.Tie into Final tubing tally for depth control
3. Have LRS pressure TBG to 2,500psi or .25BPM while taking returns out IA to tanks
4. Log OOH at 30FPM looking for leak
a.Perform up down passes over leak points
b.Perform Station counts above and below leak points
5. Send log data to josh.stephens@hilcorp.com
6. Confirm results with OE before rigging down. – EL LDL completed 7/8/23
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
Slickline:
1. MIRU SL
2. Pull TTP from 6,537’
3. RDMO SL
Coiled Tubing (NCS Tools):
1. MIRU CTU, Pressure test PCE
2. MU memory logging tools and perform tie in log from below lowest expandable metal packer at ~9058’
a. Flag pipe near lowest welltec packer.
b. Flag pipe again near upper welltec packer.
3. POOH and download log data.
a. Send log data to OE to verify set depths and correction.
b. Final set depths will be based on as-run liner tally.
4. MU 4.5” CBP BHA
a. RIH and set CBP in full joint below lowest set welltec packer.
b. POOH and lay down CBP BHA
5. MU NCS Multi Set retainer tools and RIH
a. Set NCS retainer tool in full joint above upper packer
b. Pressure up below retainer to ~4,500psi per NCS/Welltec rep.
c. Do not tag CBP with NCS tools as you may not be able to release the packer if you tag up.
6. POOH and lay down NCS tools
7. MU 4.5” Milling BHA
a. RIH and Mill CBP from
Coiled Tubing (contingent):
8. MIRU CTU, Pressure test PCE
9. MU memory logging tools and perform tie in log from below lowest expandable metal packer at
~10,670’
a. Flag pipe near first full joint below lowest welltec packer for plug setting depth
b. Flag pipe again near first full joint above upper welltec packer for retainer setting depth
10. POOH and download log data.
a. Send log data to OE to verify set depths and correction.
b. Final set depths will be based on as-run liner tally.
11. MU 4.5” CBP BHA
a. RIH and set CBP in full joint below lowest set welltec packer.
b. POOH and lay down CBP BHA
12. MU 4.5” one-trip retainer BHA
a. RIH and set retainer in full joint above upper welltec packer.
13. Expanded welltec packers by pressuring but down the CT between the retainer and CBP to ~4,500psi.
a. Welltec will recommend the final setting pressure and inflate procedure.
b. Once packer set is verified with welltec, POOH and lay down retainer BHA.
14. MU 4.5” Milling BHA
a. RIH and Mill retainer and packer and push to TD
15. RDMO CTU
Slickline:
1. MIRU SL
2. Set Nipple Reducer at 6,537’
3. Set XX Plug in reducer and CMIT-TxIA to 3,500psi to confirm set.
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
4. Pull XX Plug from reducer.
5. RDMO SL
E-Line (Sundry Required before proceeding)
1. MIRU EL
2. MU one trip patch with ~23’ element to element.
3. RIH and set patch over gauge carrier at 6362.56’
a. Set packer elements in 10’ pup joints above and below carrier avoiding collars.
Fullbore:
1. MIT-IA to 3,500psi
a. Please notify AOGCC 24hrs in advance for witness.
Slickline(Pending MIT results):
1. MIRU SL
2. RIH with 4.5” sleeve shifting tool and open SSD at ~6,320’
a. Confirm sleeve is open by pumping down the IA and monitoring WHPs during shifting.
3. MU Champion 4.5” 13A Jet pump and set in SSD at ~6,320’
a. Jet Pump to be sourced from MPU WSS, 4.5” lock to be provided by Prudhoe WLB
b. Secondary lock pin should be used for flow through application
c. Confirm set with “check set”
d. Confirm set by pumping down the IA.
4. RDMO SL
Well Testing:
1. POP well via portable test separator.
a. Detailed POP procedure will be submitted at a later date
Attachments:
1. Documentation, fluid sampling, and communication requirements
2. Proposed Schematic
3. TBG Tally
4. LDL Results
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
Documentation, fluid sampling, and communication requirements
Documentation -Please record the following additional parameters in the daily job logs
1. PWI pump pressure and rates anytime changes are made or pressure changes.
2. PWI pump volumes every 3 hours – can be a rolling total.
Fluid Sampling –Please take the following fluid sample readings and record in daily job logs
