Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
02/09/2024
Mr. Mel Rixse
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor
through 02/09/2024.
Dear Mr. Rixse,
Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off
with cement, corrosion inhibitor in the surface casing by conductor annulus through 02/09/2024.
Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement
fallback during the primary surface casing by conductor cement job. The remaining void space
between the top of the cement and the top of the conductor is filled with a heavier than water
corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached
spreadsheets include the well names, API and PTD numbers, treatment dates and volumes.
As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that
the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations.
If you have any additional questions, please contact me at 564-4891 or
oliver.sternicki@hilcorp.com.
Sincerely,
Oliver Sternicki
Well Integrity Supervisor
Hilcorp North Slope, LLC
Digitally signed by Oliver Sternicki
DN: cn=Oliver Sternicki, c=US,
o=Hilcorp North Slope LLC,
ou=PBU,
email=oliver.sternicki@hilcorp.com
Date: 2024.02.09 11:15:58 -09'00'
Oliver
Sternicki
Hilcorp North Slope LLC.
Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor
Top-off
Report of Sundry Operations (10-404)
02/09/2024
Well Name PTD #API #
Initial top
of cement
(ft)
Vol. of
cement
pumped
(gal)
Final top
of cement
(ft)
Cement top
off date
Corrosion
inhibitor
(gal)
Corrosion
inhibitor/ sealant
date
L-293 223020 500292374900 30 8/29/2023
S-09A 214097 500292077101 2 9/19/2023
S-102A 223058 500292297201 2 9/19/2023
S-105A 219032 500292297701 10 9/19/2023
S-109 202245 500292313500 7 9/19/2023
S-110B 213198 500292303002 35 9/19/2023
S-113B 202143 500292309402 10 9/19/2023
S-115 202230 500292313000 4 9/19/2023
S-116A 213139 500292318301 4 9/19/2023
S-117 203012 500292313700 3 9/19/2023
S-118 203200 500292318800 9 9/19/2023
S-122 205081 500292326500 5 9/19/2023
S-125 207083 500292336100 2 9/19/2023
S-126 207097 500292336300 3 9/19/2023
S-134 209083 500292341300 35 9/19/2023
S-200A 217125 500292284601 7 9/19/2023
S-202 219120 500292364700 13 9/19/2023
S-210 219057 500292363000 10 9/19/2023
S-213A 204213 500292299301 4 9/19/2023
S-215 202154 500292310700 3 9/19/2023
S-216 200197 500292298900 4 9/19/2023
S-41A 210101 500292264501 3 9/19/2023
W-16A 203100 500292204501 2 9/23/2023
W-17A 205122 500292185601 3 9/23/2023
L-293 223020 500292374900 30 8/29/2023
Well
Name PTD # API #
Initial top
of
cement
(ft)
Vol. of
cement
pumped
(gal)
Final top
of
cement
(ft)
Cement
top off date
Corrosion
inhibitor
(gal)
Corrosion
inhibitor/
sealant date
W-19B 210065 500292200602 8 9/23/2023
W-21A 201111 500292192901 8 9/23/2023
W-32A 202209 500292197001 4 9/23/2023
W-201 201051 500292300700 44 9/23/2023
W-202 210133 500292343400 6 9/23/2023
W-204 206158 500292333300 3 9/23/2023
W-205 203116 500292316500 3 9/23/2023
W-207 203049 500292314500 3 9/23/2023
W-211 202075 500292308000 8 9/23/2023
W-213 207051 500292335400 3 9/23/2023
W-214 207142 500292337300 10 9/23/2023
W-215 203131 500292317200 2 9/23/2023
W-223 211006 500292344000 7 9/23/2023
Z-69 212076 500292347100 2.0 27 1.5 10/24/2023
S-128 210159 500292343600 11 12/27/2023
S-135 213202 500292350800 16 12/27/2023
V-113 202216 500292312500 24 12/31/2023
V-114A 203185 500292317801 5 12/31/2023
V-122 206147 500292332800 5 12/31/2023
V-205 206180 500292333800 2 12/31/2023
V-207 208066 500292339000 8 12/31/2023
V-214 205134 500292327500 5 12/31/2023
V-215 207041 500292335100 2 12/31/2023
V-218 207040 500292335000 5 12/31/2023
V-224 208154 500292340000 16 12/31/2023
V-225 209118 500292341900 6 12/31/2023
V-01 204090 500292321000 3 1/1/2024
V-02 204077 500292320900 5 1/1/2024
V-04 206134 500292332200 5 1/1/2024
V-102 202033 500292307000 8 1/1/2024
V-104 202142 500292310300 5 1/1/2024
V-220 208020 500292338300 4 1/1/2024
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, July 27, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Guy Cook
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
L-293
PRUDHOE BAY UN ORIN L-293
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 07/27/2023
L-293
50-029-23749-00-00
223-020-0
G
SPT
4023
2230200 1500
1645 1645 1641 1640
552 701 677 670
INITAL P
Guy Cook
6/11/2023
Testing was completed with a Little Red Services pump truck and calibrated gauges.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PRUDHOE BAY UN ORIN L-293
Inspection Date:
Tubing
OA
Packer Depth
1107 2426 2375 2367IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitGDC230610153000
BBL Pumped:1.2 BBL Returned:1.1
Thursday, July 27, 2023 Page 1 of 1
1
Regg, James B (OGC)
From:Brooks, Phoebe L (OGC)
Sent:Wednesday, May 24, 2023 1:48 PM
To:Regg, James B (OGC)
Subject:FW: Hilcorp (PBU) April 2023 MIT L-293 Revision
Attachments:MIT PBU L-293 04-29-23.xlsx
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907‐793‐1242
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the
mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Ryan Holt <Ryan.Holt@hilcorp.com>
Sent: Tuesday, May 2, 2023 7:01 AM
To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Subject: Hilcorp (PBU) April 2023 MIT L‐293 Revision
Ms. Brooks,
Please see attached revision for L‐293. The previous file was missing some data for the rig MIT’s.
Thanks,
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659‐5102
M: (907) 232‐1005
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
You don't often get email from ryan.holt@hilcorp.com. Learn why this is important
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
PBU L-293PTD 2230200
REVISED
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230200 Type Inj N Tubing 0 3650 3530 3502 Type Test P
Packer TVD 4020 BBL Pump 2.2 IA 0 400 400 400 Interval O
Test psi 1500 BBL Return 2.2 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230200 Type Inj N Tubing 2000 2700 2700 2700 Type Test P
Packer TVD 4020 BBL Pump 3.2 IA 0 3607 3563 3550 Interval O
Test psi 1500 BBL Return 3.2 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp North Slope LLC
Prudhoe Bay / PBU / L pad
Shane Barber
04/29/23
Notes:Rig MIT-T Waived by Guy Cook
Notes:
Notes:
Notes:
L-293
L-293
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Rig MIT-IA Waived by Guy Cook
Notes:
Notes:
Form 10-426 (Revised 01/2017)2023-0429_MIT_PBU_L-293_2tests
jbr
PRUDHOE BAY FIELD /
SCHRADER BLUFF OIL POOL, ORION DEV AREA
By James Brooks at 9:30 am, May 17, 2023
Completed
4/29/23
JSB
RBDMS JSB 051823
GMGR08AUG2023DSR-6/12/23
5.16.2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.05.16 15:32:29 -08'00'
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-293 Date:3/30/2023
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Montague / Barber
Csg Setting Depth:6445 TMD 2687 TVD
Mud Weight:9.3 ppg LOT / FIT Press =307 psi
LOT / FIT =11.50 ppg Hole Depth =6467 md
Fluid Pumped=0.8 Bbls Volume Back =0.5 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->260 ->8250
->494 ->16 535
->6 140 ->24 815
->8 180 ->32 1110
->10 225 ->40 1411
->12 264 ->48 1725
->14 307 ->56 2064
-> ->64 2330
-> ->68 2585
-> ->
-> ->
-> ->
-> ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 307 ->0 2585
->1 284 ->1 2582
->2 277 ->2 2582
->3 271 ->3 2579
->4 267 ->4 2573
->5 264 ->5 2569
->6 260 ->10 2560
->7 258 ->15 2559
->8 255 ->20 2557
->9 252 ->25 2556
->10 250 ->30 2564
-> ->
-> ->
-> ->
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6 8
10 12
14
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8
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32
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48
56
64
68
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LOT / FIT DATA CASING TEST DATA
307284277271267264260258255252250
258525822582257925732569 2560 2559 2557 2556 2564
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LOT / FIT DATA CASING TEST DATA
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU L-293 Date:4/9/2023
Mud Weight:9.4 ppg LOT / FIT Press =560 psi
LOT / FIT =12.05 ppg Hole Depth =12400 md
Fluid Pumped=0.8 Bbls Volume Back =0.5 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->025 ->00
->2 115 ->273
->4 211 ->4113
->6 281 ->6162
->8 360 ->8220
->10 450 ->10 279
->12 518 ->12 343
->13 560 ->14 406
-> ->50 1742
-> ->55 1959
-> ->60 2167
-> ->65 2380
-> ->70 2600
-> ->73 2740
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 560 ->0 2741
->1 505 ->1 2741
->2 493 ->2 2741
->3 481 ->3 2741
->4 476 ->4 2739
->5 471 ->5 2739
->6 468 ->10 2735
->7 463 ->15 2731
->8 460 ->20 2731
->9 458 ->25 2729
->10 455 ->30 2727
-> ->
-> ->
-> ->
Csg Size/Wt/Grade: 7" 26/29 # L-80 Supervisor: Lott/Montague
Csg Setting Depth: 12,369 TMD 4062 TVD
0
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4
6
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1213
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6
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50
55
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73
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LOT / FIT DATA CASING TEST DATA
560
505493481476471468463460458455
274127412741274127392739 2735 2731 2731 2729 2727
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LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
3/18/2023 PJSM Spot Sub over L-293. Shim, level and disconnect tow bar. Spot cattle chute and shim/level. Lay rig matts for Mods. Spot and set pipe shed and mud mod.
Begin spotting Gen Mod. SIMOPS set out riggers on sub. Install skirt around sub stompers. Set sub stompers down W/ 500 psi. PJSM Cont spotting Gen Mod. Set
down and unhook truck. Remove jeep and release Cruz at 00:30. PJSM Spot break shack and enviro vac. Plug in gen mod. Safe out walkways and stairs. Assist
electrician plugging in rig. Went on Gen power at 02:30. Lay Herculite, spot cutting box and berm. Turn on steam, H2O around rig. Prep for scoping up derrick.
PJSM Perform derrick inspection before scoping up derrick. Scope up derrick, engage dogs and set down upper section. Lower blocks and bridle down.
3/19/2023 Continue working on Rig Acceptance Check list. C/O Jerk Line cable on ODS Cobra head. Install 4" conductor valves. Install Slip Loc Grub Screws. Lower Coffin
Door on TD and inspect J-Box and wiring. Mechanic Tighten Hyd Hoses and Inspect Hyd components. Update Well Sign.C/O Drag chain S[rockets. N/U Diverter
System: Hook Up Bridge Cranes and remove cross chains f/ BOPE. Land/N/U Stack on Diverter Tee. Install Bell Nipple. Install Knife valve and Vent line sections
between catwalk. Continue change out sprockets on drag chain. Assemble Mud Pump Fluid Ends. Install Pop Offs. Cont. N/U Diverter vent line Sections between
Sub and Catwalk. Tighten Set Screws in speed head. Install Trio Nipple. Clean and organize tool and equipment. SIMOPS: Put new paddles, main Gear shaft and
Bearings on Drag chain. Working acceptance check list. Continue working acceptance Check List.Continue working on Drag Chain. Clean and Inspect TD. Install
new rubber gaskets on MP #2 Suction screen pot. Install Mouse hole. Check N2 PSi on Koomey Bottles.Lock Out and chain Mezz Kill Valve. Inspect flow line and
air valves. Clear rig floor of Misc XO's. Grease IBOP. Obtain RKB's Bag 11.59', Knife valve 22.79', GL 26.58. Crane for Diverter Vent Lines arrived at 16:30 and left
at 18:00. Rig accepted at 18:00. PJSM Perform diverter test. Annular closure 17 sec, knife 5 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 2,915 PSI, after System 2,050 PSI, 200 PSI increase 17 Sec, full charge 49 sec. Nitrogen
6 bottle average. 2,308 PSI. Witnessed waived by AOGCC Sully Sullivan. PJSM P/U M/U 5" 19.5# S-135 NC50 D.P. from pipe shed and rack back in derrick 50
stands (100jnts) OD drift 3.125". Bring on 8.8 ppg Spud Mud to pits. PJSM Cont P/U M/U 5" 19.5# S-135 NC50 D.P. from pipe shed and rack back in derrick 45
stands (90jnts) Total 190 jnts. OD drift 3.125". P/U M/U 9 stands 5" HWDP 50.4# S-135 and SLB Hydra Jar. Drift OD 2.75". PJSM Open annular. Pull & L/D Mouse
Hole. Stage BHA. Function test mud pumps through bleeder. PJSM BHA. Hold Pre Spud meeting. Discuss rig evacuation, Muster Area's, H2S, Man Down,
Broaching, Gas Hydrates, keep mud cool, packing off down hole and drag chain. Roles and responsibility. P/U M/U 12.25 K5M633 Hybrid (3X13 3X14 Jets) TFA
0.8399 Bit, 8 1.5 TerraForce 4/5-5.3 stg Motor, X/O & 5" HWDP. PJSM Flood surface lines W/ 8.8 ppg Spud mud. Test surface lines to 250/ 3,000 psi, good. Wash
down 140 gpm 25 psi tag 3k at 108' MD. Drill ahead to 158' MD 350 gpm 330 psi 30 rpm Trq 1.5k. P/U 43k SLK 44k. Daily Disposal to G&I 0 bbls, total 0 bbls.
Daily Disposal to MP G&I 0 bbls, total 0 bbls. Daily water from Lake 2 810 bbls, total 810 bbls. Daily metal recovered 0 lbs, total 0 lbs. Daily surface losses 0 bbls,
total 0 bbls.
3/20/2023 PJSM Drill 12.25" Surface F/ 158' to 220' MD 350 gpm 300 psi 30 rpm Trq 1.5k. P/U 44k SLK 44k While drilling lost 71 bbls but slowed to no losses. PJSM CBU
BROOH 1 stand F/ 220' to 158' MD. Cont POOH on elevators F/ 158' to surface. Inspect bit, good. Pump through bleeder clearing flow line. Replaced swab on MP
#1 Pod #4. PJSM Stage BHA components. RIH Mud Motor and M/U 8" GWD, 8" DM, 8" EWR-M5 and TM collar. RFO DM to GWD 20.9* and DM to Motor 147.88*.
Download MWD. RIH 2 ea NM FC & X/O total 162' MD. Perform shallow pulse test of MWD, good. Wash down W/ 5" HWDP F/ 162' to 220' MD. 350 gpm 640 psi
30 rpm Trq 1k. P/U 56k SLK 53k ROT 54k. Slide/ Rot 12.25" Surface Hole F/ 220' to 471' MD (471' TVD) Total 247' (AROP 35.3) 400 GPM, On 810 psi Off 175 psi
30 RPM, TRQ on 1-1.5k, TRQ off 1k, F/O 62%, WOB 4-10k. ECD 10. Max Gas 0u. P/U 63K, SLK 57K, ROT 58K. Jet flowline. KOP 250' MD. Cont build 3/100 as
per plan. PJSM While making up to TD observed multiple faults trying to Trq connection. Decision was made to rack it back and inspect saver sub. Derrick man
noticed a piece of plastic, upon further investigation appears a thread protector was left in pipe. Decision made to POOH without pumps and check for. debris on top
of TM Collar. Blow down TD. POOH on elevators F/ 471 to 345 MD. Had 15k over pull, worked through tight spot W/ no pumps 5 rpm Trq 1.4-2k W/ stall set at 15k.
Worked string/ 5-15k over pull with minimal stalls. Cont pulling on elevators F/ 342 to 261 MD. At 261 had over pull 15-20. Started rotary at 5 rpm Trq 5k W/ 15k
stall pulling up to 20k only gaining 2. Checked BHA and appears NM FC jnt was at base of conductor. Increased rotary to 10 rpm Trq 7-7.5k stall set a 10k and
continued working string up to 20k and working down W/ 15-20k to get travel multiple times. At 258. (5 Tight area) was able to continue POOH on elevators W/O
issue. P/U 63k SLK 57k ROT 55k. At the TM collar MWD pulled the spring stack and spacers with no debris. Checked on top of pop it and no debris. No swabbing
or losses. PJSM Drifted NM FC F/ Derrick W/ 2.75 OD F/ 97 to 159 MD. Attempted to drift (2.75" OD) the 1st stand of 5 HWDP and drift was stuck. Made several
attempts to free drift with ringing pipe, steam from bottom, ringing pipe from top to bottom and using vac system without success. Had to break down the stand and
L/D jnt to pipe shed. It appears the mud inside the pipe was frozen not allowing the drift to fall out. Was able to steam and free drift from HWDP in Pipe Shed.
Staged the lower jnt in short mouse hole and run down 1 steam whip to thaw pipe. Set jnt on skate and drop drift through pipe, good. Made up single jnt to string
and perform shallow pulse test at 162 MD 350 gpm 500 psi without issue. Decision was made to L/D stand 6 W/ thread protector and thaw out Jar stand, drift and
rack back in Derrick. P/U 2 extra 5 Jnts to replace stand 6 and rack back in derrick. Checked stands 2 & 3 for frozen mud and had to lay them down. We had to
steam and drift 1 jnt on stand 5 and lay down the. other joint. Picked up/ drifted new 5 HWDP and singled them into hole. Wash down F/ 409 to 471' MD tagging fill
at 452 MD. 125-300 gpm 200-500 psi 5-15 rpm Trq 700 ft/lb to 2k. WOB 102k P/U 63k SLK 56k. Distance to WP03: 2.3', 2.02' High 1.24' Low. Daily Disposal to
G&I 228 bbls, total 228 bbls. Daily Disposal to MP G&I 0 bbls, total 0 bbls. Daily water from Lake 2 280 bbls, total 1090 bbls. Daily surface losses 71 bbls, total 71
bbls. Daily metal recovered 0 lbs, total 0 lbs.
3/21/2023 Drill 12.25" surface hole F/ 471' - T/ 943' MD / 925' TVD (472' total, 79 fph AROP). 400 gpm, 1130 psi on, 940 psi off, 30 rpm, 3k Tq on, 1.3k Tq off, 60% F/O, 8k
WOB. 9.79 ECD w/ 9.1 MW. P/U 77k, S/O 72k, Rot 74k. Continue jet flowline as needed. No losses noted. Clean MWD survey @ 730' MD. Obtained 4x clean
MWD survey then mode switch GWD off. Drill 12.25" surface hole F/ 943' - T/ 1382' MD / 1270' TVD (439' total, 73 fph AROP). 425 gpm, 1360 psi on, 1205 psi off,
40 rpm, 3.4k Tq on, 2k Tq off, 56% F/O, 7-12k WOB. 10.1 ECD w/ 9.1 MW. P/U 78k, S/O 72k, Rot 75k. Continue jet flowline as needed. No losses. Start 4.5/100
build/turn @ 550'. Slide/ Rot 12.25" Surface Hole F/ 1,382' to 1,860' MD (1,543' TVD) Total 478' (AROP 80') 425 GPM, On 1425 psi Off 1235 psi 30 RPM, TRQ on
5k, TRQ off 2-3k, F/O 62%, WOB 8-12k. ECD 10.5. Max Gas 0u. MW in/out 9.1/ P/U 82K, SLK 75K, ROT 77K. Jet flowline.
End & start build/turn 4.5*/100 as per plan. PJSM Found weep hole on MP #2 leaking. C/O Swab, liner and wear plate on Pod #4. Rack back one stand. Rot/ Rec F/
1,857' to 1,799' MD 250 gpm 485 psi 25 rpm Trq 3k. Slide/ Rot 12.25" Surface Hole F/ 1,860' to 2,180' MD (1,646' TVD) Total 320' (AROP 71') 450 GPM, On 1620
psi Off 1580 psi 50 RPM, TRQ on 5.5k, TRQ off 3-4k, F/O 63%, WOB 5-8k. ECD 10.68. Max Gas 38u. MW in/out 9.5/9.6 P/U 80K, SLK 63K, ROT 72K. Jet
flowline. Cont 4.5*/100 as per plan. Increased MW to 9.5 ppg prior to BPF. Distance to WP03: 22.30', 20.1' Low 9.7' Left. Daily Disposal to G&I 570 bbls, total 798
bbls. Daily Disposal to MP G&I 347 bbls, total 347 bbls. Daily water from Lake 2 810 bbls, total 1900 bbls. Daily surface losses 0 bbls, total 71 bbls. Daily metal
recovered 0 lbs, total 0 lbs.
50-029-23749-00-00API #:
Well Name:
Field:
County/State:
PBW L-293
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
3/19/2023Spud Date:
3/22/2023 Slide/ Rot 12.25" Surface Hole F/ 2,180' to 2,624' MD (1,755' TVD) Total 444' (AROP 74') 400 GPM, On 1230 psi Off 1200 psi 50 RPM, TRQ on 7k, TRQ off 4-6k,
F/O 60%, WOB 2-4k. ECD 10.36. Max Gas 103u. MW in/out 9.5 P/U 85K, SLK 61K, ROT 69K. Jet flowline. No losses. End 4.5*/100 Build/turn at 2,051' MD.
Perform maintenance slides for tangent, 75.12 inc 311.13 Azi. Base Permafrost logged at 2524' MD / 1746' TVD. Significant hydrates seen starting @ 2697' MD
(SV1 formation). Slide/ Rot 12.25" Surface Hole F/ 2,624' to 3.285' MD (1,923' TVD) Total 661' (AROP 110') 450 GPM, On 1650 psi Off 1470 psi 50 RPM, TRQ on
7k, TRQ off 6k, F/O 63%, WOB 4-12k. ECD 10.25. Max Gas 2805u. MW in/out 9.6 P/U 89K, SLK 57K, ROT 71K. Jet flowline.