1. Water cut and solid sampling every 30 minute while bringing the well online.
2. API gravity every 3 hours while bringing the well online.
3. Water and solid sampling every 20 minutes while on stable production.
4. API gravity every 90 minutes while well is on stable production.
Communication Requirements –Please notify OE for the following conditions
1. Production flow less than pump rate
2. Any sudden changes in WHP or Pump pressure/rate
3. Consecutive solid samples of more than 1.5%
4. Before moving the well into production
5. Before rigging the test unit down
_____________________________________________________________________________________
Revised By: JLS 7/10/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-254
Last Completed: 7/3/2023
PTD: 223-030
4-1/2” Slotted Liner
TD =15,425’(MD) / TD =4,494’ (TVD)
20”
Orig. KB Elev.: 74.18’ / GL Elev.: 47.5’
7”
5
11
9-5/8”
1
2
4
See
Slotted
Liner
Detail
7”x
4-1/2”
XO
PBTD = 15,281’(MD) / PBTD = 4,469’ (TVD)
9-5/8” ‘ES’
Cementer @
2,278’
PB1:
8845’ – 10621’
4-1/2”
10
8
7
3
6
9
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 107’ N/A
9-5/8" Surface 47/ L-80 / BTC 8.681 Surface 2,260’ 0.0732
9-5/8” Surface 40 / L-80 / VAM 21 8.835 2,260’ 7,235’ 0.0758
7” Tieback 26 / L-80 / BTC 6.276 Surface 6,358’ 0.0383
7” Liner 26 / L-80 Hyd 563 6.276 6,350’ 7,232’ 0.0383
4-1/2” Liner 12.6 / L-80 / H563 3.958 7,232’ 15,283’ 0.0155
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / VAMtop 3.958 Surface 7,230’ 0.0152
OPEN HOLE / CEMENT DETAIL
42” 18 yds Concrete
12-1/4"Stg 1 – Lead – 688 sx / Tail – 400 sx
Stg 2 – Lead – 870 sx / Tail – 270 sx
8-1/2” Cementless Slotted Liner
WELL INCLINATION DETAIL
KOP @ 150’
90° Hole Angle = @ 7,350’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23752-00-00
Completion Date: 7/3/2023
JEWELRY DETAIL
No. Top MD Item ID
1 2,890’ X Nipple 3.813”
2 6,293’ X Nipple w/ Sliding Sleeve and Jet Pump 3.813”
3/4 6,363’ Baker gauge carrier isolated with tubing patch
5 6’350’ 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve
6 6,437’ Production Packer
7 6,509’ X Nipple 3.813”
8 6,537’ X Nipple 3.813”
97,230WLEG – Bottom
10 8819’-9068’ Welltec Metal Expandable Packer straddle
11 15,281’ Shoe
Top (MD) Top (TVD) Btm (MD) Btm (TVD)
7316’ 4530’ 15242’ 4462’
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
Tubing Tally
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
Well Stage: Pre Production
Well: L-254i
Current PTD: 223-030
REV. 2
LDL Results
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
July 10, 2023
Ms. Natalie Brent
Senior Reservoir Engineer, Prudhoe Bay West
Hilcorp North Slope, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99519-6612
Re: Docket Number: CO-23-008
Request for a waiver of the gas oil ratio limitations in 20 AAC 25.240(a) for the Prudhoe Bay Unit
L-253 (PTD 223-048) and L-254 (PTD 223-030) wells
Dear Ms. Brent:
By letter dated May 24, 2023. Hilcorp North Slope, LLC (Hilcorp) requested a temporary waiver of the
gas-oil ratio (GOR) limitations in 20 AAC 25.240(a) for the two subject wells to allow the wells to be put
on production to gather performance data and fluid properties while the application to expand the Schrader
Bluff Oil Pool (SBOP) in the Prudhoe Bay Unit (PBU) is being adjudicated by the Alaska Oil and Gas
Conservation Commission (AOGCC). The PBU L-254 is an injector that will be pre-produced for up to
30 days. This pre-production period will help evaluate the potential for drilling additional wells west of
the existing SBOP development wells. The PBU L-253 will also add to the knowledge in that area. Being
able to collect this information while the AOGCC completes its adjudication of the application to expand
the SBOP will allow for the collection of information necessary to determine future development of the
SBOP which is an allowable reason for a waiver pursuant to 20 AAC 25.240(b)(3).
Hilcorp’s request is hereby granted. This waiver shall expire 6 months after date of issuance or
upon the acreage these wells are located on is added to the SBOP, which ever occurs first.