Slides as needed for tangent. No losses. Slide/ Rot 12.25" Surface Hole F/ 3,285' to 3,894' MD (2,057' TVD) Total 609' (AROP 101.5') 450 GPM, On 1690 psi Off
1485 psi 50 RPM, TRQ on 7.5k, TRQ off 6.5k, F/O 62%, WOB 4-12k. ECD 10.75. Max Gas 3085u BGG 2000u MW in/out 9.6 P/U 88K, SLK 57K, ROT 70K. Jet
flowline. Slides as needed. No losses. Hydrates subsiding around 3,468' MD. Pump test gas trap and appears no hydrates breaking out at surface.
At 3,825' MD observed gas hydrates breaking out at surface, reduced flow rate 375 gpm and control drill 200 fpm. Slide/ Rot 12.25" Surface Hole F/ 3,894' to 4,468'
MD (2,205' TVD) Total 574' (AROP 95.7') 450 GPM, On 1770 psi Off 1630 psi 50 RPM, TRQ on 8-9k, TRQ off 7-9k, F/O 62%, WOB 8-12k. ECD 10.75. Max Gas
3936u BGG 996u MW in/out 9.6/9.8 P/U 98K, SLK 58K, ROT 77K. Jet flowline. Slides as needed.No losses. Drilling ahead W/ reduced ROP to 150 fpm and 375
gpm 1220 psi due gas breaking out F/ 3,894' to 4,021' MD. Gas falling off and surface break out calming down. Drill ahead with normal parameters. Distance to
WP03: 25.16', 1.2' Low 25' Right. Daily Disposal to G&I 1037 bbls, total 1835 bbls. Daily Disposal to MP G&I 114 bbls, total 461 bbls. Daily water from Lake 2 1260
bbls, total 3160 bbls. Daily surface losses 0 bbls, total 71 bbls. Daily metal recovered 0 lbs, total 0 lbs.
3/23/2023 Slide/ Rot 12.25" Surface Hole F/ 4468' - T/ 4944' MD (2306' TVD) Total 476' (AROP 79') 425 GPM, 1480 psi on, 1400 psi off, 50 RPM, 10k Tq on, 8-10k Tq off,
F/O 58%, WOB 3-6k. ECD 10.9. Max Gas 4485u, BGG 1220u MW in/out 9.5/9.7, P/U 109K, S/O 54K, ROT 80K. Jet flowline. Slides as needed. No losses. Slide/
Rot 12.25" Surface Hole F/ 4944' - T/ 5697' MD (2493' TVD) Total 753' (AROP 126') 400 GPM, 1675 psi on, 1455 psi off, 50 RPM, 13.5k Tq on, 11k Tq off, F/O
54%, WOB 8-12k. ECD 10.4. Max Gas 4101u, BGG 1200u MW in/out 9.5/9.7, P/U 120K, S/O 41K, ROT 83K. Jet flowline. Slide/ Rot 12.25" Surface Hole F/ 5,697'
to 6,244' MD (2,634' TVD) Total 547' (AROP 91.2') 450 GPM, 2075 psi on, 1910 psi off, 50 RPM, 15k Tq on, 12-13k Tq off, F/O 55%, WOB 8-12k. ECD 10.9. Max
Gas 4147u, BGG 2500u MW in/out 9.55/9.75, P/U 121K, S/O 42K, ROT 81K. Jet. Slide as needed. No losses. Slide/ Rot 12.25" Surface Hole F/ 6,244' to Csg TD
6,447' MD (2,685' TVD) Total 203' (AROP 101') 450 GPM, 2050 psi on, 1750 psi off, 50 RPM, 14-16k Tq on, 11.5k Tq off, F/O 58%, WOB 6-14k. ECD 10.78. Max
Gas 4122u, BGG 2500u MW in/out 9.6/9.8, P/U 132K, S/O 42K, ROT 85K. Jet flow line. Obtain final survey 6,394.17' MD 2,671.22' TVD 75.1 deg inc 310.02 deg
azi. Moderate Gas Hydrates breaking out at TD. No flow. PJSM Perform clean cycle. BROOH F/ 6,447' to 6,375' MD. Circ 0.5 BU per stand for 3 stands. Rot/Rec F/
6,184' to 6,121' Pump 35 bbl 9.6 ppg 300+ Vis Nut Plug Sweep 450 gpm 1650 psi 50 rpm Trq 12-14k ECD 10.18 F/O 59% Max Gas 3,338u BGG 1500u. P/U
130k SLK 44k ROT 89k. Distance to WP03: 30.6', 28.2' High 11.95' Left. Daily Disposal to G&I 285 bbls, total 2120 bbls. Daily Disposal to MP G&I 1192 bbls, total
1653 bbls. Daily H2O from Lake 2 840 bbls, total 4000 bbls. Daily H2O from Lake LPad Lake: 700 bbls, total 700 bbls. Daily surface losses 0 bbls, total 71 bbls.
3/24/2023 Continue Circ/Condition 3x btms up (rot/recip) @ 6184' MD. Pump tandem sweep w/ no increase in cuttings. 450 gpm, 1590 psi, 54% flow, 50 rpm, 14.5k tq, 10.04
ECD. Max gas 633u. P/U 137k, S/O 40k, Rot 87k. Monitor well 20 min (no flow w/ minimal hydrates breaking out). Wash F/ 6184' to TD depth 6447' MD. BROOH
F/ 6447' - T/ 4750' MD. 450 gpm, 1500 psi, 10.2 ECD, 50 rpm, 11k tq, 55% flow. Max Gas 1903u P/U 120k, S/O 42k, Rot 80k. Pull speed 10-30 fpm as hole
allows. Slight tq spikes and packoffs,. BROOH F/ 4750' - T/ 2180' MD. 450 gpm, 1360 psi, 10.1 ECD, 50 rpm, 9.5k tq, 57% flow. Max Gas 3259u P/U 106k, S/O
44k, Rot 72k. Pull speed 10-30 fpm. Slight tq spikes and packoffs. F/ 2380' - T/ 2170' MD reduce pulling speed 10 fpm and obtain 3x btms up prior to pulling into
upper build section. BROOH F/ 2,180' to 721' MD. 450 gpm 800 psi 50 rpm Trq 7-10k ECD 10.1 F/O 57% Max Gas 652u. P/U 53k SLK 54k. ROT 60k. No losses.
Pull speed 10-30 fpm. Float not holding at 1,895' MD. At 1,365' MD hole unload heavy sand reduced to 425 gpm 40 rpm Trq 7-10k. Slight Trq spikes and packoffs.
PJSM At 721' MD monitor well for 10 min seepage loss ~3 bph. Cont BROOH W/ 5" HWDP F/ 721' to 345' MD. At 650' hole unloaded heavy sand reduced to 400
gpm 890 psi 20 rpm Trq 1.5-2k ECD 10.1 F/O 54% Pull speed 5-10 fpm. Pulled on elevators F/ 345' to 162' MD.P/U 53k SLK 54k. No losses. PJSM Blow down
TD. L/D X/O, 2 ea NM FC. Attempt to upload fast M5 ethernet, unsuccessful. Bring 67 ea solid body centralizers to rig floor. Cont L/D 8" TM, 8" EWR-M5, 8" DM, 8"
GWD, 8" 1.5 deg mud motor and 12.25" K5M633 bit. Bit grad PDC: 2-1-X-WT-1-BT-TD Cone: 2-1-WT-E-2-PN-TD. Was unable to read M-5 decision was made to
send to town for data collection. SIMOPS C/O wear plate, swap & liner on MP #1 Pod #1. PJSM R/U Parker Wellbore Csg Equip. R/U 9.625" (250T) side door
elevators. P/U M/U 360T Volant to TD. P/U M/U 14.75 STARR Power Tongs. Check all handling Equip. 160 jnts in Pipe shed and 10 outside. Monitor well on TT,
seepage loss 2.5 bph. PJSM P/U M/U 9.625" 40# L-80 TXP BTC Shoe track and blank jnt.(BakerLoc). Pumped through the bleeder to clear flow line of gravel.
Found flow line 1/2 full of gravel. Clean out flow line. Daily Disposal to G&I 798 bbls, total 2918 bbls. Daily Disposal to MP G&I 0 bbls, total 1653 bbls. Daily H2O
from Lake 2 1050 bbls, total 5050 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily surface losses 0 bbls, total 71 bbls.
3/25/2023 M/U FC (BakerLoc) fill pipe, drop ByPass Plug. Check floats, good. P/U M/U BFA (BakerLoc) Cont RIH W/ 9.625 40# L-80 TXP BTC F/ 168' to 1,928' MD. Install
centralizers as per tally. Fill every 5 top off 10 jnts. Trq TXP 20.9k. P/U 95k SLK 60k Calc 24 bbls actual 3 bbls lost 27 bbls. Speed 50-70 fpm. Cont RIH W/ 9.625
40# L-80 TXP BTC F/ 1,928' to 3,539' MD. At 2,202' MD lost down WT. Work down 3X. M/U Volant circ 3 bpm 120 psi 5 rpm (Trq stall 10k) wash through. At
2,265' MD circ string volume staging pumps up F/ 3-6 bpm 125 psi 5 rpm Trq 8k F/O 33%. Observed silt & sand at shakers cleaning up. at end of string volume.
P/U M/U ES Cementer (BakerLoc) at 3,459 MD. HES verify shear pins. Max Gas 95u. P/U 132k SLK 52k Fill every 5 top off 10 jnts. Trq TXP 20.9k Trq CDC BTC
19k. Run speed 50-70 fpm. Calc 23.6 bbls actual 1.2 bbls lost 22.4 bbls. Cont RIH W/ 9.625 47# L-80 CDC BTC F/ 3,539' to 4,428' MD. Work tight hole F/ 3,746'
to 3,751' & 4,156' MD 3 bpm 90-110 psi 5 rpm (Trq stall 14k) only getting rotation while moving. Working string Wt down to block WT (38k). Wash and ream down
F/ 3,751' MD 3 bpm 125 psi 5 rpm TRQ stall 14k P/U 200k. SLK 40k ROT 50k. L/D Jnt 117 bad box & 118 bad pin at 4,400' MD. Trq CDC BTC 19k. Max Gas
155u. Run speed 5-30 fpm. Calc 28k actual -8 lost 36 bbls. PJSM Cont wash & ream W/ 9.625 47# L-80 CDC BTC F/ 4,428' to 5,372' MD 3 bpm 115 psi 5 rpm
Trq stall set 14k only getting ROT while moving. F/ 4,520' to 4,601' MD Circ drill string volume staging pumps up to 6 bpm 135 psi 5 rpm F/O 28% max gas 155u.
No losses. At 4,560 MD L/D Jnts 124 & 125 bad box. and pin. P/U 200k SLK 45k ROT 55k. Trq CDC BTC 19k. Run speed 15-25 fpm. Calc 14k actual -2 lost 16
bbls. Daily Disposal to G&I 342 bbls, total 3260 bbls. Daily Disposal to MP G&I 0 bbls, total 1653 bbls. Daily H2O from Lake 2 350 bbls, total 5400 bbls. Daily H2O
from Lake LPad Lake: 0 bbls, total 700 bbls. Daily surface losses 77 bbls, total 148 bbls.
3/26/2023 PJSM Cont wash & ream W/ 9.625 47# L-80 CDC BTC F/ 5372' - T/6447' MD. 3 bpm, 125 psi, 5 rpm (rotation only while reciprocating), Trq limit set 16k ft/lbs. P/U
225k, S/O 42k (wts with rotary). Tag on depth @ 6447' w/ 7k set down 2x. Verify casing count (good). Stage pumps up to 6 bpm, 170 psi, 33% flow, 16k tq, 1-3 rpm
while reciprocating pipe. 5 bph dynamic losses. Circ 3x btms. R/D csg elevators and bail extensions. R/U HES cementers. Prep pits for upcoming 1st stage cement
job. B/O Volant and R/U cement line. M/U Volant and establish circulation 6 bpm, 320 psi, 1-3 rpm, 16k tq, 28% flow, Max gas 271u. P/U 220k, S/O 50k. PJSM,
Wet lines w/ 5 bbls H2O (HES) and P/T lines 1k / 4k psi high. Pump 1st stg cement job as follows: 60 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 ppb poly flake
(1st 10 bbls) 3 bpm 225 psi. Drop bypass plug. HES pump LEAD EconoCem Type I/II 12# cmt 186 bbls (445 sx), 4.1 bpm, 298 psi, 2.347 yld. TAIL HalCem Type
I/II15# cmt (Wet at 16:07) 82 bbls (400 sx), 1.152 yld, 2.1 bpm, 288 psi. Drop shutoff plug. HES Pump 20 bbls FW, 5 bpm, 225 psi. Rig disp w/ 224.1 bbls 9.5 ppg
spud mud, 6 bpm, ICP 200 psi, FCP 380 psi. HES pump 68.5 bbls 9.5 ppg spacer, 3 bpm, 224 psi. Rig displace w/ 101 bbls Spud mud, 6 bpm, 425 ICP, reduce
rate to 4 bpm, 619 FCP. Bumped @ 393.6 bbls, (Calc 391.4 bbls.) Hold 1020 psi (3 min). Bleed off psi, Check floats (good). Appeared to have aired up mud in sys-
tem when checking floats. Psi up, open stage tool 4 bpm, shift @ 3000 psi. CIP @ 18:30 hrs. Parked in tension 180k up. Lost 13 bbls during Displacement. CBU
(2,968 stks) x2 through Stage tool 6 BPM 360 psi F/O 27% at 0.5 BU saw Poly Flak at shakers. Dumped Spacer and clabbered up Mud at 2nd BU. Dumped 60
bbls Spacer, 284 bbls contaminated mud, estimated 56 bbls cement. (344 bbls Total dumped). Ramped pumps up to 8 bpm 570 psi F/O 31% every 0.5 BU. and
back to 6 bpm to attempt to clear out any channeling. CBU a total of 6X. Shut down. Drain stack. Disconnect knife valve and flushed stack 3X W/ Black Water cy-
cling Annular. Cont Circ at 6 bpm 300 psi F/O 26%. Cont Circ through ES at 6 bpm 300 psi F/O 26%. Increased to 8 bpm 520 psi for 5 min each BU with little
change in hole cleaning. Pump 30 bbl 9.6 ppg 250 vis sweep. Came back on time with 0% increase. Prep Pits for 2nd stage cement. Fill water tank and heat. PJSM
Disengage and reengage Volant to ensure working properly. Daily Disposal to G&I 456 bbls, total 3716 bbls. Daily Disposal to MP G&I 626 bbls, total 2279 bbls.
Daily H2O from Lake 2 770 bbls, total 6170 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily surface losses 44 bbls, total 192 bbls.
3/27/2023 PJSM, Pump 2nd stage cement job as follows. 56 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls) 4.2 bpm 215 psi. 414 bbls, 10.7#
Lead ArcticCem Type I/II (814 sxs), 2.855 yld, 3.9 bpm, 395 psi. 56 bbls 15.8# Tail HalCem class G cmt (270 sxs), 1.156 yld, 3.5 bpm, 585 psi. Drop closing plug.
HES 20 bbls H2O, 3.5 bpm, 478 psi. Rig disp w/ MP #1 200 bbls 9.5# spud mud (197.4 bbls calc), 6 bpm, 500 psi ICP, 847 psi FCP. Reduce rate 4 bpm last 10
bbls, 690 FCP. Bump 3223 stks. Psi up 2200 w/ 5 min hold. Observe stg tool shift close @ 1617 psi. Bleed off to static. CIP @ 07:31 hrs. No losses. Dumped 337
bbls total (60 bbls spacer / 277 bbls green cmt). B/D cmt line. Disconnect knife valve, Flush stack with black water while cycling annular 3x. N/D and lift stack. Set 9-
5/8" slips w/ 100k string wt. Set stack, Cut and L/D landing jt (30.32'). Finish flushing BOP, L/D mousehole. N/D and rack back same. N/D diverter line w/ crane.
PJSM R/D knife valve. Pull riser. Install RCD head. Clean Pits. Prep for welder to fix hole in flow box. C/O 4 stuffing boxes on MP#2. PJSM Vault dress 9.625" Csg
stump. Set well head and tubing spool. Trq slip lok. SIMOPS clean pits. Weld up hole in flow box.Cont C/O stuffing boxes on MP#2. PJSM INstall 13 5/8" X 11"
DSA and BOP. Welder released at 17:30. SIMOPS clean Pits and work on stuffing boxes on MP#2. PJSM Test wellhead 500 psi 5 min, 3,500 psi 10 min, good.
SIMOPS clean pits. PJSM Trq DSA and BOP. Install choke and kill lines. Install drip pan and secure stack. R/U MPD 4" hard lines. Remove RCD head lifting cap
and set test plug. PJSM Bleed down Koomey. Open ODS UPR doors. Clean and inspect cavities. On ODS remove 7" solid body and replace W/ 5" solid body rams.
Prep for BOP test. C/O bearing on drag chain. PJSM Open DS UPR doors. Clean and inspect cavities. On ODS remove 7" solid body and replace W/ 5" solid body
rams. Install RCD flow riser and M/U Clamp. PJSM M/U 4" dart. 4" TIW. ported sub and X/O to 4" test jnt. M/U test plug and set. R/U test lines. Flood stack and
found RCD clamp leaking, tighten. Cont flood and purge air from system. Attempted shell test and found kill line flange leaking, tighten. PJSM Attempted to perform
Annular test, fail. Trouble shoot and decision was made Annular needs changed. Cont W/ BOPE test while new Annular is brought to rig. Tested LPR (2.875" X 5.5"
VBR) & 4" Dart. 250 low, 3,000 psi high 5 min on chart. Witnessed waived by AOGCC rep Adam Earl. Daily Disposal to G&I 624 bbls, total 4340 bbls. Daily
Disposal to MP G&I 1180 bbls, total 3459 bbls. Daily H2O from Lake 2 610 bbls, total 6780 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily
surface losses 0 bbls, total 192 bbls.
3/28/2023 Cont. to test BOPE 250/3000 psi, AOGCC right to witness waived by Adam Earl. C/O 4" to 5" test joint. F on manual kill. Test gas alarms, PVT, and flow paddle.
Cont. testing BOPE 250/3000 psi on 5" test joint. F/P on choke HCR, grease and function - good. Cont. testing BOPE 250/3000 psi. R/D 5" test joint. Test blinds,
CMV 1, 2, 3 - trouble shoot test: reflood and purge lines, C/O leaking test manifold isolation valve, grease choke valves, Double block valves and find CMV 2
leaking. Test Blinds, CMV 1, 3 - good. Rebuild man kill and CMV 2. Shut blinds. Bleed off accumulator. R/D MPD hardline, mull master bushing. Break RCD clamp.
Pull riser. Clean flow box, RCD and annular. Install MPD test cap. Remove elevators and install slings. Pull RCD and set on BOPE pedestal. Connect slings to
bonnet. Break bolts, pull bonnet and set down. Rig up to pull annular element.
3/29/2023 Install new annular element, coat with hydraulic oil. Install annular cap. Install test joint and follow break in procedure. Fill stack and flood lines. Cont. testing BOPE
with 4" TJ 250/3000 psi: annular, CMV2, HCR choke, HCR Kill. Accumulator drawdown: initial pressure 3000 psi,. Fill stack and flood lines. Cont. testing BOPE
with 4" TJ 250/3000 psi: annular, CMV2, HCR choke, HCR Kill. Accumulator drawdown: initial pressure 3000 psi, after functioning 1650 psi, 200 psi recharge in 21
sec, full recover 74 secs. (6) N2 bottles at 2291 psi average. Install RCD on top of BOPE. Cont. installing MPD, install drip pan, MPD hardline, trip nipple. Install
wear bushing. Obtain RKB's. Bring BHA components to rig floor. M/U BHA: PDC bit to motor, IBS, DM collar, measure RFO, M/U ADR, ILS, DGR collar, PWD, TM.
Upload MWD. RIH with 2 flex collars, 17 jjnts HWDP and Jars to 718'. P/U 59K, S/O 64K. RIH from 718' to 2625' picking up and drifting (3.125") drill pipe. P/U
80K, S/O 50K. POOH racking back drill pipe from 2625' to 718'. Cont. to RIH with 8.5" drilling assembly picking up and drifting drill pipe from 718' to 2875'. P/U
84K, S/O 52K. Fill pipe, shallow pulse test MWD. Wash down from 2875' to ES cementer at 2963' at 400 gpm, 870 psi, 30 rpms, 7Kft-lbs. P/U 100K, S/O 56K,
ROTW 73K. Drill ES cementer from 2963' and washed down to 2974' at 400-450 gpm, 1100 psi, 30 rpms, 7-8Kft-lbs, WOB 4-12K. P/U 100, SO 56K, ROT 73K.
Reamed x 2 and tripped through without pumps/rotary - clean. Blow down top drive. Cont. to RIH picking up and drifting (3.125") drill pipe from 2974' to 3473'. Set
down at 3326' on junk. Wash and ream from 3326' at 400 gpm, 775 psi, 30 rpms, 7.5Kft-lbs. P/U 100K, S/O 51K, ROTW 71K.
3/30/2023 Continue single in w/ 8.5" mtr assy on 5" NC50, S-135 dp (drift 3.125") F/ 3326' - T/ 6307' MD. Washed and reamed down several times due to insufficient down
wt. 400 gpm, 860 psi, 10 rpm, 17k tq. Circulate btms up @ 6307' MD (rot/recip). 400 gpm, 860 psi, 10 rpm, 17k tq. P/U 162k, S/O blk wt. Contaminated mud @
btms up. Dump 40 bbls. 9.5 MW In/Out Spud mud. B/D TDS. R/U and test 9-5/8" 40/47# surface casing @ 6307' MD. Test csg 2500 psi w/ 30 min hold (test good).
Chart and record same. 4.5 bbls In / 4.3 bbls Out. R/D test equipment. Wash down F/ 6307' - T/ 6317' MD tagging BFL on depth. Drill Shoe track and hard cement
w/ 20' new formation F/ 6317' - T/ 6467' MD. 400 gpm, 1350 psi, 35 rpm, 15.5k tq, 2-5k WOB, 44% flow,. P/U 161k, S/O blk wt, Rot 86k. Tripped thru clean 2x.
Pump 35 bbls spacer then displace well over from 9.5 ppg spud mud to 9.3 ppg 6% KCL/Polymer w/ 1.5% lube. Displace @ 400 gpm, 1170 psi, 35 rpm, with final
tq @ 11.2k. P/U 144k, S/O 66k, Rot 83k. Dumped 50 bbls interface contaminated mud. Rig up and perform 11.5 EMW FIT. Pump .3/4 bbl In / 1/2 bbl out. Psi up to
307 psi. 10 min 250 psi. Chart and record same. Send FIT info to engineer. Bleed off and rig down test equipment. Cut and slip drilling line. Check brake
tolerances, calibrate drum. Check floor and crown saver. Perform crown and block wobble EAM. Service rig: check TD gear oil, grease RLA washpipe, IBOP,
spinners, roughneck, Top drive. Check rotary oil. Grease upper IBOP. Wash down from 6420' and continue drilling 8-1/2" hole from 6467' to 6635' (total 168',
AROP 67fph) at 425 gpm, 1325 psi, WOB 7-9K, 30 rpms, 11-13Kft-lbs, ECD 10.69ppg with 9.3ppg mud, max gas 127U. P/U 144K, S/O 60K, ROTW 86K.
Continue drilling 8-1/2" hole from 6635' to 7009' (total 374', AROP 62fph) at 450 gpm, 1555 psi, WOB 7-12K, 80 rpms, 12Kft-lbs, ECD 11.09ppg with 9.3ppg mud,
max gas 142U. P/U 125K, S/O 63K, ROTW 87K. Distance to WP3: 26', 12.4' high, 22' left.
3/31/2023 Continue drilling 8-1/2" hole from 7009' to 7520' (total 511', AROP 85fph) at 450 gpm, 1450 psi, WOB 3-5K, 80 rpms, 13.5Kft-lbs, ECD 10.58 ppg with 9.3 ppg
mud, max gas 82U. P/U 137K, S/O 67K, ROTW 89K. Backream full stands. Continue drilling 8-1/2" hole from 7520' to 8153' (total 633', AROP 106fph) at 450 gpm,
1573 psi, WOB 6-12K, 80 rpms, 13-5Kft-lbs, ECD 10.44 ppg with 9.0 ppg mud, max gas 186U. P/U 180K, S/O 50K, ROTW 91K. Backream full stands. Continue
drilling 8-1/2" hole from 8153' to 8786' (total 633', AROP 106fph) at 450 gpm, 1573 psi, WOB 6-15K, 80 rpms, 13-5Kft-lbs, ECD 10.67 ppg with 9.0 ppg mud, max
gas 201U. P/U 186K, S/O NA, ROTW 94K. Backream full stands. Continue drilling 8-1/2" hole from 8786' to 9324' (total 538', AROP 90 fph) at 450 gpm, 1560 psi,
WOB 1-5K, 80 rpms, 17Kft-lbs, ECD 10.76 ppg with 9.15 ppg mud, max gas 167U. P/U 177K, S/O 52K, ROTW 97K. Backream full stands. Increased lube
concentrations by 0.25% to mitigate stick slip. Distance to WP3: 10', 1.2' low, 9.9' right.
4/1/2023 Continue drilling 8-1/2" hole from 9324' to 9836' (total 512', AROP 85 fph) at 450 gpm, 1790 psi, WOB 9-13K, 80 rpms, 17-19Kft-lbs, ECD 11.02 ppg with 9.2 ppg
mud, max gas 57U. P/U 172K, S/O 52K, ROTW 97K. Backream full stands. Slide as necessary through tangent. Continue drilling 8-1/2" hole from 9836' to 10246'
(total 410', AROP 68 fph) at 450 gpm, 1805 psi, WOB 6-15K, 80 rpms, 17-19Kft-lbs, ECD 11.21 ppg with 9.15 ppg mud, max gas 121U. P/U 182K, S/O 56K,
ROTW 96K. Backream full stands. Slide as necessary through tangent. Continue drilling 8-1/2" hole from 10246' to 10629' (total 383', AROP 64 fph) at 450 gpm,
2066 psi, WOB 6-15K, 80 rpms, 18-20Kft-lbs, ECD 11.11 ppg with 9.2 ppg mud, max gas 431U. P/U 174K, S/O 58K, ROTW 97K. Backream full stands. Slide as
necessary through tangent. Continue drilling 8-1/2" hole from 10629' to 11043' (total 414', AROP 69 fph) at 450 gpm, 1970 psi, WOB 7-10K, 80 rpms, 20-22Kft-lbs,
ECD 11.105 ppg with 9.2 ppg mud, max gas 556U. P/U 180K, S/O 59K, ROTW 102K. Backream full stands. Slide as necessary through tangent. Distance to WP3:
2.1', 1.1' low, 1.8' right
4/2/2023 Continue drilling 8-1/2" hole from 11043' to 11377' (total 334', AROP 57 fph) at 450 gpm, 2000 psi, WOB 4-10K, 80 rpms, 21-23Kft-lbs, ECD 10.99 ppg with 9.2
ppg mud, max gas 677U. P/U 198K, S/O 60K, ROTW 104K. Backream full stands. Slide as necessary through tangent. Continue drilling 8-1/2" hole from 11377' to
11728' (total 351', AROP 59 fph) at 450 gpm, 2160 psi, WOB 7-13K, 80 rpms, 16-21Kft-lbs, ECD 10.75 ppg with 9.2 ppg mud, max gas 593U. P/U 174K, S/O 60K,
ROTW 99K. Backream full stands. Increase lube concentration with NXS by 0.25%. Sliding to begin build at 11,475' to 80 inclination and hold until NA-silt on logs.
Continue drilling 8-1/2" hole from 11728' to 12040' (total 312', AROP 52 fph) at 450 gpm, 2160 psi, WOB 7-13K, 80 rpms, 16-21Kft-lbs, ECD 10.75 ppg with 9.2
ppg mud, max gas 712U. P/U 178K, S/O 60K, ROTW 99K. Backream full stands. Observer NC-sand at 11747'. Re-evaluate logs, suspect fault came in late
at11620' with 62' DTS throw. Faulting from Ugnu MF sand to mid of NB-sand. Begin sliding to target 5/100 build to 97 to re-acquire NB sands. Continue drilling 8-
1/2" hole from 12040' to 12256' (total 216', AROP 36 fph) at 450 gpm, 2040 psi, WOB 8-14K, 80 rpms, 17-20Kft-lbs, ECD 10.99 ppg with 9.3 ppg mud, max gas
404U. P/U 178K, S/O 57K, ROTW 102K. Backream full stands. Sliding to build up to 97 to re-acquire NB-sands. Distance to WP3: 9.9', 8.1' low, 5.6' right.
4/3/2023 Continue drilling 8-1/2" hole from 12256' to TD at 12380' (total 124', AROP 35 fph) at 450 gpm, 2050 psi, WOB 8-14K, 80 rpms, 17-19Kft-lbs, ECD 10.98 ppg with
9.4 ppg mud, max gas 52U. P/U 183K, S/O 57K, ROTW 100K. Backream full stands. Re-acquire NB sands at 12,312'. Obtain final survey. Monitor well, static.
BROOH to 12,157'. Pump tandem sweeps low vis/wt followed by high vis/wt sweeps (25 bbls late, 50% increase) and circulate hole clean total 3x bottoms up. 450
gpm, 1850 psi, 80 rpms, 18-20Kft-lbs, ECD 11.15 ppg with 9.4 ppg mud. Wash and ream to 12,380'. Monitor well, static. BROOH from 12,380' to 10,455' at 450
gpms, 1750 psi, 80 rpms, 17-21Kft-lbs, ECD 10.12 ppg max gas 135u. Pull 20-30 fpm, no issues. P/U 174K, S/O 65K, ROTW 99K. BROOH from 10,455' to 7,850'
at 450 gpms, 1650 psi, 80 rpms, 15-20Kft-lbs, ECD 10.23 ppg max gas 89u. Pull 20-30 fpm, no issues. P/U 174K, S/O 65K, ROTW 99K. BROOH from 7,850' to
6,438' at 450 gpms, 1480 psi, 80 rpms, 12-15Kft-lbs, ECD 10.61 ppg max gas 26u. P/U 174K, S/O 65K, ROTW 99K. Pulling 20-30 fpm to 6892'. Observe packoff
at 6892' with loss of returns (54 bbls lost). Re-establish circulation and slow pulling speed to 2-10 fpm. Slow rotary at BHA comes through shoe. Minor packoff
observed at 6592' as flex collars come through shoe'. Dynamic loss rate 5-8 bph. Pump tandem low vis/wt and high vis sweeps (50% increase) and CBU x2 at 450
gpm, 1420 psi, 80 rpms, 12-14Kft-lbs, ECD 10.51 ppg, reciprocating pipe. P/U 125K, S/O 65K, ROT 80K. Distance to WP3 projected to TD: 18.09', 17.93' high,
2.46' left.
4/4/2023 PJSM - Service Rig, Grease Crown Sheaves and Inspect. Extend Top Drive Frame and Inspect crack repairs - Good. Grease and Inspect Top Drive and blocks.
Inspect drill line and Drawworks. PJSM - L/D 5" DP. POOH F/6,438' - T/6,153' MD. Pump 25 bbls of CI Brine 11.2ppg Dry-Job. B/D Top Drive and GEO-Span. L/D
5" DP F/6,153' - T/718' MD. Culling 5" DP for CATIV. Monitor well for 10m, well slightly losing. loss of 11 bbls on trip. L/D 5" DP F/718' - T/377' MD. PU=94K,
S/O=78K. PJSM - L/D BHA. L/D F/377' MD - T/Surface. L/D 5" HWDP, Jars, NM Flex Collars, MWD, Stabilizers, Mud Motor and 8.5" NOV TK66 (Graded: 4-5-WT-
A-X-2-BT-TD). PJSM - Clean and Clear Rig Floor. R/D Rig Tongs, Catheads, Bit Breaker, Service Iron Roughneck. Check Dies on Slips and Airslips. Pressure
wash rig floor. PJSM - TIH F/Derrick. M/U mule shoe to first stand and TIH F/Surface - T/2,434' MD with 5" 19.5# DP. P/U=92K, S/O=62K. Continue TIH with 5" DP
F/2,434' - T/6,355' MD F/Derrick. Loss 6.6 bbls on trip in. Monitored well for 10m - Good. Pumped 25 bbl CI 11.4 ppg Dry-Job. Blow down Top drive. P/U=120K,
S/O=58K. PJSM - L/D 5" DP to the Pipe shed. Pulled bushings and installed stripping rubbers. TOOH F/6,355' - T/2,599' MD, loss of 3 bbls. P/U=85K, S/O68K.
PJSM - L/D 5" DP to the Pipe Shed. POOH F/2,599' - T/Surface. Cull out remaining 5" DP for CATIV Inspection and Hard-banding. P/U=48K, S/O=50K, loss of 6.4
bbls. PJSM - M/U Wear ring running tool. Drain Stack, RIH and Engage wear ring. BOLDS, Pull Wear ring and L/D same. M/U Test Plug and RIH. Bleed off
Accumulator. Open UPR Doors and remove 5" SBR, clean and inspect cavity. Install 7" SBR, close and tighten ram doors. While changing out the UPR's. The 7"
SBR came dislodged from the ram door piston and fell to the cellar floor, bouncing off the grating impacting the IP lower left leg. IP is seeking first aid at the clinic
and will update later. Crew completed a safety stand down to discuss. PJSM - R/U BOP Test Equipment (witness waived by AOGCC Guy Cook). P/U 7" Test joint,
Flood Lines and Purge air. Headpin was leaking and retorqued. Test UPR 7" SBR 250 for 5 mins - Good. Testing Hi-Side (3000psi) at time of reporting. Daily
Disposal to G&I 0 bbls, total 7,974 bbls. Daily Disposal to MP G&I 57 bbls, total 3,858 bbls. Daily H2O from Lake 2, 280 bbls, total 11,125 bbls. Daily H2O from
Lake LPad Lake: 0 bbls, total 700 bbls. Daily surface losses 93 bbls, total 285 bbls.
4/5/2023 Finish testing BOP's 250/3000 psi 5/5mins - Good. R/D Testing Equipment. Attempt to pull test plug. Plug sticking in wellhead. Vault Rep verified LDS are backed
out - continue troubleshooting. Decision was made to use blocks to pull test plug, L/D 7" TJ and P/U 5" DP joint. P/U T/12k and plug came free. observed metal
debris on top of plug. PJSM - Flush Stack: M/U Jetting Tool and clean ditch magnets in possum belly. Flush BOPE at 15BPM with 30RPM while reciprocating
multiple times. B/D Topdrive and drain stack - Recovered more metal from magnets. PJSM - R/U for Casing run: P/U 7" Landing Hanger for dummy run - Good.
Remove hydraulic 5" DP elevators and install 7" 250T Parker TRS elevators. P/U 320T Volant and M/U to Topdrive. P/U Power Tongs and hookup hydraulics. R/U
TQ Turn Equipment. Check Handling Equipment with Sizing Mandrel - Good. PJSM - Run Casing F/Surface - T/1,932' MD: M/U 4-joint 26# BTC Shoe track
(bakerlock connections), check floats - Good. Crossover from 7" 26# BTC to 7" 29# VAMTOP Torque Turning Connections to 9400 ft-lb. RIH as per tally filling joints
every 10. P/U=78K, S/O=62K. Total of 33 Centralizers ran. PJSM - Run Casing F/1,932' - T/5,390' MD. Torqueing 29# 7" VAMTOP Casing to 9,400 ft-lb. Filling
casing every 10 joints. P/U=113K, S/O=59K, Calculated displacement is 56 bbls, actual is 44 bbls, loss of 12 bbls. Running speed continues to be 65fpm. Run
Casing F/5,390' - T/5,681' MD. L/D 4 Joints (2 Bad Pin, 2 Bad Box). Continue Torque Turning 7" VAMTOP. Running speed continues at 65fpm. Rig Service. Found
a blown out hose on Pipe Skate - Repaired. SIMOPS: Circulate 4bpm = 170psi, no losses observed. Rig floor Crew completed daily checklist while pipe skate
repairs were made. Run Casing F/5,681 - T/6,423'. Fill pipe every 10 joints and torque turning 29# VAMTOP casing to 9,400 ft-lb. Ran in the hole past Baffle
Adaptor and Float collar without issues. Circulating at Shoe. Staged up pumps from 3bpm to 6 bpm (320psi) completing a bottoms up. Attempted to rotate while
reciprocating at 2 RPM, torque stalling at 8000 ft-lb. P/U=127K, S/O=71K. No losses observed while circulating. Run Casing F/6,423' - T/6,900' MD. Lost 5K string
weight coming down thru the 9-5/8" shoe with the 7" shoe, P/U with clean breakover. Torque Turn 7" 29# VAMTOP to 9400 ft-lb. Continue running at 65fpm in open
hole. P/U=127k, S/O=71K. Daily Disposal to G&I 114 bbls, total 8,088 bbls. Daily Disposal to MP G&I 57 bbls, total 3,858 bbls. Daily H2O from Lake 2, 140 bbls,
total 11,265 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily surface losses 12 bbls, total 297 bbls.
4/6/2023 PJSM - Ran Casing F/6,900' - T/9,373' MD. Running speed dropped to 15-45fpm from 65fpm. Circulated Bottoms up at 9,057' MD, staging pumps up to 6bpm =
530psi. loss of 8 bbls during circulation. P/U=188k, S/O=52K, loss of 13 bbls on trip. Continue torque turning 7" VAMTOP connections to 9,400ft-lb. Continued to
Run 7" Casing F/9,373' - T/9,921' MD. Maintaining 15-45fpm running speed. Filling pipe every 10 joints and breaking circulation. P/U=186K, S/O=60K. Circulated
Bottoms up, staging pumps up to 3bpm = 400psi. Rotated and reciprocated at 2RPM with torque stalling at 9,000ft-lb. P/U=188K, S/O-62K. Continued Running 7"
Casing F/9,921' - T/10,610' MD. Lost down weight, began washing and reaming joints down at 3bpm = 450psi. Rotated at 2RPM with torque stalling at 5,700' ft-lb.
Running speed increased to 65fpm. P/U=186K, S/O=60K. Continued Washing 7" Casing down F/10,610 - T/11430' MD. Washed down at 4bpm = 562 psi.
Encountered tight spot at 11,391 and slight packing off. P/U=270K (20K over), S/O 35K. Torque stalling at 2-3 RPM at 9,200ft-lb. Worked thru tight spots and
began a clean up cycle. Circulated Bottoms up. Staged from 4bpm to 5bpm = 620 psi, slight seepage and reduced to 4bpm = 543psi. Reciprocated and rotated at 2-
3 RPM, torque stalling at 9,200ft-lb. Tight spots were wiped clean during the BU. PU=239k, S/O=45K. Loaded a lube pill in the pipe for upcoming heel-up at
11,664' MD. Continue Washing 7" Casing down F/11,430' - T/11,992' MD. Running speed slowed down to 15-35fpm, no notable ledges or sticky spots. Pumps on
at 4 bpm = 626psi. Rotated at 1-2 RPM torque stalling at 6,000 ft-lb. Continue to Torque turn 7" 29# VAMTOP to 9,400 ft-lb. PJSM - New Crew, Continued
Washing 7" Casing down F/11,992' - T/12,380" (TD) MD. Washed down at 4 BPM = 585psi. Picked up 2 additional joints (#292 and #293), tagged bottom (on
depth) with 8k down at 4.42' in on joint #293, joint count on location is good. Laid down Joint #293. P/U=240k, S/O=37K. Circulate and Condition Mud for Cement
Job. M/U Joint #292 and observed an overpull of 70k (P/U=325K). Link out bails to increase downstroke movement for better breakover, S/O=50K. Came back up
and and broke over (P/U=308K). Rotate (1-2 RPM) and Reciprocate at 6 BPM = 743psi. P/U= 288K, S/O 40K. Continued to Condition and Circulate. Pumping at 6
BPM = 607 psi. ROT P/U=220K, ROT S/O=35K. NonROT P/U=240K, NonROT S/O=28K. Reduced YP of Mud F/21cP - T/18cP. Pumped around Spiked Lube Pill
and was able to move down without rotation. Daily Disposal to G&I 352 bbls, total 8,440 bbls. Daily Disposal to MP G&I 0 bbls, total 3,858 bbls. Daily H2O from
Lake 2, 140 bbls, total 11,265 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily surface losses 38 bbls, total 335 bbls.
4/7/2023 POOH L/D Tag Joint. P/U Landing Joint and 7" Fluted Casing TQ turn connections to 9,400 ft/lbs. P/U 255K, S/O 45K. Land Hanger on Depth @ 12,369' with 10K
on Csg Hgr. Break circulation for 15 minutes, shut down and change out Seal Cup on Volant CRT. Circulate and condition mud for cement job, staging pumps to 6
bpm, 730 psi. Lower YP to 17. SIMOPS: Clean and clear rig floor. Send out Parker casing equipment. PJSM, R/U Cement equipment, Test lines 1000/4000. Pump
Cement job with 60 bbls 11 ppg Spacer, 95 bbls 15.8, 465 sx, 1.155 yld Primary cement. Displace Cement with 454.6 bbls 9.4 ppg Mud. Bump plug @ 2.5 bpm
675 FCP. Hold 1200 psi 5 min. Check Floats, good. CIP @ 10:51. No losses during job. Wet Cmt @ 8:43, Pump Cmt 3 bpm Ave, Disp Cmt @ 6.5 bpm Ave. Bump
Plug on Calc Stks/bbls. B/D Cement Lines. B/O CRT, B/O and L/D 7" Landing Joint. M/U Packoff running tool to 5: HWDP. Land Pack Off. RILDS. Test Pack Off,
10/10m, 500/5000psi - Good. L/D Pack Off running tool. PJSM - Changing Rams. Bleed down Koomey and change UPR from 7" SBR's to 2-7/8" x 5-1/2" VBR's.
Clean and Clear Rig Floor. Remove remaining Casing running tools. Break out the Volant. Remove bail extensions from Floor. Switch Handling equipment to 4".
Remove the NC50 Saver sub and Install 6-5/8" REG x XT-39, TQ to 45,000ft-lb. C/O grabber dies. Remove all 5" Handling equipment from floor and bring up 4"
Elevators, Slips and Hydraulic Elevator inserts. Change out Gear lube in top drive. Service Iron Roughneck. P/U BOP Testing Equipment. P/U TIW, Dart, XO's, Test
joints (4" and 4.5"). Verify Sensators and Chart. P/U Test joint and RIH. Flood Lines and pump through Super Choke. BOP Testing. 250/3000psi on 4" TJ and 4.5"
TJ, Test Annular, Upper/Lower IBOP, Dart, Mezz Kill and CMV 7-15, TIW (#1 and #2) Upper/Lower 2-7/8" x 5-1/2" VBR's, HCR Kill, Manual Choke - Pass. Super
Choke Fail/Pass. Witness Waived by AOGCC Rep, Guy Cook 4-7-23. PJSM - Test BOPE. 250/3000psi on 4.5" TJ. Grease Manual kill and Change out CMV #5
Fail/Pass. Test CMV 1-6, Manual Kill, HCR Choke. Koomey Draw down, Initial: ACC=2975, MAN=1500, ANN=1350. Final: ACC=1500, MAN=1500, ANN=1200.
200psi recharge = 26s, full recovery = 87s, N2 Bottle Average = 2258psi. Pull Test plug and L/D Test joint. Break down testing equipment. Blow down Choke and
Kill. Grease and inspect Top Drive, Overhead Spinner, FH-80 and Tongs. Change out Top Drive Lube Pump. SIMOPS: Process 4" DP and BHA.