DONE at Anchorage, Alaska and dated July 10, 2023.
Brett W. Huber, Sr. Gregory C. Wilson
Chair, Commissioner Commissioner
Gregory
Wilson
Digitally signed by Gregory
Wilson
Date: 2023.07.10 13:39:12
-08'00'
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.10
13:41:27 -08'00'
Ms. Natalie Brent
July 10, 2023
Page 2 of 2
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the
AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter
determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out
the respect in which the order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act
on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the
denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date
on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS
the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for
reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be
filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision
on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in
the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until
5:00 p.m. on the next day that does not fall on a weekend or state holiday.
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Phone: 907/777-8300 hilcorp.com
Hilcorp North Slope, LLC
May 24, 2023
Brett Huber, Sr., Chair
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, AK 99501
RE: Request for a Temporary Waiver of the Gas-Oil Ratio requirement of 20 AAC 25.240
Chair Huber,
Hilcorp North Slope, LLC, as operator of the Prudhoe Bay Unit, requests a Temporary Waiver of the Gas-
Oil Ratio requirement of 20 AAC 25.240 for wells L-253 and L-254. Initially, these wells will not be part
of the existing Orion PA or Schrader Bluff Oil Pool and will be operating under a tract operation and thus
statewide regulations. We are concurrently working with the AOGCC to expand the Schrader Bluff Oil
pool to include these wells. We plan to work with the DNR to expand the Orion PA shortly after.
As operator, Hilcorp plans to operate these wells similar to other producers in the Schrader Bluff Oil
Pool, Orion Development Area. We will pre-produce L-254 (injector) for 30 days to gather initial
potential and fluid quality data to determine the viability of additional drilling to the west of the existing
Schrader Bluff Oil Pool, Orion Development Area. The L-253 (producer) will be put online to gather
initial potential and fluid quality data. During this flow time, the near wellbore region will see a pressure
drop which will cause the GOR to increase, possibly above the current GOR limitations. This is expected
to be temporary because as soon as the Schrader Bluff Oil Pool, Orion Development Area pool
expansion is approved, L-254 will be converted to an injector and put on produced water and miscible
injectant to maintain reservoir pressure.
Thank you,
Natalie Brent
Senior Reservoir Engineer, Prudhoe Bay West
Hilcorp North Slope, LLC
Digitally signed by Natalie Brent (1028)
DN: cn=Natalie Brent (1028)
Date: 2023.05.24 15:26:42 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:20230620 1447 PBU L-254 (PTD_ 223-030) Surface Casing Test & FIT
Date:Tuesday, June 20, 2023 3:16:35 PM
Attachments:HAK PBW L-254 Surface Casing Test & FIT.pdf
From: Joseph Engel <jengel@hilcorp.com>
Sent: Tuesday, June 20, 2023 2:47 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: HAK PBW L-254 (PTD: 223-030) Surface Casing Test & FIT
Mel –
Attached is the 9.625” Surface Casing pressure test and FIT for L-254.
The two stage cement job went well.
First stage: Pumped 288 bbl of 12# lead, 82 bbls of 15.8# tail, lost 66 bbls during
displacement and saw ~80 bbls of cement circulated through the stage tool to surface
Second stage: Pumped 443 bbls of 10.7 lead, 56 bbls of 15.8# tail, no losses throughout the
job, circulated 343 bbls of cement to surface
-Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
Office: 907.777.8395 | Cell: 805.235.6265
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-254 Date:6/20/2023
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Amend/Carter
Csg Setting Depth:7235 TMD 4525 TVD
Mud Weight:9.2 ppg LOT / FIT Press =697 psi
LOT / FIT =12.16 ppg Hole Depth =7264 md
Fluid Pumped=1.4 Volume Back =1.3 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->2 40 ->0 0
->4 104 ->8 158
->6 159 ->16 418
->8 225 ->24 657
->10 286 ->30 830
->12 348 ->35 980
->14 418 ->40 1139
->16 483 ->45 1300
->18 547 ->50 1456
->20 615 ->60 1793
->22 677 ->70 2127
->24 697 ->80 2461
-> ->87 2695
-> ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 697 ->0 2695
->1 670 ->1 2679
->2 655 ->2 2667
->3 643 ->3 2658
->4 633 ->4 2653
->5 625 ->5 2651
->6 618 ->10 2650
->7 610 ->15 2646
->8 606 ->20 2646
->9 601 ->25 2643
->10 596 ->30 2641
-> ->
-> ->
-> ->
2
4
6
8
10
12
14
16
18
20
2224
0
8
16
24
30
35
40
45
50
60
70
80
87
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 10 20 30 40 50 60 70 80 90 100Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
697670655643633625618610606601596
269526792667265826532651 2650 2646 2646 2643 2641
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 30Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UNIT L-254
JBR 07/27/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:tested with 5 " test joint. Rig and surrounding area was well kept. All signage was in place at location. Crew was prepared and efficient.
TEST DATA
Rig Rep:Joel StureOperator:Hilcorp North Slope, LLC Operator Rep:Steve Carter
Contractor/Rig No.:Hilcorp Innovation PTD#:2230300 DATE:6/9/2023
Well Class:DEV Inspection No:divSTS230609161821
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
Test Time:1.5
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:13.625 P
Hole Size:12.25 P
Vent Line(s) Size:16 P
Vent Line(s) Length:214 P
Closest Ignition Source:80 P
Outlet from Rig Substructure:199 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:12 P
Knife Valve Open Time:6 P
Diverter Misc:NA
Systems Pressure:P3050
Pressure After Closure:P2225
200 psi Recharge Time:P18
Full Recharge Time:P42
Nitrogen Bottles (Number of):P6
Avg. Pressure:P2350
Accumulator Misc:NA
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp North Slope, LLC
3800 Centerpoint Dr., Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay, Schrader Bluff, PBU L-254
Hilcorp North Slope, LLC
Permit to Drill Number: 223-030
Surface Location: 2291’ FSL, 4062’ FEL, Sec. 34, T12N, R11E, UM, AK
Bottomhole Location: 581’ FSL, 1748’ FEL, Sec. 09, T11N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of May, 2023. 15
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.05.11 10:10:29
-08'00'
5
5
5
5
55
5
5 5 5 5
5
Schrader Bluff
DSR-3/31/23
029-23752-00-00
679 sx
* BOPE test to 3000 psi. Annular to 2500 psi.
* Approved for 30 days of pre-production
* MIT-IA to 3500 psi. 24 hour notice to AOGCC for opportunity to witness.
* AOGCC to witness MIT-IA after 7 days of stabilized injection. *Variance to 200' packer placment above top of perforations approved.
Injection may not commence until the AIO is expanded.
MGR10MAY2023
223-030
-mgr
MDG 5/1/2023GCW 05/11/23JLC 5/11/2023
5/11/2023Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.05.11 10:16:24 -08'00'
Well Name PTD API Status
Top of Oil Pool
(SB OBd, MD)
Top of Oil Pool
(SB OBd, TVD)Top of Cmt (MD) Top of Cmt (TVD)
Zonal
Isolation Comments
PBU L-121 203-0130 50-029-23138-00-00
P&A'd open
hole lateral 8363' 4528' 6050' 3641' Closed
Open hole lateral P&A'd with
4 cement plugs. 52bbl cement
plug at 12,990, 317bbl of
cement pumped on 2, 3 and
4th plug from 8850' to 6050'
MD. Plug 2 and 3 confimed
with tag/returns. 4th plug
not verified.