4/8/2023 NPT - Top Drive. Top Drive faulting with low lube oil flow alarm - changed out lube pump. Refilled w/new oil. Pump was putting out 7-8 GPM initially and became
sporadic at 3-7 GPM. Oil began to foam up again (cavitation). Decision was made to change out the PRV Cartridge, on pump suction manifold. Adjusted the PRV
cartridge to 7 GPM = 120psi. test ran for 20 minutes without issue. Determination was that the PRV cartridge was plugged. Torqued down coffin bolts and wire tied
bolts. PJSM - Picked up 4" DP. RIH w/wear ring, RILDS. L/D Running Tool and 5" DP. P/U XO's for BHA. SIMOPS: LRS pumped 77 bbls of FP diesel down 9-5/8"
x 7" OA, Max = 900psi at 1.4 BPM. PJSM - P/U BHA. P/U Smith Tri-Cone bit, Terraforce 4-3/4" 7/8 Lobe Mud motor, 4 joints of 4" XT-39 HWDP, 4-3/4" HydraJar, 3
joints of 4" XT-39 HWDP. P/U=42K, S/O=42K. BHA = 285.83'. PJSM - Singled in the hole. P/U 4" 14# XT-39 DP F/285' - T/3,027' MD. Filled pipe at 3,027'. Blew
down Top Drive both ways. Drifted on the skate with a 2.38" Drift. P/U=54k, S/O=50K. Continued P/U 4" XT-39 DP F/3,027' - T/9,219' MD. P/U=82K, S/O=50k.
Filled pipe at 6,023' MD and 8,810' MD. PJSM - P/U Drill Pipe. Continued P/U 4" XT-39 DP F/9,219' - T/12,192' MD. Washed down T/12,220 seeing no indications
of cement stringers. P/U=115K, S/O=56k. Circulate Bottoms Up. Rotate and Reciprocate at 20RPM = 7k TQ, 225GPM = 1200psi. Observed minimal clabbered up
mud upon Bottoms Up at the shakers, pumped 500 strokes over calculated. P/U=115k, S/O=80K, R/F=24%. Test CSG: Blow down top drive. R/U and Test 7" 29#
CSG at 12219' MD, blow air thru choke and then flood. Test CSG at 2500 psi with a 30m hold on chart - Pass. Pumped 4.0bbls and bled back 3.9bbls. R/D Test
Equipment.
4/9/2023 PJSM - Drill Cement F/12,220' - T/12,368' MD. Tag Float collar on depth (12,238'), drilled thru at 220GPM=1230psi. 8K TQ at 40RPM. Worked thru Pumps on/off
and Rotary on/off without issue 2x. P/U=115K, S/O=62K, ROT=82K, WOB=6K. Continued drilling cement T/12,368' MD and tagged float shoe on depth, drilled thru
at 230GPM=1375psi, 10.5K TQ at 60RPM. Worked thru Pumps on/off and Rotary on/off without issue 2x. Drilled 20' of new formation T/12,400' MD. P/U=115K,
S/O=64K, ROT=80K, WOB=4-12K. Displace well T/9.4ppg BaraDril-N while rotating and reciprocating F/12,398' - T/12,350' MD. P/U=115K, S/O=55K, ROT=77K,
RPM=60. Torque dropped from 10.5K to 8.5K once the 4% lubed mud displaced the older mud. Finish displacing the well ensuring Clean new 9.4ppg mud was to
surface. Shutdown, rack back one stand for FIT. PJSM - R/U for FIT. P/U and M/U equipment for FIT. 2x Plug Valves, Swings, High pressure Hose and whip-
checks. Flood all lines, Mud in system was aired up, decision was made to circulate and add defoamer - re-primed lines. Shut UPR and begin test. Pressure up to
550psi and hold for 10 mins - Good. Pumped 0.8bbls and bled back 0.5bbls. Obtain SPR's, MP#1 32/48=575/708psi. MP#2, 32/48=560/713. Pump 35 bbl dry-job.
B/D Kill, Choke, Test Equipment and L/D Same. Install stripping rubbers and air slips. PJSM TOOH F/12,350' - T/10,500' MD. Flow check well for 10m before
TOOH. P/U=122k, S/O=63K. Observed calculated displacement. PJSM - Slip and Cut. Cut 11 wraps (71'), 839' left on spool. Check brake tolerances - Good.
Perform Crown and Block Service. Calibrate Drum and verify floor and crown saver. Check Top Drive gear oil, Grease RLA Washpipe, IBOP, Spnners, Roughneck,
Top Drive Upper IBOP. Check Rotary Oil. Complete Iron Roughneck Monthly EAM. NPT Lube Pump Motor. Fault Code on Top Drive gear lube motor. Replaced
Motor and rewired, test motor - Good. Closed Coffin, torqueing down bolts and wire-tie bolts/nuts. Continuous hole fill during this time period - no change. PJSM -
TOOH F/10,500' - T/7,356' MD. P/U=98K, S/O=50K. Observed calculated displacement. PJSM - TOOH F/7,356' - T/285' MD. P/U=46K, S/O=46K. Monitored well
for 10m - Good. Observed calculated displacement. L/D BHA F/285' - T/Surface. Rack back 4" HWDP, Jars, break out Bit and lay down Mud Motor. P/U=40K,
S/O=40K, Bit Grade: 1-1-WT-A-E-I-NO-BHA/ Clean and Clear rig floor. PJSM - P/U Rotary Steerable. P/U NOV 6.125" SKC613M Bit, GeoPilot 5200, MWD (ADR,
DM, TM, GM, PWD), stabilizers, Jar and NM Flex Collars along with 7 joints of 4" XT-39 HWDP. BHA = 411.78' MD. Daily Disposal to G&I 518bbls, total 10,272
bbls. Daily Disposal to MP G&I 0 bbls, total 3,915 bbls. Daily H2O from Lake 2, 280 bbls, total 12,245bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls.
Daily surface losses 5 bbls, total 360 bbls.
4/10/2023 Continue P/U BHA per Sperry Reps. Perform Confidence test and download to MWD. M/U Float sub, NM Flex, 4 joints HWDP, Jars and 3 joints HWDP. Break in
GEO-Pilot and perform shallow hole pulse test. B/D Top Drive. P/U=50k, S/O=48K. BHA=411.78'. PJSM - Singling in with 4" DP. P/U 4" XT-39 14# DP F/411' -
T/4,204' MD off of the Skate. drift w/2.38". Fill pipe at 1,359' and 4,204'. GPM 225 = 645psi. P/U=70K, S/O=56K. Observed Calculated displacement on trip. PJSM -
Singling in with 4" DP. P/U 4" XT-39 14# DP F/4,204' - T/8,246' MD off of the Skate. drift w/2.38". Fill pipe at 6,400' and 8,246'. GPM 166 = 788psi. P/U=77K,
S/O=55K. Observed Calculated displacement on trip. RIH with F/8,246' - T/9,191' MD out of the Derrick. Fill pipe at 9,191' and Circulated a BU. GPM 166 = 800psi.
P/U=100K, S/O=59K. RIH with F/9,191' - T/12,314' MD out of the Derrick. P/U=114K, S/O=65K. Wash down F/12,314' - T/12,342' MD. Washing down past 12,308'
MD, S/O dropped by 6K. correlated with Stabilizer 78' back taking weight. Pulled back up through and went back down, no issue. 146 GPM = 877 psi. Return Flow
= 21%. PJSM - Installed MPD Bearing at 12,314'. Drain Stack, pull bushing and install rotating head. Install boot saver and seal around drip pan. Observed a
Hydraulic leak coming from Coffin Lid. Open lid and track down leak to a hydraulic pressure switch. SIMOPS: Check TD gear oil - Good. Grease RLA Washpipe,
IBOP's, Spinners and Iron Roughneck. Remove Hydraulic Line and unwire pressure switch. Install proper fittings on new switch and began installation. LOTO Top
Drive and Hydraulics. Continued to circulate over the hole during repairs 94 GPM = 655psi. Finish installation of the new pressure switch. Electrician on site.
Repairs completed. Unlock Top Drive and hydraulics. Function test hydraulics and Top Drive - No issues. Torque down Top Drive Coffin and wire tie as necessary.
Clean and Clear Rig floor. Drill 6.125" Injection Lateral F/12,400' - T/12,575' MD (4058' TVD), (175' total = 35' AROP). GPM 225 In / 220 Out, 1,685 psi on, WOB
10-16K, RPM 120, 8K TQ on, 6K TQ off. Max Gas 656u, ~30u BGG, 11.47 ECD w/ 9.1ppg MW. P/U 116K, S/O 52K, ROT 75K. Distance to WP03 23.19', 21.47'
High, 8.77' Left. 2 concretions for a total thickness of 4' (2.4% of the lateral). Total Footage in NB Sands = 167'. Total Footage out of NB Sand = 0'. Total Footage in
Lateral = 167'. Daily Disposal to G&I 114 bbls, total 10,386 bbls. Daily Disposal to MP G&I 0 bbls, total 3,915 bbls. Daily H2O from Lake 2, 140 bbls, total 12,385
bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily surface losses 0 bbls, total 360 bbls.
4/11/2023 Cont Drill 6.125" Hole F/ 12,575' to 13,167' MD (4,067' TVD) Total 592' (AROP 98.7') 225 gpm/ MPD 220, PSI on 1575 psi, off 1515 psi 120 rpm, TRQ on 8-9k,
TRQ off 7-8k, WOB 8-18k. ECD 11.46. Max Gas 720u.MW in/out 9.1/ 9.15 P/U 119k, SLK 41k, ROT 76k. MPD 100% open. Back ream 60'. Cont Drill 6.125" Hole
F/ 13,167' to 13,509' MD (4,077' TVD) Total 342' (AROP 57') 225 gpm/ MPD 220, PSI on 1775 psi, off 1582 psi 90-120 rpm, TRQ on 8-10k, TRQ off 7-9k, WOB 8-
18k. ECD 11.34. Max Gas 705u.MW in/out 9.1/ 9.15 P/U 122k, SLK 52k, ROT 77k. MPD 100% open. Back ream 60'. Cont Drill 6.125" Hole F/ 13,509' to 13,623'
MD (4,076' TVD) Total 115' (AROP 46') 225 gpm/ MPD 220, PSI on 1793 psi, off 1602 psi 80-120 rpm, TRQ on 8-10k, TRQ off 7-10k, WOB 10-18k. ECD 11.21.
Max Gas 741u.MW in/out 9.0/ 9.1 P/U 133k, SLK 48k, ROT 79k. MPD 100% open. Back ream 60'. At 13500 MD the Geo-Pilot began to lack tool-face
acknowledgment in reference of targeted commands. Trouble shooting revealed the reference housing may be locked up. Work the torque out of the string and put
1 wrap to the left and slowly work pipe in an attempt to back spin the Geo-Pilot within the. reference housing to free the bearings. It appeared to have been
successfully worked through and we continued drilling to 13,546 MD, at this point it was noted that the Inc. Cruz appeared to be having trouble maintaining targeted
inclination, we attempted to manual steer, and it seemed to be. accurately targeting tool-face and deflection with command settings. At 20:00hrs we lost detection all
together at which point we began trouble shooting MWD Pulses. We performed a manual reset and a mode switch in an attempt to gain communication with the
tools. After reviving pulses we continued. drilling to 13,623 MD while utilizing manual mode. During this time several erratic ABIs were observed swinging +/- 4
within just a few feet, it was also observed that the targeted tool-face was rolling 360 in an attempt to maintain set point. Decision was made to POOH and change
out tools. PJSM Rack back 1 stand. Monitor well W/ MPD 10 min, no pressure. BROOH F/ 13,601' to 12,579' MD 223 gpm/ MPD 207, PSI 1620 psi, 80-90 rpm,
TRQ 9-10k, ECD 11.03. Max Gas 645u. P/U 123k, SLK 56k, ROT 81k. MPD 100% open. Pull speed 20 ft/min. Slow rotary to 20 rpm Trq 6-8k W/ BHA entering
shoe. PJSM Cont BROOH F/ 12,579' to 12,346' MD. 223 gpm/ MPD 215, PSI 1580 psi, 20 rpm, TRQ 7k, ECD 11.03. Max Gas 20u. P/U 122k, SLK 56k, ROT 81k.
MPD 100% open. Pull speed 5-15 ft/min. Pulled GeoPilot on elevators through shoe, saw 5k over pull, SLK to neutral. ROT at 20 rpm pulled clean. PJSM CBU 225
gpm 1,475 psi no increase at shakers. Monitor well W/ MPD 10 min, no pressure build. Blow down TD. PJSM Loosen Grey Clamp and pull RCD bearing as per
Beyond rep onsite. Install trip nipple and tighten grey clamp. PJSM POOH on elevators F/ 12,346' to 11,650' MD (5 Stands) No swabbing. Pump 28 bbl 10 ppg dry
job. Blow Down TD. Cont POOH F/ 11,650' to 7,931' MD. P/U 109k SLK 64k. no losses. Distance to WP03 11.17', 1.44' High, 11.08' Left. 12 concretions for a total
thickness of 50' (4% of the lateral). Total Footage in NB Sands = 1251'. Total Footage out of NB Sand = 0'. Daily Disposal to G&I 399 bbls, total 10,785 bbls. Daily
Disposal to MP G&I 0 bbls, total 3,915 bbls. Daily H2O from Lake 2, 420 bbls, total 12,805 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily
surface losses 0 bbls, total 360 bbls.
4/12/2023 PJSM Cont POOH F/ 7,931' to 411' MD. P/U 48k SLK 48k. Lost 14 bbls. PJSM Rack back 4" XT39 HWDP, jar and NM FC W/ FS. Read MWD tools. L/D TM,
break ILS, L/D PWD/GM, DM, ADR and GeoPilot. Bit Grade 4-5-BT-A-X-I-CT-DTF. PJSM Service rig. Grease and inspect TD, blocks, crown, FH-80 and spinners.
C/O grease fitting on wash pipe. Add 2 gal oil to TD. PJSM P/U M/U BHA #5. 6 1/8" Hycalog SKC613-S5B Rebuilt (3X9,3X11 jts 0.4648 TFA), GeoPilot 5200, 4
3/4" ADR, 6" ILS, 4 3/4" DM, 4 3/4" GM, 4 3/4" PWD, 6" ILS, 4 3/4" TM, 4 3/4" FS (Non Ported/ Plunger) 4 3/4" NM FC, 4 3/4" FS (Non Ported/ Plunger) 4 3/4" NM
FC, X/O, 4 ea 4" HWDP, 4 3/4" HydraJar,. 3 ea 4" HWDP total 412.36'. Break in GeoPiolt and shallow pulse test, good. PJSM RIH BHA #5 W/ 4" XT39 D.P. to
12,278' MD. P/U 115k SLK 69k. Fill at 2,900', 8,930' & 12,296' MD. AT 6,096' MD. Sperry DD checked GeoPilot and sent down link, good. 200 gpm 783 psi. B/D
TD. Lost 32.8 bbls for trip. PJSM At 12,296' MD Install RCD bearing. Drain stack, pull bushings and trip nipple. Install RCD bearing as per Beyond rep onsite.
Tighten grey clamps and check for leaks, good. PJSM wash down F/ 12,296' to 12,550' MD side track point. 200 gpm/ mpd 201, 1,925 psi, 20-80 rpm Trq 6-8.5k
Max Gas 53u. P/U 76k SLK 52k. Rotate through shoe (12,368' MD) W/ BHA at 20 rpm increased to 80 rpm at 12,475' MD. MPD 100% open. Due to high DLS
decision was made to side track the well at 12,550' MD. Perform side track operations. Started trough F/ 12,550 to 12,585 MD in manual mode setting at 171 with
50% deflection. Trough 3 times showing steady drop in ABI @ .2/10'. 1st trough parameters 200GPM, 1965psi 100 RPM,. Torque 10K, with slight torque stalls
reduced RPM to 40-60 W/ 1-2 WOB at 40-60 ROP unable to get separation. 2nd Trough parameters, 225GPM, 1,985psi, 60-80 RPM, 10-40 ROP seeing ~0.5-
degree separation, 3rd Trough Parameters, 225GPM, 1985psi, 80 RPM, erratic torque causing reduced RPM to 30 rpm. W/ Trq stall set at 10k, increased torque
stall to 11.8k to mitigate stalls, able to maintain 80 rpm W/ 11.2-11.5K Trq without issue. On the 3rd trough Time Drill F/ 12,575 to 12,580 MD 60 fph, F/ 12,580 to
12,583 MD 40 fph, F/ 12,583 to 12,584 20 fph,. F/ 12,585 to 12,588.5 MD 10 fph, F/ 12,588.5' to 12,592 5' MD fph, increased rotary to 100 RPM F/ 12,592 to
12,595 MD seeing 1 separation from original wellbore with 2K weight on bit, incrementally staging ROP/RPM as separation increase. Cont Drill 6.125" Hole F/
12,595' to 12,607' MD (4,062' TVD) Total 22' (AROP 11') 225 gpm/ MPD 205, PSI on 1660 psi, off 1650 psi 120 rpm, TRQ on 9-11k, TRQ off 9-11k, WOB 1-4k.
ECD 11.01. Max Gas 151u.MW in/out 9.0/ 9.05 P/U 119k, SLK 53k, ROT 78k. MPD 100% open. Distance to WP03 11.17', 1.44' High, 11.08' Left. Fault #1 12,445'
MD 10' DTN. 2 concretions for a total thickness of 4' (1.7% of the lateral). Total Footage in NB Sands = 236'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 114
bbls, total 10,899 bbls. Daily Disposal to MP G&I 0 bbls, total 3,915 bbls. Daily H2O from Lake 2, 440 bbls, total 12,945 bbls. Daily H2O from Lake LPad Lake: 0
bbls, total 700 bbls. Daily losses 58 bbls, total 58 bbls.
4/13/2023 Drill 6.125" Hole F/ 12,607' to 12,760' MD (4,068' TVD) Total 153' (AROP 25.5') 225 gpm/ MPD 223, PSI on 1675 psi, off 1625 psi 130 rpm, TRQ on 9-11k, TRQ
off 8-9k, WOB 2-12k. ECD 10.95. Max Gas 284u.MW in/out 9.0 P/U 119k, SLK 52k, ROT 77k. MPD 100% open. Drill 6.125" Hole F/ 12,760' to 12,951' MD (4,072'
TVD) Total 191' (AROP 31.8') 225 gpm/ MPD 210, PSI on 1430 psi, off 1405 psi 80-130 rpm, TRQ on 9k, TRQ off 8-9k, WOB 4-8k. ECD 10.8. Max Gas 548u.MW
in/out 9.0/9.05 P/U 119k, SLK 52k, ROT 79k. MPD 100% open. Drill 6.125" Hole F/ 12,951' to 13,166' MD (4,073' TVD) Total 215' (AROP 35.8') 225 gpm/ MPD
223, PSI on 1596 psi, off 1530 psi 80-95 rpm, TRQ on 9.5-10k, TRQ off 8-9k, WOB 5-7k. ECD 11.3. Max Gas 376u.MW in/out 9.0/9.05 P/U 119k, SLK 54k, ROT
76k. MPD 100% open. Crossed fault #2 at 12,973' MD throw 10' DTN. Due to crossing fault and 8.2 DLS at 12,923' MD we controlled drilled 5-20 fph F/ 12,923' to
13,181' MD to prevent going into old wellbore, closest approach was 2.39'. Drill 6.125" Hole F/ 13,166' to 13,407' MD (4,083' TVD) Total 241' (AROP 40') 225 gpm/
MPD 223, PSI on 1608 psi, off 1560 psi 95 rpm, TRQ on 8-10k, TRQ off 7-8k, WOB 5-8k. ECD 11.47. Max Gas 376u.MW in/out 9.0 P/U 119k, SLK 48k, ROT 76k.
MPD 100% open. Distance to WP03 2.69', 0.83' High, 2.56' Left. Fault #1 12,445' MD 5' DTN Fault #2 12,973' MD 10' DTN. 2 concretions for a total thickness of 4'
(1.7% of the lateral). Total Footage in NB Sands = 987'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 285 bbls, total 11184 bbls. Daily Disposal to MP G&I 0
bbls, total 3,915 bbls. Daily H2O from Lake 2, 560 bbls, total 13505 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 0 bbls, total 58 bbls.
Daily Metal 20# total 52#.
4/14/2023 Drill 6.125" Hole F/ 13,407' to 13,735' MD (4,086' TVD) Total 328' (AROP 59.6') 225 gpm/ MPD 223, PSI on 1597 psi, off 1490 psi 120-130 rpm, TRQ on 6-8k,
TRQ off 6-7k, WOB 6-9k. ECD 11.41. Max Gas 520u.MW in/out 9.0 P/U 114k, SLK 48k, ROT 77k. MPD 100% open. No Losses. Service Top Drive and investigate
Oil Drip from Coffin. Determined residual oil from Lube Oil Pump swap. Clean up and close coffin. Drill 6.125" Hole F/ 13,735' to 14,050' MD (4,078' TVD) Total
315' (AROP 52.5') 225 gpm/ MPD 223, PSI on 1540 psi, off 1465 psi 120-130 rpm, TRQ on 6-7k, TRQ off 6k, WOB 6-8k. ECD 11.31, Max Gas 555u.MW in/out
9.0, P/U 116k, SLK 51k, ROT 77k. MPD 100% open. No Losses. Entered out of the top of NB sand into N/A Sand at 13,981' MD in preparation for Fault #3. Drill
6.125" Hole F/ 14,050' to 14,210' MD (4,072' TVD) Total 160' (AROP 26.7') 225 gpm/ MPD 223, PSI on 1510 psi, off 1480 psi 80-130 rpm, TRQ on 6k, TRQ off 6k,
WOB 6-8k. ECD 11.21 Max Gas 143u.MW in/out 9.0/9.3, P/U 116k, SLK 53k, ROT 76k. MPD 100% open. No Losses. Drill 6.125" Hole F/ 14,210' to 14,323' MD
(4,062' TVD) Total 113' (AROP 18.8') 225 gpm/ MPD 223, PSI on 1580 psi, off 1490 psi 90-120 rpm, TRQ on 6-8.5k, TRQ off 6-7k, WOB 6-8k. ECD 11.19 Max
Gas 29u.MW in/out 9.0/9.05, P/U 116k, SLK 50k, ROT 76k. MPD 100% open. No Losses. Control drill with 8k max WOB due to out of zone. Fault #3 14,206' MD
Tentative fault pick based on potential NB-Base at 14,277' MD. Distance to WP03 17.15', 5.48' Low, 16.25' Right. Fault #1 12,445' MD 5' DTN Fault #2 12,973' MD
10' DTN Fault #3 14,206'. 24 concretions for a total thickness of 137' (7.1% of the lateral). Total Footage in NB Sands = 1,400' Out 533'. PB 12,550' to 13,624' MD.