Area of Review PBU L-254i
Prudhoe Bay West
(PBU) L-254
Drilling Program
Version 1
3/28/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner ...................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 39
19.0 Innovation Rig Diverter Schematic ......................................................................................... 41
20.0 Innovation Rig BOP Schematic ............................................................................................... 42
21.0 Wellhead Schematic ................................................................................................................. 43
22.0 Days Vs Depth .......................................................................................................................... 44
23.0 Formation Tops & Information............................................................................................... 45
24.0 Anticipated Drilling Hazards .................................................................................................. 47
25.0 Innovation Rig Layout ............................................................................................................. 51
26.0 FIT Procedure .......................................................................................................................... 52
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 53
28.0 Casing Design ........................................................................................................................... 54
29.0 8-1/2” Hole Section MASP ....................................................................................................... 55
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 57
Page 2
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU L-254
Pad Prudhoe Bay L Pad
Planned Completion Type 4-1/2” Injection Tubing
Target Reservoir(s)Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 15,379’MD /4,414’ TVD
PBTD, MD / TVD 15,369’ MD /4,414’ TVD
Surface Location (Governmental)2291' FSL,1217' FWL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27)X=582,855,Y=5,978,009
Top of Productive Horizon
(Governmental)2001' FNL, 1707' FEL, Sec 4, T11N, R11E, UM, AK
TPH Location (NAD 27)X=579987,Y=5973685
BHL (Governmental)581' FSL,1748' FEL, Sec 9, T11N, R11E, UM, AK
BHL (NAD 27)X=580050, Y=5965708
AFE Number 231-00024
AFE Drilling Days 19
AFE Completion Days 3
Maximum Anticipated Pressure
(Surface)1533 psig
Maximum Anticipated Pressure
(Downhole/Reservoir)1984 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL:26.5 ft +47.5 ft =74.0 ft
GL Elevation above MSL:47.5 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-254 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-52 Weld
12-1/4”9-5/8”8.835”8.679”10.625”40 L-80 BTC 5,750 3,090 916
9-5/8”8.681”8.525”10.625”47 L-80 VAM 21 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.565 26 L-80 BTC 7,254 5,410 604
8-1/2”7”6.276 6.151 7.656 26 L-80 H563 7254 5410 604
4-1/2”3.958 3.833 5.2 12.6 L-80 H563 7780 6350 267
Tubing 4-1/2”3.958 3.833 4.937 12.6 L-80 VAMTOP 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25”6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25”6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
Report covers operations from 6am to 6am
Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
Ensure time entry adds up to 24 hours total.
Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
Health and Safety: Notify EHS field coordinator.
Environmental: Drilling Environmental Coordinator
Notify Drilling Manager & Drilling Engineer on all incidents
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Josh Stephens 907.777.8420 josh.stephens@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Natalie Brent 907.564.4313 nbrent@hilcorp.com
Drilling Env.
Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-254 is a grassroots injector planned to be drilled in the Schrader Bluff OBd sand. L-254 is part of a
multi well program targeting the Schrader Bluff sand on PBU L-pad.
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set in the OBd. An 8-1/2” section will
be drilled in the OBd. A 4-1/2” slotted injection liner will be run in the open hole section, followed by a 7”
tieback, and the well will be completed with injection tubing. L-254 is planned to be pre-produced prior to
being put on injection.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately May 22, 2023, pending rig schedule.
Surface casing will be run to 7,350’ MD / 4,530’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” hole to TD
6. Run 4-1/2” injection liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. Remote Ops geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote Ops geologist. LWD: GR + ADR (For geo-steering)
30 days per Joe Lastufka, see email 5/1/2023
L-254 is planned to be pre-produced prior to
being put on injection.
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Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-254. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
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.
If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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Drilling Procedure
AOGCC Regulation Variance Requests:
1) “A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates
pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure
that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the
maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured
depth above the top of the perforations, unless the commission approves a different placement depth as the
commission considers appropriate given the thickness and depth of the confining zone.”
In order to effectively produce this fault block, the current wellplan has the surface casing shoe landing at the
OBd production interval at ~88 degrees inclination. In order to make the ball and rod we land to set the
production packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees
inclination. The MD we currently have planned for 70 degrees is at ~6580’ MD. The production packer will be
~50’ MD above the X nipple which puts it at ~6450’ MD / ~4360’ TVD. The surface casing shoe is planned at
~7350’ MD / 4530’ TVD which means the planned packer depth is ~900’ MD away. From a TVD standpoint, the
production tubing packer is ~170’ TVD from the surface casing shoe. With the surface casing set in the Schrader
Bluff sand, and the injection packer set inside the surface casing, injection fluids will be confined to the Schrader
bluff sands.
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Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
13-5/8” x 5M Control Technology Inc Annular BOP
13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
Mud cross w/ 3” x 5M side outlets
13-5/8” x 5M Control Technology Single ram
3-1/8” x 5M Choke Line
3-1/8” x 5M Kill line
3-1/8” x 5M Choke manifold
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:
Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
24 hours notice prior to spud.
24 hours notice prior to testing BOPs.
24 hours notice prior to casing running & cement operations.
Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-254 will utilize a newly set 20” conductor on L-pad. Ensure to review attached surface plat
and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80 F).
9.10 Ensure 5” liners in mud pumps.
White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
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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).
N/U 20” x 13-5/8” DSA
N/U 13 5/8”, 5M diverter “T”.
NU Knife gate & 16” diverter line.
Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
Diverter line must be 75 ft from nearest ignition source
Place drip berm at the end of diverter line.
Utilized extensions if needed.
10.2 Notify AOGCC. Function test diverter.
Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
Ensure that the annular closes in less than 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:
A prohibition on vehicle parking
A prohibition on ignition sources or running equipment
A prohibition on staged equipment or materials
Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
Drill string will be 5” 19.5# S-135.
Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the OBd Sand. Confirm this setting depth with the
Geologist and Drilling Engineer while drilling the well.
Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
Hold a safety meeting with rig crews to discuss:
Conductor broaching ops and mitigation procedures.
Well control procedures and rig evacuation
Flow rates, hole cleaning, mud cooling, etc.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Keep mud as cool as possible to keep from washing out permafrost.
Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
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.
Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
Slow in/out of slips and while tripping to keep swab and surge pressures low
Ensure shakers are functioning properly. Check for holes in screens on connections.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at
base of perm and at TD (pending MW increase due to hydrates). This is to combat
hydrates and free gas risk and offset any gas cut MW, based upon offset wells.
Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
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Drilling Procedure
Be prepared for gas hydrates. In PBW they have been encountered typically around 1660’
TVD (Base of Perm) to 2740’ TVD (Top Ugnu). Be prepared for hydrates:
Gas Hydrates are present on L PAD
Keep mud temperature as cool as possible, Target 60-70*F
Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
Drill through hydrate sands and quickly as possible, do not backream.
Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
Monitor returns for hydrates, checking pressurized & non-pressurized scales
Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the
well. MW will not control gas hydrates, but will affect how gas breaks out at surface.
Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
Surface Hole AC:
There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
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)
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.
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.
Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
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Drilling Procedure
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.
Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 -40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity. Drop mud temp as low as possible as well.
11.6 RIH to bottom, proceed to BROOH to HWDP
Pump at full drill rate (400-600 gpm), and maximize rotation.
Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
Monitor well for any signs of packing off or losses.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
Ensure mud temp is as low as possible when backreaming before and through the SV 2 & 3
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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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)
Ensure 9-5/8” BTC x NC50, and VAM 21 x NC50 XO on rig floor and M/U to FOSV.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
R/U of CRT if hole conditions require.
R/U a fill up tool to fill casing while running if the CRT is not used.
Ensure all casing has been drifted to 8.75” on the location prior to running.
Top 2,500’ of casing 47# drift 8.525”
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 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
Ensure bypass baffle is correctly installed on top of float collar.
Ensure proper operation of float equipment while picking up.
Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
1 centralizer every joint to ~ 1000’ MD from shoe
1 centralizer every 2 joints to ~2,500’ above shoe (Top of Lowest Ugnu)
Verify depth of lowest Ugnu water sand for isolation with Geologist
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD).
Confirm depth of first major hydrates seen (possibly SV3) and position stage tool above if
possible, confirm with geo and drilling engineer before adjusting depth and ensure there is
enough 1st stage cement available
Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
Do not place tongs on ES cementer, this can cause damaged to the tool.
Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 47# L-80 VAM21 Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”28,400 ft-lbs 31,550 ft-lbs 34,650 ft-lbs
9-5/8” 40# L-80 BTC MUT:
Casing OD Minimum Optimum Maximum
9-5/8”29,800 ft-lbs -34,800 ft-lbs
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12.8 Continue running 9-5/8” surface casing
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Drilling Procedure
Centralizers: 1 centralizer every 3rd joint to 200’ from surface
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
Ensure drifted to 8.525”
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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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.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
Review test reports and ensure pump times are acceptable.
Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
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:
See step 13.8
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4
12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 3 316.4 1775.0
Total Lead 345.0 1935.5 438.9
12-1/4" OH x 9-5/8" Casing (2500 - 2000' x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6
Lead Slurry Tail Slurry
System Permafrost L G
Density 10.7 lb/gal 15.8 lb/gal
Yield 4.41 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
4.41 ft3/sk
679.1 sx -mgr
2.85 - mgr
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Drilling Procedure
13.26 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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L-254 SB Injector
Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in
bottom cavity.
Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
NU bell nipple, install flowline.
Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
Test with 5” test joint and test VBR’s with 3-1/2” test joint
Confirm test pressures with PTD
Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 9.5 ppg Baradrill-N fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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L-254 SB Injector
Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” directional BHA
Motor and Triple Combo
Ensure BHA components have been inspected previously.
Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Ensure MWD is RU and operational.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 5” 19.5# S-135 NC50.