Daily Disposal to G&I 264 bbls, total 11448 bbls. Daily Disposal to MP G&I 342 bbls, total 3257 bbls. Daily H2O from Lake 2, 420 bbls, total 13925 bbls. Daily H2O
from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 0 bbls, total 58 bbls. Daily Metal 0# total 52#.
4/15/2023 Drill 6.125" Hole F/ 14,323' to 14,653' MD (4,044' TVD) Total 330' (AROP 55' FPH) 225 gpm/ MPD 223, PSI on 1615 psi, off 1530 psi 130 rpm, TRQ on 7-8.5k,
TRQ off 6-7k, WOB 6-8k. ECD 11.55 Max Gas 2819u.MW in/out 9.0/9.0, P/U 112k, SLK 52k, ROT 75k. MPD 100% open. No Losses. Crossed Fault #3 at 14,313
md with a throw of 102' DTS. This moved the bit from the Ugnu MF way down to within the Schrader Bluff NE. We then drilled NE silt and sand, NC silt and NC-
Sand. Estimate re-enter the NB-Sand base at about 15,050 md. Drill 6.125" Hole F/ 14,653' to 14,901' MD (4,026' TVD) Total 248' (AROP 41.3' FPH) 225 gpm/
MPD 223, PSI on 1620 psi, off 1535 psi 120 rpm, TRQ on 8-9k, TRQ off 7-8k, WOB 6-8k. ECD 11.47 Max Gas 3321u, MW in/out 9.0/9.0, P/U 111k, SLK 52k,
ROT 76k. MPD 100% open. No Losses. Drill 6.125" Hole F/ 14,901' to 15,155' MD (4,012' TVD) Total 254' (AROP 42.3' FPH) 225 gpm/ MPD 223, PSI on 1605
psi, off 1525 psi 120 rpm, TRQ on 8k, TRQ off 7k, WOB 6-8k. ECD 11.5 Max Gas 810u, MW in/out 9.0/9.05, P/U 112k, SLK 52k, ROT 76k. MPD 100% open. No
Losses. Ream 60'. Back in NB Sand at 14,986' MD. That is 332' above zone before fault #3 at 14,313' MD and 673' below zone after fault #3. Drill 6.125" Hole F/
15,155' to 15,568' MD (4,009' TVD) Total 413' (AROP 68.8' FPH) 225 gpm/ MPD 223, PSI on 1640 psi, off 1595 psi 120 rpm, TRQ on 7-9k, TRQ off 7-8k, WOB 3-
7k. ECD 11.69 Max Gas 3794u, MW in/out 9.0/9.1, P/U 114k, SLK 51k, ROT 75k. MPD 100% open. No Losses. Ream 60'. Distance to WP03 30.79', 30.3' High,
5.46' Right. Fault #1 12,445' MD 5' DTN Fault #2 12,973' MD 10' DTN Fault #3 14,313' 102' DTS. 24 concretions for a total thickness of 137' (7.1% of the lateral).
Total Footage in NB Sands = 1,400' Out 533'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 528 bbls, total 11976 bbls. Daily Disposal to MP G&I 114 bbls, total
4371 bbls. Daily H2O from Lake 2, 560 bbls, total 14485 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 0 bbls, total 58 bbls. Daily Metal
0# total 52#.
4/16/2023 Drill 6.125" Hole F/ 15,568' to 16,011' MD (4,028' TVD) Total 443' (AROP 73.8' FPH) 225 gpm/ MPD 223, PSI on 1694 psi, off 1616 psi 120 rpm, TRQ on 9-11k,
TRQ off 9-10k, WOB 3-5k. ECD 11.79 Max Gas 3692u, MW in/out 9.0/9.1, P/U 116k, SLK 42k, ROT 75k. MPD 100% open. No Losses. Ream 60'. Drill 6.125"
Hole F/ 16,011' to 16,469' MD (4,034' TVD) Total 458' (AROP 76.3' FPH) 225 gpm/ MPD 223, PSI on 1790 psi, off 1695 psi 120 rpm, TRQ. on 9k, TRQ off 8-9k,
WOB 3-8k. ECD 11.7 Max Gas 2644u, MW in/out 9.0/9.1, P/U 117k, SLK 39k, ROT 76k. MPD 100% open. No Losses. Ream 60'. Drill 6.125" Hole F/ 16,469' to
16,770' MD (4,049' TVD) Total 301' (AROP 50.2') 210 gpm/ MPD 210, PSI on 1680 psi, off 1605 psi 120 rpm, TRQ on 7.5-8k, TRQ off 7k, WOB 3-8k. ECD
11.69 Max Gas 3178u, MW in/out 9.05, P/U 116k, SLK 43k, ROT 76k. MPD 100% open. No Losses. Ream 60'. Added in two drums Lube 776 at 16,576 MD
due high trq and stalls W/ 11.5k Trq stall set. Torque fell from 1.5k to 8.5k. Reduced pump rate to 210 gpm due to climbing ECD's. Drill 6.125" Hole F/ 16,770' to
17,212' MD (4,047' TVD) Total 442' (AROP 73.7') 215 gpm/ MPD 212, PSI on 1830 psi, off 1745 psi 120 rpm, TRQ on 6-8k, TRQ off 7k, WOB 3-8k. ECD 11.88
Max Gas 1011u, MW in/out 9.05, P/U 114k, SLK 42k, ROT 74k. MPD 100% open. No Losses. Ream 60'. Distance to WP03 36.59', 27.9' Low, 23.6' Right. Fault
#1 12,445' MD 5' DTN Fault #2 12,973' MD 10' DTN Fault #3 14,313' 102' DTS. 60 concretions. for a total thickness of 328' (6.9% of the lateral). Total Footage
in NB Sands = 3,534' Out 1,217' Total footage 4,751'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 456 bbls, total 12432 bbls. Daily Disposal to MP G&I 171
bbls, total 4542 bbls. Daily H2O from Lake 2, 520 bbls, total 15005 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 0 bbls, total 58
bbls. Daily Metal 0# total 52#.
4/17/2023 Drill 6.125" Hole F/ 17,212' to 17,447' MD (4,049' TVD) Total 235' (AROP 39') 215 gpm/ MPD 213, PSI on 1950 psi, off 1795 psi 120 rpm, TRQ on 9-11k, TRQ off
8-9k, WOB 3-8k. ECD 12.12 Max Gas 1475u, MW in/out 9.0, P/U 115k, SLK 40k, ROT 74k. MPD 100% open. No Losses. Ream 60'. Drill 6.125" Hole F/ 17,447' to
17,657' MD (4,062' TVD) Total 210' (AROP 35') 215 gpm/ MPD 213, PSI on 1800 psi, off 1715 psi 120 rpm, TRQ on 6-7k, TRQ off 8-9k, WOB 3-8k. ECD 11.8
Max Gas 929u, MW in/out 9.0, P/U 116k, SLK 41k, ROT 75k. MPD 100% open. No Losses. Ream 60'. Drill 6.125" Hole F/ 17,657' to 17,975' MD (4,054' TVD)
Total 318' (AROP 53') 200 gpm/ MPD 200, PSI on 1680 psi, off 1620 psi 120 rpm, TRQ on 7.5-8k, TRQ off 7k, WOB 3-8k. ECD 11.7 Max Gas 2081u, MW in/out
9.05, P/U 115k, SLK 42k, ROT 75k. MPD 100% open. No Losses. Ream 60'. Encountered Fault #4 at 17,914' MD,49' throw DTS. This moved bit position from the
NB into the NE. Anticipate back in NB reservoir by about 18,280' MD. Drill 6.125" Hole F/ 17,975' to 18,141' MD (4,042' TVD) Total 184' (AROP 30.7') 210 gpm/
MPD 205, PSI on 1730 psi, off 1650 psi 120 rpm, TRQ on 7-8k, TRQ off 7k, WOB 2-8k. ECD 11.7 Max Gas 1876u, MW in/out 9.0, P/U 115k, SLK 40k, ROT 75k.
MPD 100% open. No Losses. Ream 60'. Distance to WP03 26.47', 23.42' Low, 12.34' Right. Fault #1 12,445' MD 5' DTN #2 12,973' MD 10' DTN #3 14,313' 102'
DTS #4 17,914' 49' DTS. 70 concretions for a total thickness of 354' (6.2% of the lateral). Total Footage in NB Sands : 4328'' Out 1,400' Total footage 5728'. PB
12,550' to 13,624' MD. Daily Disposal to G&I 114 bbls, total 12546 bbls. Daily Disposal to MP G&I 328 bbls, total 4870 bbls. Daily H2O from Lake 2, 240 bbls, total
15245 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 0 bbls, total 58 bbls. Daily Metal 0# total 52#.
4/18/2023 Drill 6.125" Hole F/ 18,141' to 18,415' MD (4,030' TVD) Total 274' (AROP 45.7') 210 gpm/ MPD 205, PSI on 1785 psi, off 1685 psi 115 rpm, TRQ on 10-12k, TRQ
off 9-11k, WOB 2-8k. ECD 11.97 Max Gas 2010u, MW in/out 9.05, P/U 115k, SLK 40k, ROT 75k. MPD 100% open. No Losses. Ream 60'. Dump & dilute 440 bbl
9.0 ppg BaraDril N W/ 4% lubes to control MBT & ECD's. Fault #4 at 17,914' re-correlated to throw 58' DTS from NB-Sand into NE. After Fault #4 drilled out of zone
F/ 17,914' MD to 18,495' MD for 581'. Drill 6.125" Hole F/ 18,415' to 18,571' MD (4,019' TVD) Total 156' (AROP 26') 210 gpm/ MPD 205, PSI on 1810 psi, off 1725
psi 120 rpm, TRQ on 10-12k, TRQ off 9-11k, WOB 2-8k. ECD 11.85 Max Gas 2165u, MW in/out 9.05, P/U 115k, SLK 40k, ROT 75k. MPD 100% open. No Losses.
Ream 60'. NB-Sand reservoir base of pay entered at 18,495' md and drilled in the reservoir for 37' F/ 18,495' to 18,532' MD. Fault #5 was crossed at 18,532' md
with 4' throw DTN from NB-Sand into NB-Clay. After Fault #5 we drilled out of zone for 26' until 18,558' MD. The NB-Sand pay was entered at 18,558' MD. Drill
6.125" Hole F/ 18,571' to 18,690' MD (4,008' TVD) Total 119' (AROP 19.8') 215 gpm/ MPD 210, PSI on 1760 psi, off 1705 psi 120 rpm, TRQ on 8-9k, TRQ off 8k,
WOB 6-8k. ECD 11.68 Max Gas 1634u, MW in/out 9.05, P/U 115k, SLK 40k, ROT 75k. MPD 100% open. No Losses. Ream 60'. Drill 6.125" Hole F/ 18,690' to
18,817' MD (4,003' TVD) Total 127' (AROP 21.2') 215 gpm/ MPD 210, PSI on 1790 psi, off 1715 psi 120 rpm, TRQ on 7-8k, TRQ off 7-8k, WOB 4-8k. ECD 11.84
Max Gas 1645u, MW in/out 9.05, P/U 113k, SLK 35k, ROT 73k. MPD 100% open. No Losses. Ream 60'. Distance to WP03 28.20', 28.05' Low, 3.11' Right. Fault
#1 12,445' MD 5' DTN #2 12,973' MD 10' DTN #3 14,313' 102' DTS #4 17,914' 58' DTS #5 18532' 4' DTN. 81 concretions for a total thickness of 354' (6.8% of the
lateral). Total Footage in NB Sands: 4365'' Out 1,936' Total footage 6331'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 592 bbls, total 13138 bbls. Daily Dis-
posal to MP G&I 0 bbls, total 4870 bbls. Daily H2O from Lake 2, 470 bbls, total 15715 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 0
bbls, total 58 bbls. Daily Metal 0# total 52#.
4/19/2023 Drill 6.125" Hole F/ 18,817' to 18,981' MD (4,009' TVD) Total 164' (AROP 27.3') 205 gpm/ MPD 201, PSI on 1980 psi, off 1790 psi 120 rpm, TRQ on 8-10k, TRQ
off 8-9k, WOB 7-9k. ECD 11.96 Max Gas 358u, MW in/out 9.0, P/U 113k, SLK 38k, ROT 72k. MPD 100% open. No Losses. Ream 60'. Drill 6.125" Hole F/ 18,981'
to 18,992' MD (4,010' TVD) Total 11' (AROP 7.3') 205 gpm/ MPD 201, PSI on 1880 psi, off 1780 psi 120 rpm, TRQ on 8-9k, TRQ off 8k, WOB 7-9k. ECD 11.86
Max Gas 206u, MW in/out 9.0, P/U 114k, SLK 39k, ROT 72k. MPD 100% open. No Losses. Ream 60'. @ 18981' connection point, we swapped mud pumps to
service the other pump. Detection was good for the survey and ~10' of drilling, then detection was lost. Drilled to a depth of 18991' where the assembly was pulled
off bottom to troubleshoot the problem. Checked and charged pulsation Dampeners,. detection problems were still present. Some detection was possible and we
attempted to drill ahead. Drilled to 18993', pulled off bottom again. Troubleshot the problem, did not find any obvious problems. When off bottom circulating the
detection is maybe 5% w/occasional Geo Pilot/ECD Stats. Rack back 1 Stand anbd CBU from 18,983 to 18,921', 205 gpm, 1945 psi, 120 rpm, 7K Trq, 9.0+ MW,
11.64 ECD, Max gas 284u, PU 113K, So 38K, ROT 72K., MPD open 100%. SIMOPS: Change out Pod 4, MP #1, No Losses. Shut in MPD and monitor well, static.
PJSM BROOH F/ F/ 18,983' to 15,030' MD 210 gpm/ MPD 201, PSI on 1670 psi, 120 rpm, TRQ 5-6k. ECD 11.3 Max Gas 278u, MW in/out 9.05, P/U 102k, SLK
58k, ROT 73k. MPD 100% open. No Losses Pull speed 20-25 fpm. PJSM BROOH F/ F/ 15,030' to 12,780' MD 215' gpm/ MPD 201', 1,480 psi , 120 rpm, TRQ 4-
5k. ECD 10.69 Max Gas 338u, MW in/out 9.1, P/U 106k, SLK 60k, ROT 76k. MPD 100% open. No Losses Pull speed 20-30 fpm. Minor packing off F/ 14,142' to
13,996' md. reduce flow F/ 215 to 150 gpm, Pull Speed 1-5 fpm Out of zone and 7 Deg DLS at 13,996' MD. Lost 7 bbls. Distance to WP03 37.74', 36.46' High, 9.7'
Left. Fault #1 12,445' MD 5' DTN #2 12,973' MD 10' DTN #3 14,313' 102' DTS #4 17,914' 50' DTS #5 18,532' 18' DTN. 81 concretions for a total thickness of 440'
(6.1% of the lateral). Total Footage in NB Sands: 4501'' Out 2123' Total footage 6624'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 228 bbls, total 13366 bbls.
Daily Disposal to MP G&I 0 bbls, total 4870 bbls. Daily H2O from Lake 2, 510 bbls, total 16225 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily
losses 8 bbls, total 66 bbls. Daily Metal 0# total 52#.
4/20/2023 PJSM BROOH F/ F/ 12,780' to 12,343' MD 215' gpm/ MPD 201', 1,445 psi , 120 rpm, TRQ 4k. ECD 10.61 Max Gas 338u, MW in/out 9.1, P/U 106k, SLK 60k,
ROT 76k. MPD 100% open. No Losses Pull speed 20-30 fpm. No issue pulling up into casing shoe @ 12,369'. Pump 35 bbls, 9.1 ppg Hi Vis Sweep @ shoe, 10%
increase in cuttings. 225 gpm, 1555 psi, 20 rpm, 3K Trq, P/U 97, S/O 67K, Rot 77K. Monitor well for 10 min. Static. Remove MPD RCD Bearing and Install Flow
Riser. Flood stack and check for leaks. Good. SIMOPS: Test MP #1 to 3000 psi. Good. TOH on elevators 5 stands, from 12,343 to 11,964', no swabbing. Pump 25
bbls Slug.9.9+ ppg. Service Rig, Grease and inspect crown and block sheaves, TD, FH-80, Upper Pipe Spinners, and elevators, check fluid levels in TD. Monitor
Hole with Trip Tank, Static. TOH racking back 4" DP from 11,964' to 412'. P/U 45K, S/O 43K. Lost 61.5 bbls on trip out. Rack Back 4 stds 4" HWDP/Jar, L/D 2x
float subs and 2 NM Flex Collars, L/D 3.5" x 4" XO, Down load MWD Tools. L/D TM, ILS, PWD, GM, DM, ADR & GeoPilot. Bit Grade 2-2-BT-A-X-I-CT-BHA. Lost 88
bbls. PJSM P/U 4" test jnt M/U wear ring puller, BOLDS, pull wear ring. PJSM RIh set test plug, RLDS. Line up IA to TT. M/U 4" Dart, 4" TIW and pump in sub.
Flood stack W/ H2O and purge air. Shell test to 3,000 psi, good. PJSM Perform BOPE test W/ 4" & 4.5" to 250 PSI low and 3,000 PSI high for 5 Min. Tested Choke
Manifold 1-15, 4" Dart, 2 ea 4" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Kill, Manual and Super Choke (F/P) actuator out of time 1,600 psi, Upper
and lower VRB Rams (2,875" X 5.5"). (UPR Fail W/ 4.5) Blind Rams, Annular W/ 4" test Jnt. Koomey draw drown Initial System 3,000 PSI, Manifold 1,500 PSI,
Annular 1,160 PSI, after System 1,500 PSI, Man 1,500 PSI, Annular 1,200 PSI. 200 PSI increase 27 Sec, full charge 89 sec. Nitrogen 6 bottle average 2,266 PSI.
Test H2S 10-20 ppm,. LEL 20-40%, PVT high/ low level alarms. Closing times Ann 12 sec, UPR 9/9 sec, LPR 4 sec, HCR Choke and Kill 1/1 sec. Tested W/ H2O.
Witnessed waived by AOGCC Rep Kam StJohn. Filling annulus W/ TT 2 bbls every hour. PJSM Close blind rams and bleed down accumulator. Break bolts and
open UPR doors. Found damage to element and seals. C/O element and seals on ODS ram. Element retainer bolt was seized up on DS. C/O ram. Closed doors
and buttoned up. Energize accumulator. Test UPR's (2,875" X 5.5") HCR and manual Choke (F/P) greased & #2 TIW. 250/3500 psi for 5 min. Fault #1 12,445' MD
5' DTN #2 12,973' MD 10' DTN #3 14,313' 102' DTS #4 17,914' 50' DTS #5 18,532' 18' DTN. 81 concretions for a total thickness of 440' (6.1% of the lateral). Total
Footage in NB Sands: 4501'' Out 2123' Total footage 6624'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 114 bbls, total 13480 bbls. Daily Disposal to MP G&I
19 bbls, total 4889 bbls. Daily H2O from Lake 2, 420 bbls, total 16645 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 98 bbls, total 164
bbls. Daily Metal 0# total 52#.
4/21/2023 Cycle manual choke valve, test good. Pull and L/D 4.5" test jnt. P/U M/U 4" test joint and test UPR's (2.875" X 5.5" VBR's) 250/ 3,000 psi 5 min each good. Filling
IA 2 bph W/ TT. PJSM R/D test Equip. Pull test plug and install wear ring. (12" Lgth, 10.75" OD 7" ID) RILDS. L/.D jnt and wear ring running tool. Blow down
surface line. Took 12 bbls to fill hole. PJSM Move stands in collar finger and L/D stands 287 & 288 due to bad box and pin. Prep for P/U BHA. Static loss rate 1.8
bph. PJSM P/U M/U BHA #6. 6 1/8" Hycalog SKC613M-A1B, Rebuilt (3X9,3X11 jts 0.4648 TFA), GeoPilot 5200, 4 3/4" ADR, 6" ILS, 4 3/4" DM, 4 3/4" GM, 4 3/4"
PWD, 6" ILS, 4 3/4" TM, Down load MWD tool as per MWD.4 3/4" FS (Non Ported/ Plunger) 4 3/4" NM FC, 4 3/4" FS (Non Ported/ Plunger). 4 3/4" NM FC, X/O, 4
ea 4" HWDP, 4 3/4" HydraJar, 3 ea 4" HWDP total 412.01'. Shallow pulse test GeoPiolt, good. Continue to see 2 bph static loss rate. PJSM RIH BHA #6 W/ 4" 14#
S-135 XT39 D.P. F/ 412' to 6,090' MD. At 2,947' MD filled pipe and broke in GeoPilot ROT 10-60 rpm Trq 1.2k P/U 75k SLK 59k. Filling pipe every 3,000'. Run
speed 50-75 fpm due to pushing fluid away. Calc 58 bbls, Act 92 bbls Lost 34 bbls. Cont RIH W/ 4" 14# S-135 XT39 D.P. F/ 6,090' to 12,272' MD. Filling pipe
every 3,000'. Reduce run speed 45 fpm due to pushing fluid away. Appears to be pushing away 40% of calculated displacement. Calc 92 bbls, Act 51 bbls Lost 41
bbls. P/U 116k SLK 66k. Fill pipe and break Circ at 12,283' MD at 3 bpm 300 psi seeing 24 bph dynamic losses. PJSM Install 4" TIW and hang blocks. Cut and slip
drilling line 13 wraps (81'). Current TM 1127, ACCUM 43,126. 758' left on spool. Check brakes. Trq Deadman 80 ft/lb. Pumping down string at 2 bpm 200 psi
seeing 12-14 bph dynamic losses. PJSM Service rig. Grease TD, Crown Sheaves and Blocks. Perform EAM wobble on block sheave. Service PH8. At BU
increased rate to 3 bpm 605 psi W/ dynamic losses at ~41 bph. Call out 280 bbls new mud F/ mud plant. PJSM Monitor well 15 min, slight seepage loss. P/U stand
F/ derrick W/ RCD bearing. Pull bushings. Open grey clamp and pull riser. Lower string and set RCD bearing. M/U Grey Clamp. Cont RIH W/ 4" 14# S-135 XT39
D.P. F/ 12,272' to 13,255' MD. Reduce run speed to 20-35 fpm to prevent pushing away fluid. Calc 9.4 bbls, Act 4.3 bbls Lost 5.1 bbls. P/U 115k SLK 55k. RIH to
12,720 MD and shoot check shot 86.23 deg inc to ensure we are in mother bore and not sidetrack. Stage pumps up to 200 gpm 1,100 psi MPD showing 78-136
gpm out slowing getting better. Losing 32% in returns and dynamic loss ~90 bph. Fault #1 12,445' MD 5' DTN #2 12,973' MD 10' DTN #3 14,313' 102' DTS #4
17,914' 50' DTS #5 18,532' 18' DTN. 81 concretions for a total thickness of 440' (6.1% of the lateral). Total Footage in NB Sands: 4501'' Out 2123' Total footage
6624'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 114 bbls, total 13594 bbls. Daily Disposal to MP G&I 0 bbls, total 4889 bbls. Daily H2O from Lake 2, 420
bbls, total 17065 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 124 bbls, total 288 bbls. Daily Metal 0# total 52#.