Run a solid float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.2 TIH w/ 8-1/2” BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
12.0 ppg desired to cover shoe strength for expected ECDs. A 9.9 ppg FIT is the minimum
required to drill ahead
9.9 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP)
Email casing test and FIT digital data to AOGCC promptly upon completion of FIT. email: melvin.rixse@alaska.gov
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Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
15.8 8-1/2” hole section mud program summary:
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.
Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
Rheology: Keep viscosifier additions to an absolute minimum (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
Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
Dump and dilute as necessary to keep drilled solids to an absolute minimum.
MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total Solids MBT HPH
T
Hardness
Production 8.9-9.5 15-25 -ALAP 15 -30 4-6 <10%<8 <11.0 <100
System Formulation:
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
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
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Drilling Procedure
15.9 Install MPD RCD
15.10 Displace wellbore to 9.5 ppg Baradrill-N drilling fluid
15.11 Begin drilling 8-1/2” hole section, on-bottom staging technique:
Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
RPM: 120+
Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Monitor ECD, pump pressure & hookload trends for hole cleaning indication
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.
Reservior plan is to cross all lobes of the Schrader Bluff sand and TD beneath the OBD.
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.
Target ROP is as fast as we can clean the hole without having to backream connections
MPD will be utilized to monitor pressure build up on connections.
8-1/2” Hole Section A/C:
L-121: CF - .2, L-121 is a P&A’d OH section as the target was found to be wet
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.
Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
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.
Attempt to lowside in a fast drilling interval where the wellbore is headed up.
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.
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Drilling Procedure
Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 BROOH with the drilling assembly to the 9-5/8” casing shoe
Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
Rotate at maximum RPM that can be sustained.
Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
If backreaming operations are commenced, continue backreaming to the shoe
15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.19 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.20 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
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
If necessary, increase MW at shoe for any higher than expected pressure seen
Ensure fluid coming out of hole has passed a PST at the possum belly
15.21 POOH and LD BHA.
15.22 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
16.0 Run 4-1/2” Injection Liner
16.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner, the following well control response procedure will be followed:
P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” liner.
Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
Proceed with well kill operations.
16.2 R/U 4-1/2” liner running equipment.
Ensure 4-1/2” 12.6# W563 x NC50 crossover is on rig floor and M/U to FOSV.
Ensure all casing has been drifted on the deck prior to running.
Be sure to count the total # of joints on the deck before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 4-1/2” injection liner
Use Tenaris approved thread compound. Dope pin end only w/ paint brush. Wipe off
excess.
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Use lift nubbins and stabbing guides for the liner run.
If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
See data sheets on the next page for MU torque for the 4-1/2” liner connections.
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Drilling Procedure
16.4 Confirm with OE whether or not this is required. Ensure to run enough liner to provide for
setting the liner hanger at ~ 7200’ MD
Confirm set depth with completion engineer.
3-5 joints of 7” will be ran under the liner hanger for the production packer. Confirm with
completion engineer.
16.5 Ensure hanger/pkr will not be set in a 9-5/8” connection.
AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
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Drilling Procedure
16.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.5. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.6. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.7. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
Ensure 5” DP/HWDP has been drifted
Fill drill pipe on the fly Monitor FL and if filling is required due to losses/surging.
16.8. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.9. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.10. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.11. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.12. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.13. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.14. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
16.15. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
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Drilling Procedure
16.16. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.17. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.18. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.19. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.20. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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Drilling Procedure
17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
Ensure XO to DP made up to FOSV and ready on rig floor.
Rig up computer torque monitoring service.
String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 BTC tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, BTC
Confirm Torques with casing hand
=
17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs
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Drilling Procedure
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 4-1/2”, 12.6#, L-80 VAMTOP tubing.
Ensure wear bushing is pulled.
Ensure 4-1/2”, L-80, 13.5#, VAMTOP x XT-39 crossover is on rig floor and M/U to FOSV.
Ensure all tubing has been drifted in the pipe shed prior to running.
Be sure to count the total # of joints in the pipe shed before running.
Keep hole covered while RU casing tools.
Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
Monitor displacement from wellbore while RIH.
18.2 PU, MU and RH with the following 4-1/2” GL completion jewelry (tally to be provided by
Operations Engineer):
Torque Turn All Connections
Tubing Jewelry to include:
1x ‘X’ Nipple
1x SSD
1x Production Packer
1x X Nipple
1x WLEG
XXX joints, 4-1/2”, 12.6#, L-80, VAMTOP
18.3 PU and MU the 4-1/2” tubing hanger.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited KCL follow by ~150 bbls of diesel freeze
protect for both tubing and IA to 2,500’ TVD.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
* Approved to set packer greater than 200' above perforation but not higher than the reservoir confining zone -mgr
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Drilling Procedure
18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. CTU
a. Pull ball and rod in 4-1/2” production packer
* Approved for 30 days of production before POI.