4/22/2023 Cont RIH on elevators W/ 4" 14# S-135 XT39 D.P. F/ 13,255' to 13,295' MD. Reduce run speed to 20-35 fpm to prevent pushing away fluid. P/U 118k SLK 48k.
Had to work down to 13,295', losing S/O Weight. Wash and Ream in hole from 13,295' to 15,898'. GPM 105, PSI 1020, Max Gas 36u, RPM 15-20, Tq 5-7K, P/U
122K, S/O 44K, Rot 83K, Running Speed 15-40 FPM as hole dictates. Wash and Ream in hole from 15,898' to 18,226'. GPM 185, PSI 1450, Max Gas 682u, RPM
15-20, Tq 8K, P/U 122K, S/O 35K, Rot 74K, Running Speed 20-30 FPM as hole dictates. @ 16,248' see clabbered up mud at surface, beyond flow out spiked to
203 gpm. Shut in chokes and see 314 psi. Bleed off Beyond chokes, shut in again with no build. Stage pumps from 1 to 4 bpm, mud cleaning up. Rig pumping 166
gpm and Beyond FO reading 160-165 gpm. Lost 172 bbls, Overboard 61 bbls junk mud. Cont Wash and Ream F/ 18,226' to 18,993'. GPM 185/ MPD 185, PSI
1,750,RPM 20-40, Tq 7-8K, Max Gas 605u, P/U 116K, S/O 35K, ROT 75K, Running Speed 20-30 FPM as hole dictates. Lost 10 bbls. Drill 6.125" Hole F/ 18,993'
to 19,044' MD (4,016' TVD) Total 51' (AROP 12.75') 200 gpm/ MPD 168, PSI on 1850 psi, off 1745 psi 120 rpm, TRQ on 10-12k, TRQ off 11k, WOB 6-12k. ECD
11.96 Max Gas 1,434u, MW in/out 9.0, P/U 113k, SLK 38k, ROT 72k. MPD 100% open. No Losses. Seeing ~10 bph dynamic losses. During drilling ahead survey
points at 18,990.79 MD 85.09 deg Inc 302.69 deg azi 16.12 Left & 19,054.04 MD 85.28de inc 302.2 deg azi 23.2 left showing us drifting left of plan. We will be uti-
lizing 3.5/100' to converge back to plan by TD. Drill 6.125" Hole F/ 19,044' to 19,234' MD (4,023' TVD) Total 190' (AROP 31.7') 200 gpm/ MPD 176, PSI on 1790
psi, off 1720 psi 120 rpm, TRQ on 8-10k, TRQ off 8-9.5k, WOB 6-12k. ECD 11.94 Max Gas 2,084u, MW in/out 9.1/9.2, P/U 120k, SLK 35k, ROT 76k. MPD 100%
open. No Losses. Ream 60'. Seeing intermittent ballooning 10-20 bbls while drilling. Dynamic losses ~10 bph, lost 28 bbls. Distance to WP03 38.36', 24.61' High,
29.43' Right. Fault #1 12,445' MD 5' DTN #2 12,973' MD 10' DTN #3 14,313' 102' DTS #4 17,914' 50' DTS #5 18,532' 18' DTN. 81 concretions for a total thick-
ness of 486' (7.1% of the lateral). Total Footage in NB Sands: 4501' Out 2179' Total footage 6680'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 171 bbls, total
13765 bbls. Daily Disposal to MP G&I 57 bbls, total 4946 bbls. Daily H2O from Lake 2, 280 bbls, total 17345 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total
700 bbls. Daily losses 506 bbls, total 794 bbls. Daily Metal 0# total 52#.
4/23/2023 Drill 6.125" Hole F/ 19,234' to 19,553' MD (4,052' TVD) Total 319' (AROP 530.2') 200 gpm/ MPD 180 gpm, PSI on 1730 psi, off 1680 psi 120 rpm, TRQ on 9-10k,
TRQ off 8-9k, WOB 7-10k. ECD 11.98 Max Gas 2,098u, MW in/out 9.1/9.2, P/U 123k, SLK 35k, ROT 76k. MPD 100% open. No Losses. Ream 60. Drill 6.125"
Hole F/ 19,553' to 19,615' MD (4,071' TVD) Total 62' (AROP 62') 200 gpm/ MPD 180 gpm, PSI on 1730 psi, off 1680 psi 120 rpm, TRQ on 9-10k, TRQ off 8-9k,
WOB 7-10k. ECD 11.98 Max Gas 2,098u, MW in/out 9.1/9.2, P/U 123k, SLK 35k, ROT 76k. MPD 100% open. No Losses. Ream 60. Final Survey at 19,562,72'
MD 4,071.26' TVD 80.95 deg inc 308.67 deg azi. Circ and conditon mud wrking pipe from 19,612' to 19'553'. Pump Tandem Low vis/Low Wt, Hi Vis/Hi Wt sweeps.
203 gpm, 1725 psi, ECD 11.91, Max gas 1661, Trq 9-10K, Rpm 120. No Change in cuttings back. Sweep back 15 bbls late. Cont Circ and condition W/O Brine to
arrive location. Cont Rot/Rec waiting on QuicDril trucks to show up on location. F/ 19,615' to 19,553' MD 203 gpm/ mpd 183, 1,725 psi 120 rpm Trq 9-10k ECD
11.95. Max Gas 289u. P/U 121K SLK 35k ROT 75k. PJSM Displace well F/ 9.1 ppg BaraDril to 9.2 ppg QuickDril 4 % lubricated brine. Pump SAPP Train (40 bbls
X3 W/ 20 bbl 2X) chased W/ 9.2 ppg QuickDril taking return to Vac trauck. About 3/4 through displacement Trq started climbing, increased Trq stall to 14.5k.
Working string to prevent stalling out. On the up stroke rpm fell from 115 to 80-90 rpm W/ 20-30k over pull, down stroke fell to 30-50 rpm W/ 20k lost down weight.
After Displacement F/ 19,615' to 19,553' MD 200 gpm/ mpd 187, 1,380 psi 120 rpm Trq 14.5k ECD 11.95 Max Gas 165u. Shut in MPD, no pressure. P/U 165k
SLK 35k ROT 76k Lost 30 bbls. PJSM BROOH F/ 19,615' to 18,605' MD. 225 gpm/ mpd 190, 1,725 psi 100-120 rpm Trq 13.5-14.5k, ECD 11.97 Max Gas 241u At
18,603' MD encountered tight hole working string W/ 8-10 rpm stalled out at 14.5k pulling to 40k over string weight (80k) RIH 1 stand having to work stand down to
~47k string WT. BROOH 1 stand with 60-70k over pull (140-150k String WT) string stalled W/ 14.5k Trq and 6-8 rpm. No signs of packing off. Cont BROOH F/
18,605' to 18,360' MD W/ over pull and rpm getting better. Issue appears to be Fault #5 18,532'MD and out of zone. At 18,360' was able to clean up area getting
back 90-100 rpm Trq 14.1-14.5k while moving and back reaming weight fell back to 81k while BROOH. Same BROOH parameters Cont BROOH F/ 18,360' to
18,160' MD. Pull speed 15 ft/min. Lost 30 bbls during BROOH. P/U 155k SLK 35k ROT 71k. Distance to WP03 30.17', 21.58' Low, 21.07' Left. Fault #1 12,445'
MD 5' DTN #2 12,973' MD 10' DTN #3 14,313' 102' DTS #4 17,914' 50' DTS #5 18,532' 18' DTN. 87 concretions for a total thickness of 498' (6.9% of the lateral).
Total Footage in NB Sands: 4827' Out 2419' Total footage 7246'. PB 12,550' to 13,624' MD. Daily Disposal to G&I 1108 bbls, total 14873 bbls. Daily Disposal to
MP G&I 114 bbls, total 5060 bbls. Daily H2O from Lake 2, 280 bbls, total 17625 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses 133 bbls,
total 927 bbls. Daily Metal 0# total 52#.
4/24/2023 Cont BROOH F/ 18,160' to 15,420' MD. 225 gpm/ mpd 187, 1,525 psi 120 rpm Trq 10-11k, ECD 11.35 Max Gas 196u Pull speed 15-30 fpm as hole dictates. P/U
127k SLK 35k ROT 80k Dynamic loss rate 5 bph. Cont BROOH F/ 15,420' to 13,035' MD. 225 gpm/ mpd 180, 1,375 psi 120 rpm Trq 9-10k, ECD 11.05 Max Gas
309u Pull speed 15-30 fpm as hole dictates. Dynamic loss 2-8 bph. P/U 128k SLK 46k ROT 78k. F/ 14,190' to 13,996' MD again minor packing off, Trq increase to
13k, speed 1-5 fpm, pump rate 175 gpm. Cont BROOH F/ 13,035' to 12,346' MD. 225 gpm/ mpd 180, 1,340 psi 120 rpm Trq 8k, ECD 11.05 Max Gas 286u Pull
speed 15-30 fpm as hole dictates. Dynamic loss rate 5 bph. P/U 112k SLK 49k ROT 77k. Pulled through shoe (12,368') 60 rpm no issue. Rot/ Rec Pump 35 bbl
250 Vis sweep, back on time no increase. Reduced pump rate F/ 225 to 200 gpm to reduce dynamic losses. Rot/ Rec F/ 12,346' to 12,283' MD. 200 gpm/ mpd 185,
1,300 psi 120 rpm Trq 7k, ECD 10.88 Max Gas 310u P/U 116k SLK 55k ROT 76k Lost 21 bbls. Shut in MPD check for Press, good. PJSM Remove Grey Clamp
and bushings. P/U RCD bearing to rig floor. Set bushing and break stand. Install bearing remover and remove bearing. Install trip nipple W/ spare 20" are boot. M/U
Grey Clamp. Check for leaks, had to replace rubber seal on trip nipple. PJSM Service rig. Grease blocks, crown, TD and spinners. Check oil in TD, added 2 gal.
Monitor well W/ TT, no losses. PJSM Pump out of hole. Went to pull 1 st stand and started to see swabbing. Decision was made to pump out F/ 12,283' to 12,219'
MD 125 gpm 520 psi F/O 19%. P/U 100k SLK 75k. PSJM Pump out of hole F/ 12,219' to 8,872 MD 125 gpm 520 psi F/O 12%. P/U 105k SLK 80k.Dyanmic losses
2 bph. Calc 19 Act 31 Lost 12. Stopped at 11,314' & 9,376' MD to check for swabbing, still swabbing. Daily Disposal to G&I 1018 bbls, total 15891 bbls. Daily
Disposal to MP G&I 0 bbls, total 5060 bbls. Daily H2O from Lake 2, 560 bbls, total 18185 bbls. Daily H2O from Lake LPad Lake: 0 bbls, total 700 bbls. Daily losses
104 bbls, total 1031 bbls. Daily Metal 0# total 52#.
4/25/2023 Cont. to pump out of hole from 8872' to 5847' at 125 gpm, 380 psi. P/U 90K, S/O 65K. Dynamic loss rate 2.5bph. CBU at 225 gpm, 980 psi 120 rpms, 2Kft-lbs
reciprocating pipe to 5784'. POOH from 5784' to 4516' with no indication of swabbing. P/U 69K, S/O 60K. POOH laying down drill pipe from 5468' to 412'. P/U 45K,
S/O 43K. Calculated hole fill observed. Rack back 3 stands HWDP. L/D BHA. Download MWD. Clean and clear rig floor. Bit grade 1-1-WT-A-X-1-NO-TD. Rig up to
RIH with lower completion: P/U Parker power tongs, elevators, slips. Install elevators. RIH with 4-1/2", 12.6#, L-80, W563 liner with slotted joints as per tally from
surface to 2398'. TQ connections to 3800 ft-lbs. P/U 52K, S/O 50K. Cont. to RIH with 4-1/2", 12.6#, L-80, W563 liner with slotted joints as per tally from 2398' to
7188'. TQ connections to 3800 ft-lbs. P/U 76K, S/O 56K. C/O to hydraulic DP elevators. P/U SLZXP as per Baker rep. M/U swab cup and ball seat on LRT. M/U
SLZXP to 7225'. R/D Parker power tongs. Service rig: grease crown sheaves, TD and blocks.
4/26/2023 M/U first stand of drill pipe to ZXPN liner top packer. pump through at 2 bpm 25 psi to ensure clear - good. Cont. to RIH with 4-1/2" lower completion from 7229' to
14,605' conveyed on drill pipe. P/U 112K, S/O 60K. Calc disp 43 bbls, actual 35 bbls. RIH with 4-1/2" lower completion from 14,605' to 16,381' conveyed on drill
pipe. RIH with 4-1/2" lower completion, picking up and drifting HWDP from 16,381' to 19,400'. P/U 166K, S/O 57K. Calc disp. 39.3 bbls, actual 36.3 bbls. Pick up to
put string in tension. Drop 1.125" phenolic ball and pump down at 3 bpm, slowing to 1 bpm. Observe ball on seat at 1710 strokes, pressure up to 2500 psi and hold
for 5 minutes to set liner top. Cont to pressure up to 4507psi and observe ball seat shear. Pick up to expose dog sub. Rotate at 20 rpms and set 50K down x 2 to set
liner top packer. Pick up to neutral wt. Rig up, flood choke and kill lines, purge air. PT liner top to 1500 psi for 10 minutes - good. Pumped 1.3 bbls, bled back 1.3
bbls. Blow down choke and kill lines. POOH laying down HW drill pipe. Pull 6 joints and verify no swabbing observed. Pump corrosion inhibited dry job. Cont.
POOH from 12,227' to 10,256' P/U 113. Pulling slow due to swabbing observed at faster pull speeds. Cont. to POOH laying down HW DP/DP from 10,256' to
surface. L/D LRT. Calc 53.2 bbls, Act. 67.8 bbls.
Activity Date Ops Summary
4/27/2023 RIH with excess drill pipe from derrick to 5,677'. P/U 76K, S/O 67K. Cacl disp 34.2 bbls, actual 29.2 bbls. Monitor well, static. POOH laying down drill pipe from
5,677' to surface. Calc displacement 32 bbls, actual 35 bbls. Pull stripping rubbers. R/D hydraulic elevators,Clean and clear rig floor. Pull wear bushing. Rig up to
RIH with upper completion. Rig up power tongs, Tq turn equipment. Install elevators. RIH with 4-1/2", 12.5#, L-80, JFE Bear upper completion as per detail to 6614'.
Tq to 5940 ft-lbs. P/U 68K, S/O 55K. Cacl 28.5 bbls, Act 21.5 bbls. Running speed 60 fpm with TNT. Cont. RIH with 4-1/2", 12.5#, L-80, JFE Bear upper
completion as per detail from 6614' to 11,801'. Tq to 5940 ft-lbs. P/U 92K, S/O 60K. Cacl 53.2 bbls, Act 39.3 bbls.
4/28/2023 Cont. RIH with 4-1/2", 12.5#, L-80, JFE Bear upper completion as per detail from 11801' to 12096' MD. Tq to 5940 ft-lbs. P/U 92K, S/O 62K. Cacl 53.2 bbls, Act
39.3 bbls. RIH @ reduced rate from 12096' to tag depth 12193' MD w/ 3k set down (tag on depth). Calc spaceout, L/D tag joints and M/U 9.7' and 9.63' pups below
first full joint. M/U hanger assy (loaded w/ BPV - CTS installed). Drain stack and landout hanger w/ 27k string wt (92k up, 62k dn). Shoe @ 12184' w/ 9' off
no/go.13.9 total bbl loss for run. Clean and clear rig floor. Rig down casing equipment and pipe handling equipment. M/U stack flushing tool. Flush stack, choke and
kill lines and choke manifold. B/D lines. N/D BOP: bleed down accumulator. Remove split bushings. Open RCD clamp and pull riser. Install MPD test cap Remove
MPD hardline, aluminum drip pan. Connect bridge cranes and disconnect cross chains. Break bolts on DSA, choke and kill flanges. Drain stack. Open ram doors
and remove rams. Disconnect accumulator lines. R/D choke and kill lines and cap. Unbolt stack and DSA. Set stack back on pedestal. Remove DSA. Center stack
over well, remove RCD bearing and set stack back on pedestal. N/U tree with wellhead rep. PT void 500/5000 psi - good. Rig up and PT tree 500/5000 psi - good.
Sim Ops: Change out saver sub. Pull CTS and BPV. Pick up and Rig up manifold for reverse circulating/U-tubing. Reverse circulate in 170 bbls of corrosion
inhibited brine at 2.5 bpm, 675 psi. R/U and line up LRS. PT lines to 3500 psi. Reverse circulate 105 bbls diesel for freeze protect at 2 bpm, ICP 420 psi, FCP 500
psi. Allow well to U-tube while monitoring T/IA pressures. Final SITP 240 psi, SICP 260 psi. SimOps: Assemble 3" ball and rod launcher. Bridal up and raise blocks.
Cont. cleaning pits. R/D U-tube manifold. Pull bushing and install ball and rod 'lubricator' with ball and rod loaded. Open master valve to release ball and rod. Shut
in well. Bleed pressure on 'lubricator'. R/D and break down. R/U circulating manifold.
4/29/2023 SITP 240 psi, SICP (IA) 260 psi. Flood lines, purge air. Psi up on tubing to 750 psi w/ 5 min hold (IA 400 psi indicating ball on seat). Psi up on tbg @ 1 bpm to 3500
psi, 1500 psi on IA, 0 psi OA. Attempt MIT-T 3500 psi (fail). Tbg psi slowly dropping, IA psi increase from 1500 psi to 1900 psi indicating communication.
Troubleshoot surface equipment (replace isolation valve on pumping equipment). Retest 4.5" tubing 3500 psi w/ 30 min hold (good test), IA 1000 psi stabilized.
Test fluid (Fresh water), pumped 2.2 bbls in / 2.2 bbls out. Initial 3650 psi, 15 min 3530 psi, 30 min 3502 psi with stabilization. Chart and record same. Attempt MIT-
IA 3500 psi w/ 30 min hold (held 2000 psi on tbg). Steady psi drop on IA with tbg slowly showing increase. Troubleshoot surface equipment. Found another isolation
valve leaking. Replace and retest. MIT-IA 3500 psi w/ 30 min hold (test good) w/ fresh water holding 2000 psi on tbg. Initial 3607 psi, 15 min 3563 psi, 30 min 3550
psi with stabilization. Pumped 3.2 bbls in / 3.2 bbls out. OA showed 0 psi throughout test. B/D and R/D pumping equipment. AOGCC waived witness by Guy Cook.
ANS Wells Integrity notified (waived witness),M/U lubricator and install type "H" BPV. R/D lubricator. Secure well, clean tree and cellar box. Secure tools and
equipment in cellar. Flush both MP's with fresh water and prep pit module for rig move. Release rig @ 12:00 hrs.
50-029-23749-00-00API #:
Well Name:
Field:
County/State:
PBW L-293
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
MIT-IA 3500 psi w/ 30 min hold (test good) w/ fresh water holding 2000 psi on tbg
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
81
74
X Yes No X Yes No 3.7
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 Ported
RKB
10 3/4
405 7378.5
SE
C
O
N
D
S
T
A
G
E
MP 1
7:31
Cement Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.5
Shoe @ 6445 FC @ Top of Liner6,359.00
Floats Held
30 738
333 405
Spud Mod
CASING RECORD
County State Alaska Supv.S Barber/ O Amend
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-293 Date Run 25-Mar-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC OSP 1.77 6,445.00 6,443.23
24.96
Csg Wt. On Hook:100,000 Type Float Collar:BFA No. Hrs to Run:29
9.5 6
2200
10
10.7 414 3.9
97
619
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned spacer 60
15.8
847
3.5
9.5 6 219.8/217.4
393.6/391.4
1020
56
MP 1
15 82
Bump press
Mechanical
Bump Plug?
Yes
19:30 3/27/2023 2,965
2965
6,445.006,447.00
CEMENTING REPORT
Csg Wt. On Slips:
Spud Mud
Tuned Spacer
814 2.85
Stage Collar @
56
Bump press
100
277
ES Closure OK
56
12 186
26.58 RKB to CHF
Type of Shoe:Ported Casing Crew:Parker Wellbore
No. Jts. Delivered 179 No. Jts. Run 172 7
Length Measurements W/O
Threads
Ftg. Delivered 7,160.00 Ftg. Run 6,445.00 Ftg. Returned 715.00
Ftg. Cut Jt.30.32 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
2.1
ArcticCem Type I/II
Type
2 ea SB & 4 ea SR on shoe jnt, 1 ea SB on Blank Jnt and 1 SB & 2 SR FC jnt. 1 ea SB to jnt 25. Every other Jnt to
Jnt 49. 5 ea SB before ES, 1 ea SB & 1 ea SR on ES Pups, 5 ea SB after ES. Every third jnt F/ jnt 102 to jnt 166.
Total 8 stop rings and 71 Solid Body Centralizers.