* After 7 days of stabilized injection, 24 hour notice to AOGCC for opportunity to witness MIT-IA.
24 hour notice to AOGCC for opportunity to witness MIT-IA to 3500 psi. - mgr
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Drilling Procedure
19.0 Innovation Rig Diverter Schematic
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Drilling Procedure
20.0 Innovation Rig BOP Schematic
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Drilling Procedure
21.0 Wellhead Schematic
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Drilling Procedure
22.0 Days Vs Depth
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Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
1,563.5
1,701.5
2,051.5
2,495.5
2,786.5 Possible Heavy Oil in Ugnu 4A: ~ 3820' - 3950' MD
3,116.5
3,696.5 Possible Heavy Oil Lower Ugnu: ~5310' - 5950' MD
3,890.5
4,121.5
4,259.5
4,402.5
4,508.5
4,413.5
EASTING Est.
Pressure GradientEXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING
L-254 wp04ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY
Depths provided are TVD, not MD.
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Drilling Procedure
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Drilling Procedure
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have been seen on PBU L Pad. They were reported between 1660’ and 2740’ TVD. MW
has been chosen based upon successful trouble free penetrations of offset wells.
PBU L-206 (2021) saw gas hydrates from the base of permafrost to top of Ugnu 4, with the
highest levels in the SV3 & 2.
o Keep mud temperature as cool as possible, Target 60-70*F
o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
o Drill through hydrate sands and quickly as possible, do not backream.
o Reduce flowrate as needed to help control hydrates in the mud column.
Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not
prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been
disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible
while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone.
Excessive circulation will accelerate formation thawing which can increase the amount of hydrates
released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with
both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud
cut weight. Isolate/dump contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
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Drilling Procedure
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 50
Prudhoe Bay West
L-254 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.
Well Specific AC:
L-121: CF - .2, L-121 is a P&A’d OH section as the target was found to be wetL-121: CF - .2, L-121 is a P&A’d OH section as the target was found to be wet
Page 51
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
25.0 Innovation Rig Layout
Page 52
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 53
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
28.0 Casing Design
Page 55
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 56
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Prudhoe Bay West
L-254 SB Injector
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
X
Prudhoe Bay
X
223-030
Schrader Bluff Undefined Oil
PBU L-254
X
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT L-254Initial Class/TypeSER / WAGINGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230300PRUDHOE BAY, SCHR BLUF UND OIL - 640190NA1 Permit fee attachedYes2 Lease number appropriateYes Surf Loc & Top Prod Int lie in ADL0028239; Top Prod Int & TD lie within ADL0028241.3 Unique well name and numberNo Well targeting Prudhoe Bay, Schrader Bluff Undefined Oil Pool4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNo Pending application to expand the pool and AIO to include this well's location.14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes PBU L-121 (203-013)15 All wells within 1/4 mile area of review identified (For service well only)Yes 30 days per Joe Lastufka, see email 5/1/202316 Pre-produced injector: duration of pre-production less than 3 months (For service well only)No17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 105'18 Conductor string providedYes 9-5/8" L-80 casing fully cemented from surface to horizontal in the reservoir19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes 9-5/8" 47# L-80 from surface to BOPF. 9-5/8" 40# L-80 from BOPF to SB reservoir23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies only one close approach to an abandoned L-121 within the reservoir26 Adequate wellbore separation proposedYes 16" diverter below full BOPE27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 13-5/8" - 1 annular, 3 ram, 2 flow cross29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)No32 Work will occur without operation shutdownYes Monitoring will be required33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required, L pad is known H2S pad.35 Permit can be issued w/o hydrogen sulfide measuresYes Gas hydrates are present at L pad, see pages 19, 51, and 53. Wellbore breathing and instability also possible,36 Data presented on potential overpressure zonesNA see pages 36 and 52. Barite and CaCO3 onsite to weight up, LCM material also present.37 Seismic analysis of shallow gas zonesNA Conditions of Approval added that injection may not commence until AIO is expanded.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprMDGDate5/1/2023ApprMGRDate5/7/2023ApprMDGDate5/1/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 05/11/23JLC 5/11/2023