9.625 CSG 9 5/8 40.0 L-80 BTC Tenaris 82.04 6,443.23 6,361.19
Float Collar 10 3/4 BTC Innovex 1.39 6,361.19 6,359.80
9.625 CSG 9 5/8 40.0 L-80 BTC Tenaris 41.36 6,359.80 6,318.44
Baffle Adapter 10 3/4 BTC Halliburton 1.40 6,318.44 6,317.04
9.625 CSG 9 5/8 40.0 L-80 TXP BTC Tenaris 3,331.94 6,317.04 2,985.10
Pup 9 5/8 40.0 L-80 TXP BTC 16.69 2,985.10 2,968.41
ES Cementer 11 3/4 TXP BTC Halliburton 3.73 2,968.41 2,964.68
Pup 9 5/8 40.0 L-80 TXP BTC 18.10 2,964.68 2,946.58
9.625 CSG 9 5/8 47.0 L-80 TXP BTC Tenaris 2,946.58 2,946.58
EconoCem Type I/II 445 2.35
HelCem 400 1.15
4.1
HelCem 270 1.16
3/28/2023 0
Spud Mud
Cement Returns to Surface
97
56
100
2,965
X
0
X
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
196
197
198
199
200
X Yes No X Yes No 35
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes X No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe 7 26.0 L-80
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ FC @ Top of Liner
Floats Held
64 95
095
6% KCL BaraDril-N
CASING RECORD
County State Alaska Supv.J. Lott / S. Carter
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-293 Date Run 7-Apr-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Republic 2.32 12,368.77 12,366.45
Csg Wt. On Hook:250 Type Float Collar: No. Hrs to Run:
9.4 7
100
675
FI
R
S
T
S
T
A
G
E
11Spacer 60
434.7/434.62
1189
432.9
1
15.8 95
Bump press
STROKES AND LOSSES
Bump Plug?
10:51 4/7/2023 9,530
12,368.7712,380.00 12,380.00
CEMENTING REPORT
Csg Wt. On Slips:
6" KCL BaraDril-N
26.58 RKB to CHF
Type of Shoe:Oilfield Service Professi Casing Crew:Parker TRS
No. Jts. Delivered No. Jts. Run
Length Measurements W/O Threads
Ftg. Delivered Ftg. Run Ftg. Returned
Ftg. Cut Jt. Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
33 Centralizers Ran in total. 2 ran on Shoe with 4 stop rings. 1 centralizer on FC joint with 2 Stop Rings. 1 floating
centralizer on each joint from Joint # in hole 6-31.
Pup Joint 7 26.0 L-80 BTC Republic 126.86 12,366.45 12,239.59
Float Collar 7 26.0 L-80 BTC Republic 1.30 12,239.59 12,238.29
Pup Joint 7 26.0 L-80 BTC Republic 41.96 12,238.29 12,196.33
XO Joint 7 29.0 L-80 VAMTOP VAM 33.39 12,196.33 12,162.94
Casing 7 29.0 L-80 VAMTOP VAM 12,129.46 12,162.94 33.48
Pup Joint 7 26.0 L-80 VAMTOP VAM 8.72 33.48 24.76
Hanger 7 26.0 L-80 TCII Vault 0.54 24.76
RKB 24.22 24.22
PRIMARY 465 1.16
X
9,530
100
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Chelsea Wright Digitally signed by Chelsea Wright
Date: 2023.04.25 13:45:20 -08'00'Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.04.25 14:19:03 -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: 05/04/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: PBU L-293
PTD: 223-020
API: 50-029-23749-00-00
FINAL LWD FORMATION EVALUATION LOGS (03/20/2023 to 04/23/2023)
x ROP, AGR, DGR, PCG, ABG, EWR-M5, ADR, 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-293 LWD Subfolders:
PBU L-293 Geosteering Subfolders:
Please include current contact information if different from above.
PTD: 223-020
PBU L-293: T37629
PBU L-293PB1: T37630
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.05.05
08:49:17 -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-293PB1
PTD: 223-020
API: 50-029-23749-70-00
FINAL LWD FORMATION EVALUATION LOGS (03/20/2023 to 04/11/2023)
x ROP, AGR, DGR, PCG, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
PBU L-293PB1 LWD Subfolders:
Please include current contact information if different from above.
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.05.05
08:49:39 -08'00'
1
Regg, James B (OGC)
From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent:Tuesday, May 2, 2023 6:38 AM
To:Brooks, Phoebe L (OGC)
Cc:Regg, James B (OGC)
Subject:Hilcorp (PBU) April 2023 MIT Forms
Attachments:MIT PBU 16-14C 04-03-23.xlsx; MIT PBU A-27A 04-15-23.xlsx; MIT PBU B-13B 04-21-23.xlsx; MIT PBU
L-221 04-16-23.xlsx; MIT PBU NK-23 04-08-23.xlsx; MIT PBU P1-21 04-03-23.xlsx; MIT PBU P2-28
P2-46 04-03-23.xlsx; MIT PBU R-11A 04-13-23.xlsx; MIT PBU S-09A 04-13-23.xlsx; MIT PBU S-16
04-18-23.xlsx; MIT PBU S-17C 04-20-23.xlsx; MIT PBU S-32A 04-11-23.xlsx; MIT PBU S-37A
04-08-23.xlsx; MIT PBU V-213A 04-16-23.xlsx; MIT PBU V-217 04-10-23.xlsx; MIT PBU Y-10B
04-15-23.xlsx; MIT PBU Z-19A 04-10-23.xlsx; MIT PBU L-293 04-29-23.xlsx
Ms. Brooks,
Attached are the completed AOGCC MIT forms for the tests completed by Hilcorp in April 2023
Well: PTD: Notes:
16‐14C 2181170 4‐year MIT‐IA
A‐27A 1982350 4‐year MIT‐IA
B‐13B 2100390 Under Evaluation for IAxOA
L‐221 2080310 2‐year MIT‐T per CO736
L‐293 2230200 Rig MIT‐T & MIT‐IA
NK‐23 1940350 4‐year MIT‐IA
P1‐21 1930590 2‐year MIT‐IA per AA AIO 4G.005
P2‐28 1950440 4‐year MIT‐IA
P2‐46 1931320 4‐year MIT‐IA
R‐11A 1982060 2‐year MIT‐IA per AA AIO 3.024
S‐09A 2140970 4‐year MIT‐IA
S‐16 1840840 MIT‐T Per Sundry 323‐042
S‐17C 2020070 CMIT‐TxIA Per Sundry 322‐717
S‐32A 2120820 MIT‐T Per Sundry 323‐032
S‐37A 2120920 MIT‐T Per Sundry 323‐030
V‐213A 2220010 Annual MIT‐T per AA AIO 26B.007
V‐217 2061620 4‐year MIT‐IA
Y‐10B 2120210 4‐year MIT‐IA
Z‐19A 2061050 2‐year MIT‐IA per AA AIO 3B.006
Please reply with questions or concerns.
Ryan Holt
Hilcorp Alaska LLC
Field Well Integrity / Compliance
Ryan.Holt@Hilcorp.com
P: (907) 659‐5102
M: (907) 232‐1005
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
PBU L-293PTD 2230200
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230200 Type Inj N Tubing 0 3650 3530 3502 Type Test P
Packer TVD 4020 BBL Pump 2.2 IA Interval O
Test psi 1500 BBL Return 2.2 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230200 Type Inj N Tubing 0 945 945 945 Type Test P
Packer TVD 4020 BBL Pump 3.2 IA 0 3607 3563 3550 Interval O
Test psi 1500 BBL Return 3.2 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Rig MIT-IA Waived by Guy Cook
Notes:
Notes:
Hilcorp North Slope LLC
Prudhoe Bay / PBU / L pad
Shane Barber
04/29/23
Notes:Rig MIT-T Waived by Guy Cook
Notes:
Notes:
Notes:
L-293
L-293
Form 10-426 (Revised 01/2017)2023-0429_MIT_PBU_L-293_2tests
J. Regg; 5/8/2023
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Joseph Engel
To:Rixse, Melvin G (OGC)
Cc:McLellan, Bryan J (OGC); Joseph Lastufka
Subject:HAK PBU L-293 (PTD: 223-020) Lateral Update
Date:Thursday, April 13, 2023 7:46:20 AM
Attachments:image003.png
Mel/Bryan –
I wanted to give you an update on the lateral for L-293. While drilling ahead in the lateral we started
to observe housing roll and erratic ABI on the geopilot. The decision was made to POOH and replace
the entire BHA.
Due to the erratic ABI and subsequent doglegs, we have made the decision to perform an open hole
side track so that tortuosity does not impact our weight transfer for future drilling and running the
liner.
The OHST details are below.
Please let me know if you have any questions.
Thanks you for your time.
-Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
Office: 907.777.8395 | Cell: 805.235.6265
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
From:McLellan, Bryan J (OGC)
To:Joseph Engel; Rixse, Melvin G (OGC)
Cc:Davies, Stephen F (OGC)
Subject:RE: [EXTERNAL] RE: HAK PBU L-293 (PTD: 223-020) Intermediate Log and TOC
Date:Tuesday, April 4, 2023 11:10:00 AM
Joe,
AOGCC has reviewed the logs and agree that the top of significant hydrocarbon zone is at 10,030’
MD and your plan to place 500’ MD of cement above that point is sufficient to isolate them and
meet regulations.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Joseph Engel <jengel@hilcorp.com>
Sent: Tuesday, April 4, 2023 11:05 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC)
<melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] RE: HAK PBU L-293 (PTD: 223-020) Intermediate Log and TOC
Hey Bryan –
We just got to the surface casing shoe, plan forward is to POOH, LD BHA, then do a full BOPE test
before RIH with 7” long string. Cementers are looking to build and load out volumes.
If we could get an answer by tomorrow morning that should give them enough time to build the
slurry.
Thanks.
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503
Office: 907.777.8395 | Cell: 805.235.6265
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, April 3, 2023 5:03 PM
To: Joseph Engel <jengel@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] RE: HAK PBU L-293 (PTD: 223-020) Intermediate Log and TOC
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.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Hi Joe.
Our Geos are reviewing the logs. When do you need an answer by?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Joseph Engel <jengel@hilcorp.com>
Sent: Monday, April 3, 2023 3:58 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: HAK PBU L-293 (PTD: 223-020) Intermediate Log and TOC
Mel –
Attached is the MWD logs for the 8.5” intermediate hole on PBU L-293.
Hilcorp Geologists are calling the Schrader NB (target sand) at ~11,618’ MD, we crossed a fault from
the Ugnu MF sand directly into the NB at that depth. The top of significant hydrocarbon Ugnu sand
at ~ 10,030’ MD.
Hilcorp is proposing a TOC of 9,530’ MD, 500’ above top of significant Ugnu, with class g 15.8ppg
cement and a planned 40% excess.
Please let me know if you have any questions. Thank you for your time.
-Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503
Office: 907.777.8395 | Cell: 805.235.6265
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
1
Regg, James B (OGC)
From:James Lott - (C) <jlott@hilcorp.com>
Sent:Monday, March 20, 2023 6:18 AM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Shane Barber - (C); Oliver Amend - (C)
Subject:Diverter Hilcorp Innovation 3-19-23
Attachments:Diverter Hilcorp Innovation 3-19-23.xlsx
James Lott
HILCORP Drilling Foreman
HILCORP INNOVATION Rig
PBU, North Slope Alaska
907‐670‐3094 (Office)
907‐398‐9069 (Cell)
Harmony 1006
jlott@hilcorp.com
jameslott352@yahoo.com
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PBU L-293PTD 2230200
Date: 3/19/2023 Development:X Exploratory:
Drlg Contractor:Rig No.Innovation AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.:2230200 Rig Phone:
Rig Email:
MISCELLANEOUS:DIVERTER SYSTEM:
Location Gen.:P Well Sign:P Designed to Avoid Freeze-up?p
Housekeeping:P Drlg. Rig.P Remote Operated Diverter?p
Warning Sign P Misc:NA No Threaded Connections?p
24 hr Notice:P Vent line Below Diverter?p
ACCUMULATOR SYSTEM:Diverter Size:13 5/8 in.
Systems Pressure:2915 psig P Hole Size:12 1/4 in.
Pressure After Closure:2050 psig P Vent Line(s) Size:16 in.P
200 psi Recharge Time:17 Seconds P Vent Line(s) Length:217 ft.P
Full Recharge Time:49 Seconds P Closest Ignition Source:90 ft.P
Nitrogen Bottles (Number of):6 Outlet from Rig Substructure:201 ft.P
Avg. Pressure: 2308 psig P
Accumulator Misc:NA
Vent Line(s) Anchored:P
MUD SYSTEM:Visual Alarm Turns Targeted / Long Radius:NA
Trip Tank:p p Divert Valve(s) Full Opening:P
Mud Pits:p p Valve(s) Auto & Simultaneous:
Flow Monitor:p p Annular Closed Time: 17 sec p
Mud System Misc:0 NA Knife Valve Open Time: 5 sec p
Diverter Misc:NA
GAS DETECTORS:Visual Alarm
Methane:p P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Total Test Time:1 hrs Non-Compliance Items:0
Remarks:
Submit to:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Diverter Systems Inspection Report
GENERAL INFORMATION
WaivedParker
*All Diverter reports are due to the agency within 5 days of testing*
jlott@hilcorp.com
TEST DATA
Joel Sture
phoebe.brooks@alaska.gov
Hilcorp
Tested with 5" drill pipe.
0
James Lott
0
670-3094
TEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
PBU L-293
Form 10-425 (Revised 05/2021)2023-0319_Diverter_Hilcorp_Innovation_PBU_L-293
Hilcorp North Slope LLC=======jbr
J. Regg
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 100
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L-293
Hilcorp North Slope, LLC
Permit to Drill Number: 223-020
Surface Location: 2287’ FSL, 4077’ FEL, Sec. 34, T12N, R11E, Umiat
Bottomhole Location: 1373’ FNL, 2188’ FEL, Sec. 19, T12N, R11E, Umiat
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
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 March, 2023.
1a.
Contact Name:Joe Engel
Contact Email:jengel@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8395
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated
from without prior written approval.
Drill
Type of Work:
Redrill
Lateral
1b.Proposed Well Class:Exploratory - Gas Service - WAG 1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple ZoneExploratory - Oil
Gas Hydrates
Geothermal
Hilcorp North Slope, LLC Bond No. 107205344
11.Well Name and Number:
PBU L-293
TVD:19938'4054'
12. Field/Pool(s):
MD:
ADL 028239, 047449 & 047446
00-001 March 22, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
2287' FSL, 4077' FEL, Sec. 34, T12N, R11E, UM, AK
1304' FNL, 1502' FEL, Sec. 29, T12N, R11E, UM, AK
Kickoff Depth:300 feet
Maximum Hole Angle: 91 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:1793 1386
17.Deviated wells:16.
Surface: x- y- Zone -582841 5978005 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
74.0'
47.5'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
1704'
Surface
4053'
19.PRESENT WELL CONDITION SUMMARY
Production
Surface
Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Shallow Hazard Analysis
Commission Use Only
See cover letter for other
requirements:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No
H2S measures Yes No
Spacing exception req'd: Yes No
Mud log req'd: Yes No
Directional svy req'd: Yes No
Inclination-only svy req'd: Yes No
Other:
Date:
Address:
Location of Well (State Base Plane Coordinates - NAD 27):
129.5#
11700'8238'
50-
Intermediate
Conductor/Structural
Single Zone
Service - Disp
NoYesPost initial injection MIT req'd:
NoYes
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
1373' FNL, 2188' FEL, Sec. 19, T12N, R11E, UM, AK
Time v. Depth PlotDrilling Program
4731'
Stg 2 L - 672 sx / T - 268 sx
(To be completed for Redrill and Re-Entry Operations)
6-1/8"
7"
L-8012.6#4-1/2"
9-5/8"
4078'
12-1/4"
12000'179 sx Class G
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stratigraphic Test
Development - Gas Service - Supply
Coalbed Gas
Shale Gas
2.Operator Name:5.Bond Blanket Single Well
3.
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
6. Proposed Depth:
7. Property Designation (Lease Number):
8. DNR Approval Number:13.Approximate spud date:
9. Acres in Property: 14. Distance to Nearest Property:
Location of Well (Governmental Section):
4b.
7467
3660'
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
12-1/4"
8-1/2"
9-5/8" 47#
40#
29#
L-80
L-80
L-80 Vam 21
TXP
VamTop
Hyd 563
2500'
3550'
12000'
Surface
2500'
Surface
2500'
6050'
19938'
1704'
2616'
4054'
Stg 1 L - 441 sx / T - 395 sx
Uncemented Slotted Liner
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):
Junk (measured):
Casing Length Size MD
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
110'110'Driven 20"X-56 80'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
PRUDHOE BAY FIELD
SCHRADER BLUFF OIL POOL
ORION DEVELOPMENT AREA
3.9.2023
By Samantha Carlisle at 10:03 am, Mar 09, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.03.09 07:01:14 -09'00'
Monty M
Myers
x
MGR16MAR2023
x
x
* BOPE test to 3000 psi. Annular to 2500 psi. x x
x
029-23749-00-00
* Variance to 20 AAC 25.412(b) Approved for packer placement
to be greater than 200' from top of perforations. Packer to be
placed within the reservoir to assure monitorable IA so
injection remains in zone. * LWD data for 8-1/2" OH to AOGCC to confirm requirment of TOC on 7" casing.
* State to witness MIT-T and MIT-IA to 3500 psi.
MDG 3/14/2023
223-020
1386
x
DSR-3/9/23
Well Name PTD API Status
Top of Oil Pool
(SB NB, MD)
Top of Oil Pool
(SB NB, TVD)Top of Cmt (MD) Top of Cmt (TVD)
Zonal
Isolation Comments
PBU NWE2-01 198-035 50-029-22866-00-00
Suspended
Exploration 4068' 4021' 2664' 2664' Closed
Suspended Exploration Well.
9-5/8" cemented in two
stages. 1st stage 89.7bbls
through shoe, 2nd stage
524bbls through stage collar
at 7,418' MD
PBU I-100PB1 205-010 50-029-23245-00-00
Suspended
Development 7253' 4102' 4956' 3489 Closed
Plugged back open hole with
3 cement plugs, TOC of each
plug verified by cement
returns during circulation.
PBU 33-29E 170-010 50-029-20060-00-00
Plugged and
Abandoned 4068' 4068' 2202' 2202' Closed
1970 Exploration well drilled
by SOCAL. 9-5/8" casing shoe
set at 9,383' and cemented
with 1323 cu. ft. with 8% gel.
Followed by 250sx of cement.
Second stage cemented
through DV collar at 2,699'
with 300sx class G cement.
Cement excess noted in
records during cleanout.
Additional 415sx squeeze
conducted at 6848', and
another 800sx squeeze at
3582'. Based on squeeze
volumes at 3582' and OH
volumes + 30% washout from
the DV collar at 2,699' its
assumed bottom of cement is
~6,228'
Area of Review PBU L-293
Prudhoe Bay West
(PBU) L-293
Permit to Drill Application
Version 1
3/5/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 13-5/8 5M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4 Hole Section ........................................................................................................ 14
12.0 Run 9-5/8 Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8 Surface Casing ................................................................................................. 23
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 28
15.0 Drill 8-1/2 Hole Section .......................................................................................................... 29
16.0 Run & Cement 7 Intermediate Casing .................................................................................. 32
17.0 Drill 6-1/8 Hole Section .......................................................................................................... 37
18.0 Run 4-1/2 Injection Liner ...................................................................................................... 42
19.0 Run Upper Completion/ Post Rig Work ................................................................................. 46
20.0 Innovation Rig Diverter Schematic ......................................................................................... 50
21.0 Innovation Rig BOP Schematic ............................................................................................... 51
22.0 Wellhead Schematic ................................................................................................................. 52
23.0 Days Vs Depth .......................................................................................................................... 53
24.0 Formation Tops & Information............................................................................................... 54
25.0 Anticipated Drilling Hazards .................................................................................................. 56
26.0 Innovation Rig Layout ............................................................................................................. 62
27.0 FIT Procedure .......................................................................................................................... 63
28.0 Innovation Rig Choke Manifold Schematic ............................................................................ 64
29.0 Casing Design ........................................................................................................................... 65
30.0 MASP ....................................................................................................................................... 66
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 68
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 69
Page 2
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU L-293
Pad Prudhoe Bay L Pad
Planned Completion Type 4-1/2 Injection
Target Reservoir(s) Schrader Bluff NB Sand
Planned Well TD, MD / TVD 19,938 MD / 4,054 TVD
PBTD, MD / TVD 19,928 MD / 4,054 TVD
Surface Location (Governmental) 2287' FSL, 4077' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582,840.6, Y= 5,978,004.6
Top of Productive Horizon
(Governmental)1304' FNL, 1502' FEL, Sec 29, T12N, R11E, UM, AK
TPH Location (NAD 27) X=574,746.3, Y= 5,984,887.6
BHL (Governmental) 1373' FNL, 2188' FEL, Sec 19, T12N, R11E, UM, AK
BHL (NAD 27) X= 568,733, Y= 5,990,040
AFE Drilling Days 32
AFE Completion Days 2
Maximum Anticipated Surface
Pressure (intermediate) 1386 psi
Maximum Anticipated Surface
Pressure (production) 1386 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 1793 psig
Work String 5 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 47.1 ft = 73.6 ft
GL Elevation above MSL: 47.1 ft
BOP Equipment 13-5/8 x 5M Annular, (3) ea 13-5/8 x 5M Rams
Page 3
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20 19.25- - - X-52 Weld
12-1/49-5/8 8.8358.67910.62540 L-80 TXP 5,750 3,090 916
9-5/8 8.6818.52510.62547 L-80 VAM 21 6,870 4,750 1,086
8-1/2 7 6.184 6.125 7.644 29 L-80 VamTop 8,160 7,030 676
6-1/8 4-1/2 3.958 3.833 5.2 12.6 L-80 H563 8,430 7,500 288
Tubing 4-1/2 3.958 3.833 5 12.6 L-80 JFE BEAR 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Intermediate
54.2763.25 6.62519.5 S-135 DS50 36,100 43,100 560klb
54.2763.25 6.62519.5 S-135 NC50 30,730 34,136 560klb
Production 43.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
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
_____________________________________________________________________________________
Revised By: JLS 3/8/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-293
Last Completed: TBD
PTD: TBD
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 110 N/A
9-5/8 Surface 47 / L-80 / VAM 21 8.525 Surface 2,500 0.0732
9-5/8 Surface 40 / L-80 / TXP 8.679 2,500 6,050 0.0758
7 Intermediate 29 / L-80 / VT 6.184 Surface 12,000 0.0371
4-1/2 Liner 12.6 / L-80 / Hyd 563 3.958 11,700 19,938 0.0152
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / JFE-B 3.958 Surface 11,700 0.0152
JEWELRY DETAIL
No. MD Item ID
1 ~5,600 X Nipple 3.813
2 ~11,390 X Nipple 3.813
3 ~11,450 4-1/2 HES TNT Production Packer 3.865
4 ~11,500 X Nipple 3.725
5 ~11,700 Liner Hanger 4.890
6 ~11,700 Hanger Packer 6.180
7 19,938 Shoe 3.800
4-1/2 SLOTTED LINER DETAIL 40 JTS with 10 Slots
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
1 TBD TBD TBD TBD
16 TBD TBD TBD TBD
GENERAL WELL INFO
API: TBD
Completion Date: TBD
TD =19,938(MD) / TD =4,054(TVD)
4
20
Orig. KB Elev.: 74.0 / GL Elev.: 47.5
7
5
4
7
9-5/8
1
2
3
See
Slotted
Liner
Detail
PBTD =19,938(MD) / PBTD =4,054(TVD)
7 5, 612
4-1/2
3
2
4-1/2
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8 5M Cameron Wing
Wellhead FMC 11 5K x sliplock bottom w/ (2) 2-1/16 5K outs
OPEN HOLE / CEMENT DETAIL
Driven 20 Conductor
12-1/4Stg 1 Lead 441 sx / Tail 395 sx
Stg 2 Lead 672 sx / Tail 268 sx
8-1/2 Tail 179 sx
6-1/8 Uncemented Slotted Liner
WELL INCLINATION DETAIL
KOP @ 300
90° Hole Angle = @ 12,100
Page 7
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-293 is a grassroots injector planned to be drilled in the Schrader Bluff NB sands. L-293 is part of a
multi-well program targeting the Schrader Bluff sand on PBU L-pad
The directional plan is 12-1/4 surface hole and 9-5/8 surface casing set below the SV1. 8-1/2 intermediate
hole will be drilled into the top of the Schrader Bluff NB sand, with 7 casing ran and cemented. A 6-1/8
lateral section will be drilled. A 4-1/2 slotted liner will be run in the open hole section, followed by 4-1/2
injection tubing. This well will not be pre-produced prior to being on injection.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately March 20, 2023, pending rig schedule.
Surface casing will be run to 6,050 MD / 2,616 TVD and cemented to surface via a two stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point B pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8 Diverter and 16 diverter line
3. Drill 12-1/4 hole to TD of surface hole section. Run and cement 9-5/8 surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8 5M BOP & Test
5. Drill 8-1/2 to section TD, Run and cement 7 casing
6. Drill 6-1/8 lateral to well TD
7. Run 4-1/2 liner
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface & Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
p
This well will not be pre-produced prior to being on injection.
Page 8
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-293. 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).
Page 9
Prudhoe Bay West
L-293 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states:
A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates
pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure
that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the
maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured
depth above the top of the perforations, unless the commission approves a different placement depth as the
commission considers appropriate given the thickness and depth of the confining zone.
In order to effectively produce this fault block, the current wellplan has the intermediate casing shoe landing at
the NB production interval at 90 degrees inclination. The production packer is planned to be set ~ 400 MD above
the liner top packer, ~ 550 MD above the 7 casing shoe to allow for spacing of the x nipple beneath it at a pump
downable depth at 75* inclination. The intermediate casing shoe is planned at ~12,000 MD / 4078 TVD which
means the planned packer depth is ~550 MD away. From a TVD standpoint, the production tubing packer is ~70
TVD from the intermediate casing shoe. With the intermediate casing set in the Schrader Bluff sand, and the
injection packer set inside the intermediate casing, injection fluids will be confined to the Schrader bluff sands.
g q
Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states:
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Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/413-5/8 5M CTI Annular BOP w/ 16 diverter line Function Test Only
8-1/2 & 6-1/8
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-293 will utilize a 20 conductor on L-pad. Ensure to review attached surface plat and make
sure rig is over appropriate conductor.
9.2 Ensure PTD, COAs, and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4 nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4 surface hole section. Ensure mud temperatures are cool (<80 F).
Cold mud temps are necessary to mitigate hydrate breakout
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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Drilling Procedure
10.0 N/U 13-5/8 5M Diverter System
10.1 N/U 13-5/8 CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
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 with 24 hour notice to witness. 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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Drilling Procedure
10.4 Rig & Diverter Orientation:
May change on location
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Drilling Procedure
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 below the SV1 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.
Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
Gas hydrates have been seen at L-Pad
n TD below the SV1 sand.
Gas hydrates have been seen at L-Pad
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Drilling Procedure
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
Prelim L-232 wp03 is a planned well in the database, and has not been drilled
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 drillers 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.
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 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
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Drilling Procedure
Surface 8.8 9.8 75-175 20 - 40 25-45 <10 8.5 9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 9.0 pH)
as needed
as required for 8.8 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity. Observe well for flow.
11.6 RIH to bottom, proceed to BROOH to HWDP
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.
11.7 TOOH and LD BHA
11.8 No wireline 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
Actual depth to be dependent upon base of permafrost and stage tool
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns 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 coreclty installed on top of float collar
Ensure proper operation of float equipment while picking up.
Ensure to record S/Ns of all float equipment and stage tool components.
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Drilling Procedure
12.5 Float Equipment and Stage tool equipment drawings
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Drilling Procedure
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:
Bowspring Centralizers only
1 centralizer every joint to ~ 1000 MD from shoe
1 centralizer every 2 joints to ~ 2,000 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.
9-5/8 47# L-80 VAM21 Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/828,400 ft-lbs 31,550 ft-lbs 34,650 ft-lbs
9-5/8 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/818,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
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L-293 SB Injector
Drilling Procedure
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Drilling Procedure
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Drilling Procedure
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100 TVD below
the permafrost (~ 2,500 MD, actual depth based upon base of permafrost)
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.
12.8 Continue running 9-5/8 surface casing
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 Centralizers 1/jt for 5 joints above and below stage tool.
Confirm stage tool depth compatibility with cancellation plug, inclination sensitive
12.10 The last 2,500 of 9-5/8 will be 47#, from 2,500 to Surface
Actual length of 47# may change due to depth of permafrost as drilled
Ensure drifted to 8.525
12.11 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary. Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10 from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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Drilling Procedure
13.0 Cement 9-5/8 Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
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 Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Casing (6,050'-1,000'-2,500') x 0.0558 bpf x 1.3 184.9 1037.4
Total Lead 184.9 1037.4 441.4
12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.7
9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.1
Total Tail 81.6 457.8 394.6
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L-293 SB Injector
Drilling Procedure
Cement Slurry Design (1st Stage Cement Job)
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets sticky, cease pipe reciprocation and continu
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5 liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
2500 x 0.0732 bpf + (6,050-120-2500) x .0758 bpf =
= 443.1 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mixed
Water 13.92 gal/sk 4.98 gal/sk
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Drilling Procedure
13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.15 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher
pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or
cement returns to surface and volume pumped to see the returns. Circulate until YP < 20
again in preparation for the 2nd stage of the cement job.
Ensure the free fall stage tool opening plug is available. This is the back-up option to open
the stage tool if the plugs are not bumped.
13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the
shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to
assist. Ensure to flush out any rig components, hard lines and BOP stack that may have
come in contact with the cement.
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Drilling Procedure
Second Stage Surface Cement Job
13.17 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.19 Fill surface lines with water and pressure test.
13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.21 Mix and pump cmt per below recipe for the 2
nd stage.
13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. Cement will continue to be pumped until
clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4
12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 3 316.4 1775.0
Total Lead 345.0 1935.5 672.0
12-1/4" OH x 9-5/8" Casing (2500 - 2000' x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6
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Drilling Procedure
13.25 Displacement calculation:
2500 x 0.0732 bpf = 183 bbls mud
13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.27 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.28 Land closing plug on stage collar and pressure up to 1,000 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has
closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set
slips.
13.29 Make initial cut on 9-5/8 final joint. L/D cut joint. Make final cut on 9-5/8. Dress off stump. Install
9-5/8 wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
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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Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 Give AOGCC 24hr notice of BOPE test, for test witness.
14.2 ND the diverter T, knife gate, diverter line & NU 11 x 13-5/8 5M casing spool.
14.3 NU 13-5/8 x 5M BOP as follows:
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 4-1/2 x 7 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.
14.4 RU MPD RCD and related equipment
14.5 Run 5 BOP test plug
14.6 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
Test with 5 test joint and test VBRs with 4-1/2 and 5 test joints
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
14.7 RD BOP test equipment
14.8 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.9 Mix 9.5 ppg spud mud to be used in intermediate hole
14.10 Set wearbushing in wellhead.
14.11 If needed, rack back as much 5 DP in derrick as possible to be used while drilling the hole
section.
14.12 Ensure 5 liners in mud pumps.
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Drilling Procedure
15.0 Drill 8-1/2 Hole Section
15.1 P/U 8-1/2 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.
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 intermediate hole section.
15.2 TIH to TOC above the shoetrack. Note depth TOC tagged on morning report.
15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and
volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin
17-001.
15.4 Drill out shoe track and 20 of new formation.
15.5 CBU and condition mud for FIT.
15.6 Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
11.5 ppg provides >25 bbls based on 9.5ppg MW, 8.46 ppg PP (swab kick at 8.46 ppg BHP).
15.7 Drill 8-1/2 hole section to section TD in the Schrader NB sand. Confirm this setting depth with
the Geologist and Drilling Engineer while drilling the well.
Efforts should be made to minimize dog legs. Keep DLS < 6 deg / 100.
Hold a safety meeting with rig crews to discuss:
Well control procedures
Flow rates, hole cleaning, etc.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
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.
Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a ~9.5 by
TD.
Intermediate Hole AC:
There are no wells with a clearance factor of <1.0
Casing test and FIT digital data to AOGCC immediately upon completion of FIT. email: melvin.rixse@alaska.gov
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Drilling Procedure
15.8 8-1/2 hole 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 same ppg as
surface TD MW and ensure we TD with 9.5+ ppg.
Depth Interval MW (ppg)
Surface shoe - TD 9.5+
PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the drillers 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.
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 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 9.8 75-175 20 - 40 25-45 <10 8.5 9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
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
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Drilling Procedure
ALDACIDE G 0.1 ppb
15.9 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
15.10 RIH to bottom, proceed to BROOH to surface casing shoe
Pump at full drill rate 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.
15.11 CBU at casing shoe
15.12 TOOH and LD BHA
15.13 No wireline logging program planned
LWD Gamma-ray and Resistivity data to AOGCC promptly to confirm required location
for TOC on 8-1/2" OH x 7" annulus.
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Drilling Procedure
16.0 Run & Cement 7 Intermediate Casing
16.1 R/U and pull wearbushing.
16.2 R/U 7 casing running equipment (CRT & Tongs)
Ensure 7 VamTop 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.
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
Plan to land the 7 casing on a mandrel hanger.
16.3 P/U shoe joint, visually verify no debris inside joint.
16.4 Continue M/U & thread locking 120 shoe track assembly consisting of:
7 Float Shoe
1 joint 7, 2 Centralizers 10 from each end w/ stop rings
1 joint 7, 1 Centralizer mid joint w/ stop ring
1 joint 7, 1 Centralizer mid joint with stop ring
7 Float Collar
16.5 Continue running 7 intermediate casing
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 ~ 500 MD above Schrader Bluff
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.
7 29# L-80 VamTop Make-Up Torques:
Casing OD Minimum Optimum Maximum
78,460 ft-lbs 9,400 ft-lbs 10,340 ft-lbs
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Drilling Procedure
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16.6 Continue running 7 casing
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
16.8 Slow in and out of slips.
16.9 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10 from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
16.10 Lower casing to setting depth. Confirm measurements.
16.11 Have emergency slips staged along with necessary equipment for the operation.
16.12 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
16.13 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
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.
16.14 Document efficiency of all possible displacement pumps prior to cement job.
16.15 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
16.16 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
16.17 Fill surface lines with water and pressure test.
16.18 Pump 60 bbls 11 ppg tuned spacer.
16.19 Mix and pump cmt per below recipe.
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16.20 Cement volume based on annular volume + open hole excess (40%). Job will consist of tail,
TOC brought to 1000 above the Schrader Bluff (Note: TOC will be adjusted to 500 above
Ugnu hydrocarbon bearing zone if Ugnu contains significant hydrocarbons).
Estimated Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
16.21 After pumping cement, drop top plug and displace cement with mud out of mud pits.
16.22 Monitor returns closely while displacing cement. Adjust pump rate if necessary.
16.23 Land top plug on stage collar and pressure up to 500 psi over bump pressure. Bleed pressure and
check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement
builds compressive strength.
Ensure to report the following on wellez:
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
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
8.5" OH x 7" (12,000 - 10,975)' x 0.0226 bpf x 1.4 = 32.4 181.8
7" Shoetrack 120' x 0.0372 bpf = 4.5 25.2
Total Tail 36.9 207.0 178.5
Tail Slurry
System HalCem
Density 15.8 lb/gal
Yield 1.17 ft3/sk
Mixed
Water 5.08 gal/sk
( ) ,
TOC will be adjusted to 500 aboveg( j
Ugnu hydrocarbon bearing zone if Ugnu contains significant hydrocarbons)
Displacement (12000-120) * .0372 = 441 bbls mgr
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Add any comments which would describe the success or problems during the cement job
Send final As-Run casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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Drilling Procedure
17.0 Drill 6-1/8 Hole Section
17.1 MU 6-1/8 Cleanout BHA (Milltooth Bit & 1.22° PDM)
17.2 TIH w/ 6-1/8 cleanout BHA to float collar with 4 dp
17.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and
volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin
17-001.
17.4 Drill out shoe track and 20 of new formation.
17.5 CBU and condition mud for FIT.
17.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
12.0 ppg desired to cover shoe strength for expected ECDs. A 9.7 ppg FIT is the minimum
required to drill ahead
9.8 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5ppg BHP)
17.7 POOH and LD cleanout BHA
17.8 PU 6-1/8 directional BHA.
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 4 14# XT39
Run a ported float in the production hole section.
17.9 6-1/8 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
7" casing test and FIT digital data to AOGCC upon completion of FIT. Email: melvin.rixse@alaska.gov
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Drilling Procedure
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
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 drillers console, Co Man office, &
Toolpusher office.
System Type:8.9 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total
Solids
MBT HPHT Hardness
Production 8.9-9.5 15-25 -
ALAP
15 - 30 4-6 <10% <8 <11.0 <100
System Formulation:
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
17.10 TIH with 6-1/8 directional assembly to bottom
17.11 Install MPD RCD
17.12 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
Density may change based upon TD of surface hole section
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Drilling Procedure
17.13 Begin drilling 6-1/8 hole section, on-bottom staging technique:
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 6-1/8 hole section to section TD per Geologist and Drilling Engineer.
Flow Rate: 150-250 GPM, target min. AVs 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.
Use ADR to stay in section. Reservoir plan is to stay in NB sand.
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
Schrader Bluff NB Concretions: 4-6% Historically
MPD will be utilized to monitor pressure build up on connections.
6-1/8 Lateral A/C:
There are no wells with CF < 1.0
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
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.
Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV and rotation (120+ RPM). Pump tandem sweeps if
needed
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Drilling Procedure
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 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
17.14 Monitor the returned fluids carefully while displacing to brine.
15.19 BROOH with the drilling assembly to the 7 casing shoe
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
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 7 shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
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Drilling Procedure
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
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
18.0 Run 4-1/2 Injection Liner
18.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner, the following well control response procedure will be followed:
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.
18.2 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 ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
18.3 Run 4-1/2 injection liner
4-1/2 liner will be floated to bottom for improved T&D. Liner will be isolated by float shoe
and float collar at the toe, closed NCS sleeves along liner length and the Airlock buoyancy
system at top of liner.
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
18.4 Ensure to run enough liner to provide for setting the liner hanger at ~ 11,850 MD
Confirm set depth with completion engineer.
18.5 Ensure hanger/pkr will not be set in a 7 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 7 connection.
18.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
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Drilling Procedure
18.7 M/U Baker SLZXP liner top packer to 4-1/2 liner.
18.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
18.9 RIH with liner no faster than 30 ft/min this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
Ensure 5 DP/HWDP has been drifted
Fill drill pipe on the fly above the Airlock Bouyancy system. Monitor FL and if filling is
required due to losses/surging.
18.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
18.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
18.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
18.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
18.14 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
18.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
18.16 Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
18.17 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
18.18 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
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Drilling Procedure
18.19 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
18.20 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
18.21 PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
18.22 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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Drilling Procedure
19.0 Run Upper Completion/ Post Rig Work
19.1 RU to run 4-1/2, 12.6#, L-80 JFEBear tubing.
Ensure wear bushing is pulled.
Ensure 4-1/2, L-80, 12.6#, JFEBear x NC50 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 ODs, IDs, lengths, SNs of all components with vendor & model info.
Monitor displacement from wellbore while RIH.
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Drilling Procedure
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Drilling Procedure
19.2 PU, MU and RH with the following 4-1/2 injection completion jewelry (tally to be provided by
Operations Engineer):
Tubing Jewelry to include:
1x X Nipple
1x X Nipple w/ sliding sleeve
1x Production Packer
1x X Nipple
XXX joints, 4-1/2, 12.6#, L-80, JFEBear
X1 WLEG, set as close to 7 x 4-1/2 liner xo as possible
19.3 PU and MU the 4-1/2 tubing hanger.
19.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
19.5 Land the tubing hanger and RILDS. Lay down the landing joint.
19.6 Install 4 HP BPV. ND BOP. Install the plug off tool.
19.7 NU the tubing head adapter and NU the tree.
19.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
19.9 Pull the plug off tool and BPV.
19.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel
freeze protect for both tubing and IA to 2,500 MD.
19.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburtons setting procedure
19.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
i. Note this test must be witnessed by the AOGCC representative.
ii. Notify wells group coordinator prior to performing,
1. Contact number: 659-5102
2. pbwellsintegrity@hilcorp.com
19.13 Bleed both the IA and tubing to 0 psi.
19.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
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19.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
19.16 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
2. Fullbore
a. Shear hydraulic toe port
3. Coil
a. Shift injection sleeves open
4. Well Tie in
5. Put well on injection
a. AOGCC witnessed MIT-IA once injection is stable
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Drilling Procedure
20.0 Innovation Rig Diverter Schematic
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Drilling Procedure
21.0 Innovation Rig BOP Schematic
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Drilling Procedure
22.0 Wellhead Schematic
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Drilling Procedure
23.0 Days Vs Depth
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Drilling Procedure
24.0 Formation Tops & Information
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Drilling Procedure
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25.0 Anticipated Drilling Hazards
12-1/4 Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
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 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.
Surface Hole AC:
There are no wells with a clearance factor of <1.0
Prelim L-232 wp03 is a planned well in the database, and has not been drilled
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs.
PBU L-pad has a history of H2S
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Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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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.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
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Prudhoe Bay West
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Drilling Procedure
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Gas Cut Mud
Gas cut mud as been seen on L pad, ensure sufficient MW is used during hole section. Ensure gas
detectors are always functioning. Watch swab effect.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Casing Running
Casing running issue have been noted on L pad, gravels, stability wood chunks, etc. Watch casing run,
and ensure to condition hole prior to running casing, ex: backream trouble intervals.
8-1/2 Section specific A/C:
There are no wells with a CF <1.0
Gas Cut Mud
Gas cut mud as been seen on L pad, ensure sufficient MW is used during hole section. Ensure gasp ,
detectors are always functioning. Watch swab effect.
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Prudhoe Bay West
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Drilling Procedure
6-1/8 Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole.
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs.
4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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Prudhoe Bay West
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Drilling Procedure
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
6-1/8 Lateral A/C:
There are no wells with a CF <1.0
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Drilling Procedure
26.0 Innovation Rig Layout
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Drilling Procedure
27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
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Drilling Procedure
28.0 Innovation Rig Choke Manifold Schematic
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Drilling Procedure
29.0 Casing Design
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Drilling Procedure
30.0 MASP
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31.0 Spider Plot (NAD 27) (Governmental Sections)
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32.0 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 no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
X
X
223-020
Schrader Bluff Oil
PBU L-293
Prudhoe Bay Field
X
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN ORIN L-293Initial Class/TypeSER / WAGINGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230200PRUDHOE BAY, SCHRADER BLUF OIL - 64013NA1 Permit fee attachedYes Surface Location lies within ADL028239; Top Productive Interval lies in ADL047449; TD lies in ADL047446.2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 026 B applies.14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes PBU 33-29E (170-001), PBU I-100Pb1 (205-010), PBU NWE2-01 (198-035), (-),15 All wells within 1/4 mile area of review identified (For service well only)No page 11 of PTD states "This well will not be pre-produced prior to being on injection."16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20' 129.5# X-56 driven to 110'18 Conductor string providedYes 9-5/8" surface casing set just below the SV1 sand19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes 2 stage surface casing cement job. 300% excess across the permafrost21 CMT vol adequate to tie-in long string to surf csgYes 7" casing to be cemented to 500' above the UGNU.22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan recognizes no close approaches to drilled wells.26 Adequate wellbore separation proposedYes 16" diverter line below BOPE27 If diverter required, does it meet regulationsYes All fluids overbalanced to pore pressure28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram, 1 flow cross 29 BOPEs, do they meet regulationYes 5M 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)Yes32 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 PBU L-Pad Schrader Bluff wells have measured H2S >20 ppm. H2S measures required.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprMDGDate3/14/2023ApprMGRDate3/16/2023ApprMDGDate3/14/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate
