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Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
06/01/2023
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 6/1/2023.
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 6/1/2023.
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
Hilcorp North Slope LLC.Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-offReport of Sundry Operations (10-404)06/01/2023Well NamePTD #API #Initial top of cement (ft)Vol. of cement pumped (gal)Final top of cement (ft)Cement top off date Corrosion inhibitor (gal)Corrosion inhibitor/ sealant dateL-2072210815002923702003.371.31/23/2023123/1/2023L-2312230105002923746003.003.0-393/27/2023M-111810575002920589002.602.6-105/29/2023M-311920325002922256001.501.5-165/29/2023M-331941165002922504001.301.3-145/29/2023N-171830095002920898001.201.2-115/30/2023N-18A2081755002920906010.500.5-65/30/2023N-21A1961965002921342011.001.0-85/30/2023N-272071045002923365000.500.5-45/30/2023N-292141105002923521002.302.3-245/30/2023N-31215175500292356000-0--205/30/2023V-2342220045002923707006.3210.91/23/2023243/1/2023W-2412221545002923741002.502.5-263/1/2023Z-121891025002921977000.700.7-45/23/2023Z-34212061500292346900-0--155/27/2023Z-402111735002923462000.700.7-65/27/2023Z-46A2052035002923280010.500.5-35/23/2023Z-502120015002923463000.500.5-35/27/2023Z-662121955002923482000.700.7-85/27/2023Z-116211124500292345500-0--175/27/2023Z-210204181500292322600-0--125/27/2023Z-2292221045002923726003.8361.23/5/2023363/27/2023L-2312230105002923746003.003.0-393/27/2023
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: 04/06/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
PBU L-231
PTD: 223-010
API: 50-029-23746-00-00
FINAL LWD FORMATION EVALUATION LOGS (03/03/2023 to 03/13/2023)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Geosteering and EOW Report
SFTP Transfer – Main Folders:
PBU L-231 Final LWD Subfolders:
PBU L-231 Final Geosteering Subfolders:g
Please include current contact information if different from above.
PTD: 223-010
T37583
Kayla Junke
Digitally signed by
Kayla Junke
Date: 2023.04.06
13:42:05 -08'00'
PRUDHOE BAY FIELD /
SCHRADER BLUFF OIL POOL, ORION DEV AREA
7"x4-1/2"
By James Brooks at 10:11 am, Mar 29, 2023
Completed
3/18/2023
JSB
RBDMS JSB 040623
GDSR-4/14/23MGR03AUG2023
3.29.2023
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: 2023.03.29 06:48:39 -08'00'
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-231 Date:3/11/2023
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Lott/Montague
Csg Setting Depth:5901 TMD 4226 TVD
Mud Weight:9.1 ppg LOT / FIT Press =670 psi
LOT / FIT =12.15 ppg Hole Depth =5931 md
Fluid Pumped=1.5 Bbls Volume Back =1.1 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
->4 120 ->8230
->8 241 ->16 455
->12 342 ->24 670
->16 413 ->30 855
->20 502 ->35 1040
->24 598 ->40 1220
->27 670 ->45 1420
-> ->50 1605
-> ->55 1790
-> ->60 2005
-> ->65 2185
-> ->70 2395
-> ->80 2735
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 670 ->0 2735
->1 645 ->1 2734
->2 632 ->2 2733
->3 621 ->3 2733
->4 612 ->4 2732
->5 600 ->5 2732
->6 565 ->10 2730
->7 530 ->15 2726
->8 513 ->20 2722
->9 499 ->25 2720
->10 484 ->30 2715
-> ->
-> ->
-> ->
0
4
8
12
16
20
24
27
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8
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45
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65
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0 102030405060708090
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e
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Strokes (# of)
LOT / FIT DATA CASING TEST DATA
670645632621612600565530513499484
273527342733273327322732 2730 2726 2722 2720 2715
0
100
200
300
400
500
600
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800
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0 5 10 15 20 25 30
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Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
3/1/2023 Spot sub base over L-231. Remove steering arms and hitch from sub base. Level and shim sub-base. Spot and level catwalk. Spot pipe shed, mud mod and gen
mod.
3/2/2023 Rig up interconnects. Get steam, air, water around rig. Scope up derrick and R/D bridle lines. Start working on rig acceptance checklists. NES rig move trucks
released at 06:30. On generator power at 07:15. N/U diverter stack. P/U and remove MPD head. Install diverter 'T' and stack. Connect diverter vent line. Work on rig
acceptance checklist. Install bell nipple and tiser. Obtain RKB's. Install hydraulic elevators. Sim Ops put pumps together. Replace bearing/rollers in drag chain.
Cont. working on rig acceptance checklist. Monthly TD inspection. Open BOP ram doors and inspect cavities. Stamp rams for BOP maintenance during rig moves.
Continue working on rig acceptance checklist. Verify serial numbers on rams, inspect rubbers and close up doors.
Install rotary mouse hole. Inspect accumulator, pipe skate, FH-80. Function test both mud pumps. Rig accepted at 03:00. Pick up, drift (3.125") and rack back 90
joints 5" drill pipe. 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 0 bbls, total 550 bbls.
3/3/2023 Continue picking up, drifting and racking back total of 184 joints of drill pipe, 8 stands HWDP and 1 HWDP/jar stand. L/D rotary mouse hole. Install short mouse
hole. Perform diverter test, witness waived by Austin McLeod. Test gas alarms, PVT and return flow. Knife valve open in 6 seconds, annular close in 13 seconds.
Accumulator drawdown initial pressure 2950 psi, after functioning, 1950 psi. First 200 psi recharge 17 sec, full 53 sec. (6)N2 at 2283 psi average. Pre-spud
meeting. M/U 12-1/4" bit, mud motor and XO. Fill conductor and surface lines. PT surface lines to 3000 psi - good. Wash down from 36' and tag at 107'. 150 gpm,
80 psi. Spud well. Drill 12-1/4" hole from 107' to 220' at 350 gpm, 320 psi, 30 rpms, 1400ft-lbs, WOB 2-3K. P/U 46K, S/O 45K, ROTW 45K. Circulate bottoms up x
2 while backreaming stand to 155'. POOH. Bring BHA components to rig floor. Blow down top drive. M/U remaining BHA, GWD collar, DM collar, EWR-M5 collar,
TM collar. Measure RFO =334.32. Upload MWD. P/U and M/U NM flex collars, XO and HWDP. Continue drilling 12-1/4" surface hole from 220' to 282' at 350-400
gpm, 652 psi, WOB 2-5K, 30 rpms, 2-5Kft-lbs. P/U 55K, S/O 53K, ROTW 54K. Jet flow line continually. Pick up off bottom and pump through bleeder and clear out
flowline multiple times. Cont. drilling 12-1/4" surface hole from 282' to 702' (total 420', AROP 70fpm) 400-450 gpm, 1100 psi, WOB 4-10K, 30-80 rpms, 3Kft-lbs,
P/U 73K, S/O 68K, ROT 68K. Continually jet flow line, pump through bleeder as needed. Collect gyro surveys. Distance to WP4: 6.54', 3.88' High, 5.26' Left. Daily
Disposal to G&I 57 bbls, total 57 bbls. Daily Disposal to MP G&I 171 bbls, total 171 bbls. Daily water from Lake 2 570 bbls, total 1120 bbls. Daily DH losses 80 bbls,
total 80 bbls.
3/4/2023 Cont. drilling 12-1/4" surface hole from 702' to 1099' (total 397', AROP 66 fpm) 450-475 gpm, 1100 psi, WOB 3-10K, 80 rpms, 3-4Kft-lbs, P/U 77K, S/O 73K, ROT
75K. Continually jet flow line, pump through bleeder as needed. Last gyro survey at 868'. Backream 30'. Sliding as necessary for 4/100 build. Cont. drilling 12-1/4"
surface hole from 1099' to 1680' (total 581', AROP 97 fpm) 475 gpm, 1450 psi, WOB 3-10K, 80 rpms, 3-4Kft-lbs, P/U 83K, S/O 73K, ROT 75K. Cont. jet flow line,
pump through bleeder as needed. Backream 30'. Sliding as necessary for 4/100 build to tangent (~1445'). Cont. drilling 12-1/4" surface hole from 1680' to 2239'
(total 559', AROP 93 fpm) 525 gpm, 1566 psi, WOB 5-10K, 80 rpms, 5-8Kft-lbs, P/U 102K, S/O 76K, ROT 87K. max gas 3059u. Cont. jet flow line, pump through
bleeder as needed. Backream full stands. Maintenance slides as needed through tangent. Base of permafrost logged at 2015'. Hydrates initially noted at 2050' with
140u recorded. Change out gas trap at 2200' and observe gas increase from <100u to 1353u. Cont. drilling 12-1/4" surface hole from 2239' to 2811' (total 572',
AROP 95 fpm) 525 gpm, 1426 psi, WOB 4-10K, 80 rpms, 5-7Kft-lbs, P/U 111K, S/O 82K, ROT 93K. max gas 4251u. Cont. jet flow line, pump through bleeder as
needed. Backream full stands. Sliding as necessary for 4/100 build. Distance to WP4: 14.46', 13.8' high, 4.24' right. Daily Disposal to G&I 570 bbls, total 627 bbls.
Daily Disposal to MP G&I 684 bbls, total 855 bbls. Daily water from Lake 2 980 bbls, total 2100 bbls. Daily DH losses 0 bbls, total 80 bbls.
3/5/2023 Cont. drilling 12-1/4" surface hole from 2811' to 3321' (total 510', AROP 85 fpm) 475 gpm, 1433 psi, WOB 4-13K, 80 rpms, 6-9Kft-lbs, ECD 10.41 ppg, 9.5 ppg
mud, max gas 3562u. P/U 119K, S/O 87K, ROT 96K. Backream full stands. Sliding for 4/100 drop/turn. Observe oil on shakers at 3321'MD. Cont. drilling 12-1/4"
surface hole from 3321' to 3750' (total 429', AROP 72 fpm) 475 gpm, 1433 psi, WOB 6-18K, 80 rpms, 7-10Kft-lbs, ECD 9.93 ppg, 9.5 ppg mud, max gas 2322u.
P/U 135K, S/O 95K, ROT 106K. Backream full stands. Sliding for 4/100 build/turn. Cont. drilling 12-1/4" surface hole from 3750' to 4045' (total 295', AROP 49 fpm)
500 gpm, 1719 psi, WOB 8-23K, 80 rpms, 7-12Kft-lbs, ECD 10.13 ppg, 9.45 ppg mud, max gas 681u. P/U 144K, S/O 95K, ROT 115K. Backream full stands.
Sliding for 4/100 build/turn. Cont. drilling 12-1/4" surface hole from 4045' to 4400' (total 355', AROP 59 fpm) 525 gpm, 1836 psi, WOB 5-18K, 80 rpms, 10-12Kft-
lbs, ECD 10.38 ppg, 9.5 ppg mud, max gas 1334u. P/U 146K, S/O 97K, ROT 116K. Backream full stands. Sliding for 4/100 build/turn. Distance to WP4: 15.26',
10.9' high, 10.6' right. Daily Disposal to G&I 741 bbls, total 1368 bbls. Daily Disposal to MP G&I 456 bbls, total 1311 bbls
Daily water from Lake 2 980 bbls, total 3080 bbls. Daily DH losses 0 bbls, total 80 bbls.
3/6/2023 Cont. drilling 12-1/4" surface hole from 4400' to 4781' (total 381', AROP 64 fph) 525 gpm, 1515 psi, WOB 2-15K, 80 rpms, 11-14Kft-lbs, ECD 9.91 ppg, 9.5 ppg
mud, max gas 2329u. P/U 158K, S/O 96K, ROT 116K. Backream full stands. Sliding for 4/100 build/turn. Cont. drilling 12-1/4" surface hole from 4781' to 5115'
(total 334', AROP 56 fph) 525 gpm, 1836 psi, WOB 8-16K, 80 rpms, 12-16Kft-lbs, ECD 10.0 ppg, 9.5 ppg mud, max gas 899u. P/U 165K, S/O 94K, ROT 118K.
Backream full stands. Sliding for 4/100 build/turn. Cont. drilling 12-1/4" surface hole from 5115' to 5480' (total 365', AROP 61 fph) 525 gpm, 1940 psi, WOB 10-
14K, 80 rpms, 12-16Kft-lbs, ECD 10.14 ppg, 9.5 ppg mud, max gas 904u. P/U 166K, S/O 92K, ROT 115K. Backream full stands. Sliding for 4/100 build/turn. Cont.
drilling 12-1/4" surface hole from 5480' to TD at 5911' (total 431', AROP 72 fph) 525 gpm, 1825 psi, WOB 3-8K, 80 rpms, 11-13Kft-lbs, ECD 10.34 ppg, 9.5 ppg
mud, max gas 767u. P/U 155K, S/O 90K, ROT 111K. Backream full stands. Sliding for 4/100 build/turn. Distance to WP4: 2.19', 0.1' high, 2.19' Right. Daily
Disposal to G&I 1202 bbls, total 2570 bbls. Daily Disposal to MP G&I 0 bbls, total 1311 bbls. Daily water from Lake 2 980 bbls, total 4060 bbls. Daily DH losses 0
bbls, total 80 bbls.
50-029-23746-00-00API #:
Well Name:
Field:
County/State:
PBW L-231
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
3/3/2023Spud Date:
3/7/2023 Obtain final survey at 5911' TD. BROOH 2 stds. Work pipe from 5801' to 5610'. Pump Sweep and CBU x2 after Sweep. Sweep back 20 bbls late, minimal change
at shakers. RIH on elevators to 5911', no fill. ECD prior to circulating 10.2 ppg, after 9.97 ppg. Max Gas @ 2957u P/U 152K, SO 87K, Rot 113K. Monitor Well for 10
min. Static. BROOH @ 10-30 fpm from 5911' to 5037' at 525 gpm, 1647 psi, 80 rpms, 11Kft-lbs, P/U 165K, SO 94K, Rot 109K. See Minor Trq swings through slide
Intervals, slow pulling speed and wipe clean. Cont BROOH @ 15-30 fpm from 5037' to 2910'. at 525 gpm, 1480 psi, 80 rpms, Trq 10-11Kft-lbs, P/U 145K, SO 83K,
Rot 110K. See Minor Trq swings through slide intervals, slow pulling speed and wipe clean, no pack off or erratic Trq. Cont BROOH @ 15-35 fpm from 2910' to
719'. at 515 gpm, 1240 psi, 80 rpms, 4-12Kft-lbs, 9.9 ppg ECD, max gas 2492u. P/U 77K, SO 64K, Rot 98K. See Minor Trq swings through slide intervals. Slow
pulling speed 3 stands prior to base of permafrost and obtain 2 x BU. Service rig. Open TD coffin and investigate hydraulic leak. Tighten ORB plug. Grease TD,
blocks and crown. Attempt to POOH on elevators, unable to. Cont. BROOH from 719' to 347' at 400 gpm, 865 psi, 40 rpms, 7-10Kft-lbs. POOH on elevators from
347' to 158'. P/U 55K, S/O 55K. Monitor well, static. L/D BHA: XO, Flex collar. Plug in and download. L/D flex collar, TM, WER-M5, DM, GWD. Milk motor. PDC bit
grade: 1-3-BT-G-X-2-CT-TD. Tri-cone 1-1-WT-A-F-NO-TD. Clean and clear rig floor. Rig down hydraulic elevators, C/O bushings. Distance to WP4: 3.06', 1.38'
low, 2.73' right. Daily Disposal to G&I 1627 bbls, total 3197 bbls. Daily Disposal to MP G&I 0 bbls, total 1311 bbls. Daily water from Lake 2 600 bbls, total 4660
bbls. Daily DH losses 11 bbls, total 91 bbls.
3/8/2023 Cont. to rig up to run casing. R/U Parker TRS power tongs, install bail extensions and elevators. Verify pipe count in shed. M/U shoe track, Bakerlok, check floats -
good. Install by pass baffle. RIH with 9-5/8", 40#, L-80 BTC casing to 1826'. Fill pipe every 5 joints, break circulation to pits every 20 joints. Install centralizers as per
tally. P/U 92K, S/O 68K. Cont. RIH with 9-5/8", 40#, L-80 BTC casing from 1826' to 2200'. Fill pipe every 5 joints, break circulation to pits every 20 joints. Install
centralizers as per tally. P/U 116K, S/O 72K. Circulate bottoms up staging pumps up to 6 bpm, 139 psi, reciprocating pipe. max gas 816u. Cont. RIH with 9-5/8",
40#, L-80 BTC casing from 2200' to 3448'. RIH with 9-5/8", 47#, L-80, CDC casing from 3448' to 3747'. M/U ES cementer and RIH to 3886'. Fill pipe every 5 joints,
break circulation to pits every 20 joints. Install centralizers as per tally. P/U 179K, S/O 90K. Circulate bottoms up staging pumps up to 6 bpm, 250 psi, reciprocating
pipe. max gas 1436u. RIH with 9-5/8", 47#, L-80, CDC casing from 3886' to 5095', TQ connections to 19,500ft-lbs. M/U CDC x Vam21 crossover to 5124'. Fill pipe
every 5 joints, break circulation to pits every 20 joints. Install centralizers as per tally. P/U 240K, S/O 107K. Circulate bottoms up staging pumps up to 6 bpm, 162
psi, reciprocating pipe. max gas 81u. RIH with 9-5/8", 47#, L-80, Vam21 casing from 5124' to 5495', TQ connections to 31,550ft-lbs. Fill pipe every 5 joints, break
circulation to pits every 20 joints. Install centralizers as per tally. P/U 246K, S/O 117K. Cont. RIH with 9-5/8", 47#, L-80, Vam21 casing from 5495' to 5901', TQ
connections to 31,550ft-lbs. Wash last two stands down at 4 bpm, 105 psi. Fill pipe every 5 joints, break circulation to pits every 20 joints. Install centralizers as per
tally. P/U 270K, S/O 120K. Circulate hole clean, conditioning mud to <20YP. Stage pumps up to 7 bpm, 175 psi. Prep for cement job, thaw out side entry on Volant,
thaw out hose to Vac truck, thaw out 4" conductor valves, clear out dump line in pits. Thaw out circ line in HES cementer truck. Start circulating through cement line
at 6 bpm, 330 psi. Daily Disposal to G&I 689 bbls, total 3886 bbls. Daily Disposal to MP G&I 0 bbls, total 1311 bbls. Daily water from Lake 2 480 bbls, total 5140
bbls. Daily DH losses 119 bbls, total 210 bbls.
3/9/2023 PJSM, Grease TD, Blocks and Wash Pipe. While Greasing TD, noticed Hyd Oil leaking from TD Coffin Lid. Found leaking ORB Plug. Mechanic change out plug.
PJSM, Wet lines w/ 5 bbls H2O (HES) and P/T low kick out 1169/ 4000 psi high. Pump 1st stage cement job as follows: 60 bbls 10 ppg Tuned spacer w/ 4# red
dye & 5 ppb poly flake (1st 10 bbls) 3.5 bpm 320 psi. Release F/ Volant & drop bypass plug. HES pump LEAD EconoCem Type I/II cmt 200 bbls (479 sx). 12 ppg,
2.347 yld, 4.5 bpm, ICP 362 psi FCP 370 psi. TAIL HalCem Type I/II cmt (Wet at 09:52) 82 bbls (400 sx) 15.8 ppg, 1.152 yld, 3.5 bpm, ICP 334 psi FCP 608 psi.
Release F/ Volant & drop shutoff plug. HES Pump 20 bbls FW, Rig disp w/ 243.7 bbls 9.5 ppg spud mud, 8 bpm, ICP 425 psi, FCP 330 psi @ 6 BPM, HES pump
80 bbls 9.5 ppg spacer, 5 bpm, 380 ICP, 520 FCP, Rig displace w/ 87.7 bbls Spud mud, 6 bpm, 678 ICP, Maintain 3 BPM to Bump with 710 FCP. Bumped @
431.4 bbls, (Calc 431.4 bbls.) Hold 1200 psi (3 min). Bleed off psi, Check floats (good). Psi up, open stage tool 3 bpm, shift @ 3040 psi. CIP @ 11:45 hrs. Parked
in tension 180k up. No losses during Displacement. CBU (2340 stks)x2 through Stage tool 4-5 BPM w/no Cmt back on 1st BU. stage up to 6 bpm/275 psi. See
Spacer and clabbered up Mud at 2nd BU. Dumped 140 bbls Spacer, 164 bbls contaminated mud. with Trace cement. (304 bbls Total dumped). Continue to
circulate and condition mud via stage tool (2150'). at 5 bpm, 190 psi, 34% flow. Ramp pumps up to 8 bpm periodically and back to 5 bpm to attempt to clear out any
channeling. Prep Pits for 2nd stage cement. Fill water tank and heat. Check dump and conductor valves. B/D cement and water lines to HES. Pump 2nd stage
cement job: 5 bbls water at 5 bpm, 155 psi. 60 bbls 10 ppg Tuned spacer at 4.35 bpm, 201 psi. 447 bbls (870 sx) 10.7 ppg Type I/II lead cement at 5 bpm, 470 psi.
Observe good cement at surface 415 bbls into lead. 56 bbls (270 sx) 15.8 ppg Type I/II tail cement at 2.5 bpm, 230 psi. Drop closing plug..Displace with: 20 bbls
water at 5 bpm, 250 psi. 137.4 bbls 9.5 ppg Spud mud (137.4 calculated) at 6 bpm, 750 psi. Slow to 3 bpm with 10 bbls to go FCP 500 psi. Bump plug, pressure
up to 2000 psi, observe tool close at 1376. Hold for five minutes. Bleed back 2 bbls and confirm tool closure. No losses during cement job. CIP at 03:42. 245 bbls
green cement returned to surface. Drain stack and flush with black water while functioning annular x 3. Flush and blow down cement line with black water. Rig down
CRT. Install 9-5/8" elevators. R/D 3 sections of vent line between stack and catwalk. Clean surface equipment in pits, start cleaning pits. Daily Disposal to G&I 943
bbls, total 4829 bbls. Daily Disposal to MP G&I 0 bbls, total 1311 bbls. Daily water from Lake 2 920 bbls, total 6060 bbls. Daily DH losses 0 bbls, total 210 bbls.
3/10/2023 Suck out 9-5/8" casing, drain stack. Clean out cellar box. 4-bolt speed head from diverter 'T'. Lift stack, center casing. Install 'E' slips with 20K. Set stack down,
break spped head off diverter'T' and lift stack. Cut 9-5/8" casing. Pull cut joint (28.06'). Set stack down and johnny whack. N/D diverter system. R/D vent line. pull
bushings, riser, bell nipple. Remove knife valve. N/D diverter 'T'. Set stack on pedestal. R/U MPD RCD. Empty and clean pits. Install MPD on BOP. Dress off 9-5/8"
stump. Continue cleaning pits. Install casing and tubing spool. PT void 500/3800 psi for 5-minutes. Continue cleaning pits. Install DSA, inspect and clean all ring
grooves. N/U BOP, choke and kill lines. Install drip pan, chain binders, install MPD hard lines. TQ BOP and wellhead to spec. Install accumulator lines. Continue
cleaning pits. Change out LPR's from 5" SB to 2-7/8" x 5.5" VBR's. Clean and inspect door seals and cavities. Open top rams and clear out cement from cavities.
Rig up and PT Beyond MPD RCD 250/1200 psi - good. Rig down testing cap, install trip nipple. M/U 3-1/2" test joint. Flood stack and bleed air. Pump through
super choke. Shell test BOP 250/3000 psi - good. Test BOPE 250/3000 psi on 3-1/2", 5" and 7" test joint. Witnessed by AOGCC Kam St. John. Test gas alarms,
PVT, flow paddle. Fail on 7" test joint. F/P HCR choke - function and grease pass. Accumulator drawdown starting pressure 3000 psi, after functioning 1500 psi,
first 200 psi 23 seconds, full recharge 92 second. (6)N2 at 2400 psi average. Rig down testing equipment. Pull test plug, Install wear ring. Daily Disposal to G&I
1807 bbls, total 6636 bbls. Daily Disposal to MP G&I 0 bbls, total 1311 bbls. Daily water from Lake 2 1120 bbls, total 7180 bbls. Daily DH losses 0 bbls, total 210
bbls.
3/11/2023 Obtain RKB's, install mouse hole, hydraulic elevators. Bring air slips to floor. Rig up tongs. Service and inspect top drive. M/U drillout BHA: 8-1/2" tri-cone, motor, 3
stands HWDP, HWDP/Jar stand, 5 stands HWDP to 590'. P/U 46K, S/O 45K. Pick up, drift (3.125") and single in the hole with 5" drill pipe from 590' to 2148'.
Wash down last 100' to ES cementer at 400 gpm, 510 psi, 30 rpms, 4Kft-lbs. P/U 86K, S/O 67K, ROT 76K. Tag ES cementer on depth. Drill ES cementer from
2151' to 2156' with 400 gpm, 510 psi, 30 rpms, 4Kft-lbs. Cont to wash down to 2207' to ensure no debris below. Cont. to pick up, drift (3.125") and single in the hole
with 5" drill pipe from 2,207' to 4850'. P/U 175K, S/O 79K. RIH with stands from derrick from 4850' to 5750'. Tagged on junk at 5435', wash and reamed from 5435'
to 5530'. 350 gpm, 670 psi, 30 rpms, 14Kft-lbs, WOB 1-3K. Circulate hole at 400 gpm, 700 psi, 40 rpms, 14Kft-lbs, reciprocating pipe. Rig up and PT casing to
2500 psi for 30 minutes - good. Pumped 5 bbls, bled back 4.7 bbls. Blow down and rig down lines. Drill cement, shoe track and 20' of new hole from 5750' to 5931'
at 450 gpm, 875 psi, 40 rpms, 14-15Kft-lbs, WOB 2-10K. Tag BA at 5774', FC at 5859', shoe 5899'. Start displacing to 9.15 ppg Baradril N on the fly. Work through
float equipment x 2 with pumps rotary, then dry run - good. Cont. to displace to 9.15 ppg Baradril N at 450 gpm, 875 psi, 40 rpms, 14-15Kft-lbs. reciprocating pipe.
L/D working single, rack back stand to 5855'. Rig up, purge lines and perform FIT to 12.1 ppg EMW, 670 psi, shoe at 4226'TVD with 9.15 ppg mud. Pumped 1.5
bbls, bled back 1.1 bbls. Rig down and blow down lines. Monitor well, static. Pump dry job. POOH from 5855' to 590'. L/D BHA. L/D 4 stands HWDP, rack back 4
stands. C/O HWDP on jar stand due to hard band. Milk motor and break bit. Clean and clear rig floor. Prep to pick up RSS drilling assembly. Daily Disposal to G&I
934 bbls, total 7570 bbls. Daily Disposal to MP G&I 0 bbls, total 1311 bbls. Daily water from Lake 2 700 bbls, total 7880 bbls. Daily metal recovered 5 lbs, total 5lbs.
Daily DH losses 0 bbls, total 210 bbls.
3/12/2023 M/U 8.5" RSS drilling BHA: Hycalog bit, NRP, Geo-Pilot, ADR, ILS, DGR, PWD, GWD, DM, TM. Upload MWD. M/U flat subs and flex collars, (4) HWDP, jars, (3)
HWDP to 415'. P/U 56K, S/O54K. RIH from 415' to 4568'. Fill pipe, shallow test and break in Geo-Pilot at 2642'. P/U 129K, S/O 89K. Continue to TIH from 4568'to
5879'. P/U 130K, S/O 75K. Cut and slip drilling line. Check brake tolerances, calibrate drum. Check floor and crown saver. Service rig: check TD gear oil, grease
RLA, washpipe, IBOP, spinners, FH-80, top drive. Check rotary oil. Complete crown sheave wobble EAM. Drain stack, blow down top drive. Remove trip nipple.
Install MPD bearing. test MPD lines - good. Wash down to 5931'. Drill 8-1/2" hole from 5931' to 6082' (total 151', AROP 76 fph) at 475 gpm, 1550 psi, 100 rpms,
13Kft-lbs, ECD 10.1 ppg with 9.2 ppg mud. WOB 8-10K. Max gas 1524u. P/U 142K, S/O 78K, ROTW 108K. Drill 8-1/2" hole from 6082' to 6957' (total 875', AROP
146 fph) at 400-450 gpm (adjusted as needed due to gas overwhelming the shakers), 1135 psi, 120 rpms, 13Kft-lbs, ECD 10.2 ppg with 9.3 ppg mud. WOB 8-10K.
Max gas 1751u. P/U 142K, S/O 80K, ROTW 107K. Drill 8-1/2" hole from 6957' to 7705' (total 748', AROP 136 fph) at 400-450 gpm (adjusted as needed due to gas
overwhelming the shakers), 1230 psi, 120 rpms, 11-13Kft-lbs, ECD 10.56 ppg with 9.2 ppg mud. WOB 2-8K. Max gas 1776u. P/U 142K, S/O 75K, ROTW 105K.
Hold 100-150 psi back pressure on MPD to. mitigate gas overwhelming shakers. At 7630' observe 38% loss rate with 425 at 10.8 ppg ECD. Open MPD chokes and
observe loss rate improve to 15% at 400-450 gpm (same loss rate). Continue drilling to 7705'. No magnetic interference noted, C-C distance from L-205A ~200'.
Discuss with pad operator close approach to L-205A. Downhole pressure increased from 1260 psi to 1360 psi time coinciding with the loss of mud. Rack back
stand. Circulate at 350 gpm while discussing with town. Distance to WP4: 3.16', 1.47' Low, 2.8' Left. Daily Disposal to G&I 347 bbls, total 7917 bbls. Daily Disposal
to MP G&I 342 bbls, total 1653 bbls. Daily water from Lake 2 280 bbls, total 8160 bbls. Daily metal recovered 0 lbs, total 5lbs. Daily DH production losses 0 bbls,
total 0 bbls. Total surface DH losses 210 bbls.
3/13/2023 Cont. to circulate hole pumping LCM pill due to loss circulation and apparent communication with L-205A at 400 gpm, 1037 psi, 120 rpm, 12.5Kft-lbs. P/U 142K,
S/O 75K, ROTW 108K. Loss rate 15%. Drill 8-1/2" hole from 7705' to 8357' (total 652', AROP 118 fph) at 400, 996 psi, 150 rpms, 13-15Kft-lbs, ECD 10.03 ppg
with 9.2 ppg mud. WOB 2-13K. Max gas 1850u. P/U 142K, S/O 75K, ROTW 107K. Increase background LCM from 6 ppb to 12 ppb, loss rate decreased to 10%.
Drill 8-1/2" hole from 8357' to 8990' (total 633', AROP 106 fph) at 455, 1300 psi, 120 rpms, 15Kft-lbs, ECD 10.4 ppg with 9.05 ppg mud. WOB 8-10K. Max gas
1888u. P/U 145K, S/O 68K, ROTW 106K. Loss rate 5%. Drill 8-1/2" hole from 8990' to TD at 9925' (total 935', AROP 156 fph) at 425, 1200 psi, 120 rpms, 15Kft-
lbs, ECD 10.5 ppg with 9.2 ppg mud. WOB 8-12K. Max gas 1894u. P/U 144K, S/O 72K, ROTW 105K. Loss rate 5%. Obtain final survey. BROOH one stand. Pump
tandem low vis/wt, high vis/wt sweep (on time 25% increase in cuttings) and circulate hole clean 4 x BU, once sweep is out of hole rack back stand every bottoms
up. 450 gpm, 1400 psi, 120 rpms, 16Kft-lbs. max gas 1874u. Drop metal drift. RIH with three stands from 9693' to 9925', washing last stand to bottom. Pump SAPP
train: 3 x 40 bbls SAPP pill followed by 20 bbls 9.2 ppg QuikDril and displace to 9.2 ppg QuikDril at 250 gpm, 495 psi. 80 rpms, 18Kft-lbs. P/U 147K, S/O 73K,
ROT 102K. No faults were crossed. 19 concretions were drilled for a total footage of 152 (3.8% of the lateral). 4,024' Drilled in OA sands. Distance to WP4 projected
to TD: 2.99', 0.54' Low, 2.94' Left. Daily Disposal to G&I 746 bbls, total 8663 bbls. Daily Disposal to MP G&I 285 bbls, total 1938 bbls. Daily water from Lake 2 420
bbls, total 8580 bbls. Daily metal recovered 0 lbs, total 5lbs. Daily DH production losses 560 bbls, total 560 bbls. Total surface DH losses 210 bbls.
3/14/2023 Continue to Displace well to 9.3 ppg Quick Drill Brine, obtain passing PST , GPM 500, PSI 1425, RPM 120, Tq 15K, P/U 146K, S/O 72K, Rot 103K. Monitor well for
15 min, shut in 3 times for 5 min each, pressure trending down each time, 62 psi, 50 psi, 40 psi. BROOH from 9925' to 8167', 20-40 FPM, 500 GPM, 1300 PSI, 120
RPM, Tq 12.5K, ECD 10.1, MW 9.3, Max Gas 1480u. P/U 142k, S/O 80K, Rot 105K. BROOH from 8167' to 5879', 20-40 FPM, 500 GPM, 1125 PSI, 120 RPM, Tq
10K, ECD 9.4, MW 9.3, Max Gas 0u. P/U 128k, S/O 95K, Rot 107K. No Losses. Pump 30 bbls Sweep inside casing. Circulate/Reciprocate f/ 5879' to 5816', GPM
500, PSI1280, P/U 128K, S/O 95K, Rot 107K, Gas 0u, RPM 80, Tq 7.8, ECD 9.78. Sweep back on time, 0% increase. Flow check with Beond Chokes. Start PSI
50, end PSI 13 for 10 min. Remove Bushing, Unclamp rotating Element and remove. Pull air boot saver and install Trip Nipple. Service Rig, Grease Blocks, Crown,
TD RLA Link Assy, Check oil in TD, trouble shoot Hyd Leak inside coffin on the TD. Add 1 gal gear oil. PJSM install stripping rubber and air slips. POOH rack back
5" D.P. F/ 5,879' to 3,913' MD P/U 113k SLK 97k. Pulled 5 stands, no swabbing, Pumped 25 bbl 10 ppg dry job. B/D TD. Calc 16.8 bbls, Actual 23.7 bbls, lost 6.9
bbls. PJSM POOH L/D 5" D.P. to pipe shed F/ 3,913' to 418' MD. Cull D.P. for CAT IV inspection. Calc 44.8 bbls, actual 65.1 bbls Lost 20.3 bbls. P/U 54k SLK 56k.
PJSM L/D BHA. L/D 7 ea 5" HWDP, Jars, 2 ea FS, rabbit in first FS. L/D 2 NM FC. Download MWD tools. Cont L/D ILS, TM, DM, GWD, PWD, DGR, ILS & ADR.
Monitor well TT, ~6 bph static loss rate. PJSM Cont L/D BHA. L/D GeoPilot and 8.5" PDC bit. Bit Grade 2-1-BT-X-I-NO-TD. Clean and clear rig floor. L/D TM, DM,
ILS and FS. PJSM Service TD and C/O wash pipe. Break in wash pipe as per procedure. PJSM P/U R/U 4.5" handling Equip. M/U 5" D.P. safety jnt 4.5" IF X/O to
4.5" JBER, 5" FOSV and lift sub. L/D in pipe shed. Install 4.5" side door elevators (150T). R/U Power Tongs. PJSM RIH Shoe jnt and 4.5" JBER 100 micron
screens as per tally to 2,318' MD. P/U 61k SLK 58k. Trq JBER 5,940 ftlb. Performed kick while tripping W/ safety jnt. Calc 8 bbls actual -12 bbls lost 20 bbls. Daily
Disposal to G&I 1821 bbls, total 10484 bbls. Daily Disposal to MP G&I 0 bbls, total 1938 bbls. Daily water from Lake 2 560 bbls, total 9140 bbls. Daily metal
recovered 0 lbs, total 5lbs. Daily DH production losses 145 bbls, total 705 bbls. Total surface DH losses 210 bbls.
3/15/2023 Continue to Single in Hole P/U 4.5" JBER 100 micron screens as per tally f/ 2,318' to 3964'. Trq JBER 5,940 ftlb. Change to 7" handling Equipment. M/U XO jt 4.5"
JBEAR x 7" 563 Hyd and 4 jts 7", 26#, L-80, 563 Hyd, Tq to 9000 ft/lbs. Change to 5" Elevators and P/U 7" x 9 5/8" SLZXP LTP to 4202.71'. Circulate through
SLZXP on 1st std of DP. Continue TIH conveying production liner on 5" DP from Derrick from 4202' to 7312' MD. P/U 128K, S/O 91K. Continue to TIH conveying 4
1/2" Screens on 5" DP from 7312' to 9925'. Tag BTM @ 9925'. P/U 152K, S/O 86K. Circulate 1 Drill Pipe Volume, 200 GPM, 460 PSI. Drop 1.125" Ball, pump ball
on seat. Pressure up to 2600 PSI and hold 5 min. Slack off to block Wt to verify set.Pressure up 4070 PSI shear ball seat. P/U and Verify release with new PUW
127K. TOL @ 5734 MD. R/U and PT IA on chart for 10 minute to 1500 PSI. Pump 2 bbls with 1.7 back. R/D Blow Down Lines. L/D 20' 5" DP Pup Jt. M/U TD and
CBU from TOL @ 5734', 500 GPM, 1120 PSI. Pump 20 bbls Dry Job. B. low down TD. TOOH from 5723' to 3946' L/D 5" DP. Calc 15.6 bbl actual 7.9 bbl Lost 7.7
bbl. TIH remaining 5" D.P. F/ derrick F/ 3,946' to 4,780' MD. P/U 121k SLK 100k. Lost 1 bbl. POOH L/D 5" D.P. F/ 4,780' L/D running tool. Cull CAT V inspection.
Calc 38.6 bbl actual 65 bbl lost 26.4 bbl. SIMOPS Clean Pits. Clean and clear rig floor. Send down air slips, break down 5" safety jnts. Static loss rate 5-6 bph.
PJSM Install wear ring puller to 5" D.P. Drain stack BOLDS and poll wear ring. L/D wear ring. Install test plug. L/D running tool and 5" D.P. Daily Disposal to G&I 0
bbls, total 10484 bbls. Daily Disposal to MP G&I 57 bbls, total 1995 bbls. Daily water from Lake 2 140 bbls, total 9280 bbls. Daily metal recovered 0 lbs, total 5lbs.
Daily DH production losses 142 bbls, total 847 bbls. Total surface DH losses 210 bbls.
Activity Date Ops Summary
3/15/2023 PJSM C/U OPR's F/ 4.5" X 7" VBR's to 7" solid body. Clean ram cavities and lightly grease door seals. Button up doors. PJSM P/U 7" test jnt and M/U 4.5" IF pump
in sub, X/O 4.5" IF to XT39 and 4" XT39 FOSV. M/U to test plug. Flood stack W/ H2O. Test 7" UPR's and 4" XT39 FOSV 250/ 3,000 psi for 5 min on chart. good.
Witnessed waived by AOGCC Rep Kam StJohn. R/D test Equip. PJSM C/O 5" elevators to 7" side door (250T) R/U 7" power tongs & Trq Turn. P/U 7" air slips.
PJSM P/U M/U 7" Bullet seal assy and RIH W/ 7" 29# L-80 VanTop to 363' MD. P/U xxk SLK xxk. Perform dump test on first jnt for Trq turn. Avg shoulder 3000 ft/lb
Opt trq 9,400 ft/lb. Daily Disposal to G&I 0 bbls, total 10484 bbls. Daily Disposal to MP G&I 57 bbls, total 1995 bbls. Daily water from Lake 2 140 bbls, total 9280
bbls. Daily metal recovered 0 lbs, total 5lbs. Daily DH production losses 142 bbls, total 847 bbls. Total surface DH losses 210 bbls.
3/16/2023 Continue to RIH with 7", 29#, L-80, VAMTOP Tie Back Csg as per Tally F/ 363' to 2773'. Opt Trq 9400 ft/lbs, Avg Shoulder 3000 ft/lbs, Final Trq 9700 ft/lbs. P/U
88K, S/O 80K. Continue to RIH with 7", 29#, L-80, VAMTOP Tie Back Csg as per Tally from 2,773' to 4,922'. P/U 143K, S/O 112K. Note: Lost Trq readings on Trq
Turn. Trouble shoot and change out main comms, Change out Trq Turn System, Change out Pan Cake Gauge. Continued to run casing from 4609' to 4922'. P/U
144K, S/O 114K Calc 46.2 bbls actual 8.7 bbks lost 54.9 bbls. Continue to RIH with 7", 29#, L-80, VAMTOP Tie Back Csg as per Tally from 4,922' to 5,745'. Opt
Trq 9400 ft/lbs, Avg Shoulder 3000 ft/lbs, Final Trq 9700 ft/lbs. P/U 157K, SLK 115K. Lost 7.3 bbls. Perform space out. Tagged No/Go at 7,745' MD. L/D Jnts 134,
133 & 132. P/U 4 Pups (19.82', 2.05', 2.87' & 14.82') & Jnt 132. P/U M/U 7" Hanger and landing jnt as per Vault Rep onsite. Drain stack and land Hanger. Set
depth off No/Go 5,744.01' MD 1.01' off No/Go. P/U 153K SLK 115K Wt in Hanger 80K. PJSM M/U 7" X/O X 4.5" IF M/U to TD. R/U HP hoses for reverse
circulating. Close Annular Bag. Press up to 500 psi for 5 min good. Bleed won to 250 psi and strip up exposing ports. Displace 100 bbls 9.2 ppg corrosion inhibited
brine 4 bpm 130 psi W/ rig pump. Turn over to LRS and pump 57 bbls Diesel FP 3 bpm ICP 200 psi FCP 340 psi. Shut down slack off and land hanger. R/D B/D
lines. PJSM Break out L/D 7" Landing Jnt. C/O elevators to 5". P/U M/U 5" D.P. running tool and Pack Off. Drain stack and set Pack Off. RILDS. Cont RILDS. Back
out running tool and L/D. Test void to 500/ 5000 psi 5 min, good. PJSM R/U LRS to 7" X 9 5/8" annulus. Test lines to 1,500 psi, good. Pressure up to 1,500 psi for
30 min on chart, good. Pumped 1.3 bbls bled 1.0 bbls. R/D test Equip and release LRS. PJSM Service rig. Grease and inspect crown sheaves & blocks. Service
TD. Check oil good. PJSM Remove 5" elevators and install 3.5" YT (75T) elevators. R/U 5500 Starr power tongs and Trq turn Equip. M/U 3.5" X 4.5" IF X/O to TIW.
Monitor well on TT static loss rate 7.4 bph. PJSM P/U 3.5" mule shoe and perform dump test on Jnt 2. Power tongs not reading Trq and resulted in crushing Jnt 2.
Trouble shot change out computer. L/D Jnt 2. Cont RIH 3.5" 9.2# 13CR L-80 JFE Bear tubing as per tally to 313' MD. Clear run Trq Opt Trq 5,030 ft/lbs, P/U 39K,
S/O 41K. Lost 7.4 bbls. Daily Disposal to G&I 57 bbls, total 10541 bbls. Daily Disposal to MP G&I 0 bbls, total 1995 bbls. Daily water from Lake 2 0 bbls, total 9280
bbls. Daily metal recovered 0 lbs, total 5lbs. Daily DH production losses 125 bbls, total 972 bbls. Total surface DH losses 210 bbls.
3/17/2023 Cont RIH 3.5" Gas lift completion. RIH 3.5" 9.2# 13Cr L-80 JFEBear Clear Rum F/ 313' to 1,123' with X Nipple RHC-M and Baker 7" X 4.5" S-3 Packer. Cont RIH
W/ 3.5" 9.2# L-80 JFEBear Modified F/ 1,123' to 3,084' and jewelry as per tally. Trq Clear Run to 5,030 ft/lb. Trq modified to 3,870 ft/lb all on Trq turn. P/U 55k SLK
52k. Lost 7.4 bbls. PJSM Cont RIH W/ 3.5" 9.2# L-80 JFEBear Modified F/ 3,084' to 5,918' MD and jewelry as per tally. C/O to 4.5" elevators. P/U Landing jnt and
hanger. Drain stack and set hanger W/ 26k. RILDS. Trq modified to 3,870 ft/lb all on Trq turn. P/U 72k SLK 59k. Total lost for run 32.6 bbls. Had to back out and
redope connections due shouldering failing QC. PJSM Pull landing jnt and L/D mouse hole. Clear rig floor of 3.5" handling Equip and power tings. PJSM R/U
reverse Circ lines and Equip. Reverse Circ 130 bbls 9.2 ppg Corrosion Inhibited brine F/ Vac Truck at 3 bpm ICP 250 psi FCP 320 psi. PJSM R/U landing jnt and
drop roller rod 1 3/8" OD ball. Remove landing jnt. Close blind rams, flood kill and choke lines. Press up W/ kill line to 1,500 psi and hold 5 min. Cont to pressure up
to 3,650 psi without indication of packer setting. Held pressure for 30 min and failed 30 min MIT T. Lost 85 psi in forst 15 min and 59 psi the second 15 min, total
lost 144 psi. Bled off pressure purged air and cycled blind rams. Retested to 3,750 psi for 30 min on chart, good. Bled down to 2,100 psi on tubing. Pressured up IA
to 3,623 psi for 30 min on chart, good. Bled down tubing and witnessed shear valve shear. Pumped 1.1 bbl down tubing, 2 bbls down IA and bled back 2.7 bbls.
PJSM Open blind rams. R/D HP test lines. Vault rep installed modified BPV W/ Tee Bar. PJSM R/D 4.5" elevators and install 5". P/U 5" D.P. and Johnny Whacker.
Johnny whack stack and flush Kill, Choke and choke manifold. Blow down all lines. L/D Johnny whacker. PJSM Remove hole fill line. R/D MPD hard lines. Take
down drip pan. Remove kill & choke lines. Send split bushing down from rig floor. P/U master bushings and riser. Install MPD test cap and M/U gray clamp. Rack
back BOP to pedestal. Break RCD bolts while removing DSA F/ wellhead. SIMOPS: Load and process 5" D.P. in pipe shed. Haul off fluids and clean pits. Daily
Disposal to G&I 0 bbls, total 10541 bbls. Daily Disposal to MP G&I 0 bbls, total 1995 bbls. Daily water from Lake 2 0 bbls, total 9280 bbls. Daily metal recovered 0
lbs, total 5lbs. Daily DH production losses 66 bbls, total 1038 bbls. Total surface DH losses 210 bbls.
3/18/2023 PJSM P/U stack off pedestal. Hook up tugger to RCD and tack off RCD L/D in cellar. Set stack back on pedestal and secure. SIMOPS clean Pits. PJSM Vault rep
pressed in SBMS seals in well head. Install CTS plug. P/U Install Tree to well head. Test void 500/ 5000 psi 10 min ea, good. Fill tree and test 500/5000 psi 5/15
min, good. R/D test Equip. Pull CTS plug and BPV. SIMOPS clean pits. PJSM R/U U Tube manifold and LRS. Test lines to 2,500 psi, good. Reverse Circ 64 bbls
Diesel FP 1 bpm 38 psi. SIMOPS Bridle up, untie block hanging line. Prep for rig move. Rig released at 12:00. Cont U Tube well final pressure 58 psi. R/D B/D
lines. Blow down steam. H2O and bleed of air lines. Scope down Derrick. Disconnect inner connects F/ Mods. Empty poor boy, rig vac and boiler. Lift roog caps and
safe out. Swap to cold start. Disconnect electrical in utilidoors. Remove flanges on tree. Remove berm F/ cutting box. Raise all landings and safe out stairs. Retract
cattle chute and lift skate bed. Remove enviro vac and install jeep to Gen Mod. PJSM NES on location at 16:00. RDMO 18:00.
50-029-23746-00-00API #:
Well Name:
Field:
County/State:
PBW L-231
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
Pressure up to 1,500 psi for
30 min on chart, good.
Held pressure for 30 min and failed 30 min MIT T.
Retested to 3,750 psi for 30 min on chart, good Pressured up IA
to 3,623 psi for 30 min on chart, good.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
2
1
8
33
18
Yes X No Yes X No 30
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Cut Joint
Casing (Or Liner) Detail
Shoe
Crossover
Casing
10 40.0 L-80
500.7 155323
SE
C
O
N
D
S
T
A
G
E
Rig
3:42
Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.5
Shoe @ 5901 FC @ Top of Liner5,818.00
Floats Held
362.3 785
245 540
Spud Mud/Spacer
CASING RECORD
County State Alaska Supv.J Lott / C Montague
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-231 Date Run 8-Mar-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC DHS 1.76 5,901.00 5,899.24
38.04 24.60
28.88 805.11 776.23
776.239 5/8 47.0 L-80 Vam21 Vam 738.19
Vam21
9 5/8 47.0 L-80 Vam21xCD
38.04
9 5/8 47.0 L-80 Vam 13.44
Csg Wt. On Hook:270,000 Type Float Collar:Conventional No. Hrs to Run:17
9.5 3
2000
10
10.7 447 5
100
710
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
500
2.5
9.5 3 137.4/137.4
431.4/431.4
1200
1
HES/Rig
15.8 82
Bump press
Returns
Bump Plug?
Y
11:45 3/9/2023 2,151
2151
5,901.005,911.00
CEMENTING REPORT
Csg Wt. On Slips:20,000
Spud Mud
Tuned Spacer
870 2.86
Stage Collar @
60
Bump press
100
245
ES Cementer Closure OK
5208.34
56
12 200
Water
26.63 RKB to CHF
Type of Shoe:Bullnose 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
ArcticCem
Type
2 on joint #1, 1 every joint to 4864', 1 every other joint to 3865'. 6 before/after ES cementer, 1 every third joint to 243'.
Casing 9 5/8 40.0 L-80 BTC 80.42 5,899.24 5,818.82
Float Collar 10 40.0 L-80 BTC DHS 1.43 5,818.82 5,817.39
Casing 9 5/8 40.0 L-80 BTC 42.05 5,817.39 5,775.34
Baffle Adapter 10 40.0 L-80 BTC HES 1.46 5,775.34 5,773.88
Casing 9 5/8 47.0 L-80 CDC USS 3,602.70 5,773.88 2,171.18
Pup Joint 9 5/8 40.0 L-80 BTC 17.52 2,171.18 2,153.66
ES Cementer 10 L-80 BTC HES 2.74 2,153.66 2,150.92
Pup Joint 9 5/8 40.0 L-80 BTC 18.01 2,150.92 2,132.91
Casing 9 5/8 47.0 L-80 CDC USS 1,327.80 2,132.91 805.11
Type I/II 479 2.35
Type I/II 400 1.15
4.5
Type I/II 270 1.16
3/10/2023 Surface
Spud Mud
00
2,151
100
Returns
245
Surface
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Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.03.15 08:56:25 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.03.15 10:21:51 -08'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN ORIN L-231
JBR 04/05/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Tested with 3.5", 5" and 7" TJ. Fail on 7" TJ on 4.5" X 7" UPR VBR had issues with TJ and when they get to that portion of the
job they will swith over to 7" fixed blocks and test again at that time with notifacation. FP on HCR choke line greased and
functioned retest pass. 20 accumulator bottles at 1000psi avg precharge.
Test Results
TEST DATA
Rig Rep:Matt vanhooseOperator:Hilcorp North Slope, LLC Operator Rep:James Lott
Rig Owner/Rig No.:Hilcorp Innovation PTD#:2230100 DATE:3/10/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopKPS230312063642
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 6.5
MASP:
1434
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8 P
#1 Rams 1 4-1/2" x 7"FP
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8" x 5-1/2 P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"FP
Kill Line Valves 1 3-1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1500
200 PSI Attained P23
Full Pressure Attained P92
Blind Switch Covers:Pall Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@2400
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P11
#1 Rams P9
#2 Rams P9
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9
9999
9
9
9
FP
FP
UPR VBR had issues with TJ
FP on HCR choke line
Date: 3/3/2023 Development:X Exploratory:
Drlg Contractor:Rig No.Innovation AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.:2230100 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:2950 psig P Hole Size:12 1/4 in.
Pressure After Closure:1950 psig P Vent Line(s) Size:16 in.P
200 psi Recharge Time:17 Seconds P Vent Line(s) Length:216 ft.P
Full Recharge Time:53 Seconds P Closest Ignition Source:90 ft.P
Nitrogen Bottles (Number of):6 Outlet from Rig Substructure:200 ft.P
Avg. Pressure: 2283 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: 13 sec P
Mud System Misc:0 NA Knife Valve Open Time: 6 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
WaivedHilcorp
*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-231
Form 10-425 (Revised 05/2021)2023-0303_Diverter_Hilcorp_Innovation_PBU_L-231
Hilcorp North Slope LLC======jbr
J. Regg; 6/13/2023
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 Drive, Suite 1400
Anchorage, AK 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L-231
Hilcorp North Slope, LLC
Permit to Drill Number: 223-010
Surface Location: 2446' FSL, 4179' FEL, Sec. 34, T12N, R11E, UM, AK
Bottomhole Location: 2551' FNL, 548' FWL, Sec. 03, T11N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of February, 2023. 16
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.02.16 14:21:41
-09'00'
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:
5
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
5
Service - WAG
5
1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple Zone Exploratory - Oil
Gas Hydrates
Geothermal
Hilcorp North Slope, LLC Bond No. 107205344
11.Well Name and Number:
PBU L-231
TVD:10132'4253'
12. Field/Pool(s):
MD:
ADL 028239 & 028241
00-001 February 26, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
2446' FSL, 4179' FEL, Sec. 34, T12N, R11E, UM, AK
1815' FSL, 204' FEL, Sec. 33, T12N, R11E, UM, AK
Kickoff Depth:350'feet
Maximum Hole Angle: 90 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:1871 1434
17.Deviated wells:16.
Surface: x-y- Zone -582736 5978163 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
73.4'
46.9'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
2139'
Surface
4203'
19.PRESENT WELL CONDITION SUMMARY
Production
Surface
Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements
Shallow Hazard Analysis
55
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#
5600'4532'
50-
Intermediate
Conductor/Structural
Single Zone
Service - Disp
No YesPost initial injection MIT req'd:
No Yes 5
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
2551' FNL, 548' FWL, Sec. 03, T11N, R11E, UM, AK
Time v. Depth Plot555 5Drilling Program
5351'
Stg 2 L - 672 sx / T - 268 sx
(To be completed for Redrill and Re-Entry Operations)
8-1/2"
7"
L-8012.6#4-1/2"
9-5/8"
4203'
12-1/4"
5600'Uncemented Tieback
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 5 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.
5120
140'
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
12-1/4"
Tieback
9-5/8" 47#
40#
26#
L-80
L-80
L-80 Vam 21
TXP
VamTop
JFE Bear
2500'
3300'
5600'
Surface
2500'
Surface
2500'
5800'
10132'
2139'
4219'
4253'
Stg 1 L - 398 sx / T - 395 sx
Uncemented Screen 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-52 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
2.3.2023
By Meredith Guhl at 10:18 am, Feb 03, 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: 2023.02.03 10:03:46 -09'00'
Monty M
Myers
X
X
029-23746-00-00
X
* Casing test and FIT digital data to AOGCC
immediately upon completion of performing FIT.
* Offset well L-121 to be shut in, deep set plug and gas lift to be bled off.
223-010
X
* BOPE test to 3000 psi. Annular to 2500 psi..
1434
X X
MGR14FEB2023
X
DSR-2/3/23SFD 2/8/2023GCW 02/16/23
JLC 2/16/2023
2/16/23
2/16/23
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.02.16 14:22:18 -09'00'
RBDMS JSB 021723
Prudhoe Bay West
(PBU) L-231
Drilling Permit
Version 1
2/1/2023
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 ..................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 4-1/2” Screen Liner .......................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 40
19.0 Innovation Rig Diverter Schematic ......................................................................................... 43
20.0 Innovation Rig BOP Schematic ............................................................................................... 44
21.0 Wellhead Schematic ................................................................................................................. 45
22.0 Days Vs Depth .......................................................................................................................... 46
23.0 Formation Tops & Information............................................................................................... 47
24.0 Anticipated Drilling Hazards .................................................................................................. 49
25.0 Innovation Rig Layout ............................................................................................................. 53
26.0 FIT Procedure .......................................................................................................................... 54
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 55
28.0 Casing Design ........................................................................................................................... 56
29.0 8-1/2” Hole Section MASP ....................................................................................................... 57
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 58
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 59
Page 2
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU L-231
Pad Prudhoe Bay L Pad
Planned Completion Type 3-1/2” Gas Lift
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 10,132’ MD / 4253’ TVD
PBTD, MD / TVD 10,122’ MD / 4253’ TVD
Surface Location (Governmental) 2,446' FSL, 4179' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582,736.06, Y= 5,978,162.85
Top of Productive Horizon
(Governmental)1815' FSL, 204' FEL, Sec 33, T12N, R11E, UM, AK
TPH Location (NAD 27) X=581,439.95, Y=5,977,517.18
BHL (Governmental) 2551' FNL, 548' FWL, Sec 3, T11N, R11E, UM, AK
BHL (NAD 27) X= 582,249, Y= 5,973,160
AFE Number 231-00030
AFE Drilling Days 19
AFE Completion Days 3
Maximum Anticipated Pressure
(Surface) 1434 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1871 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 46.9 ft = 73.4 ft
GL Elevation above MSL: 46.9 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Schrader Bluff OA Sand
Page 3
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.565 26 L-80 JFE Bear 7,240 5,410 604
8-1/2” 4-1/2” 3.958 3.833 5.0 12.6 L-80 JFE Bear 8430 7500 288
Tubing
3-1/2” 2.992 2.867 3.883 9.2 L-80 JFE Bear 10160 10540 207
3-1/2” 2.992 2.867 3.883 9.2
L-80
13Cr JFE Bear 10160 10540 207
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Wyatt Rivard 907.777.8547 wrivard@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 mmayfield@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-231 is a grassroots producer planned to be drilled in the Schrader Bluff OA sands. L-231 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 into the top of the Schrader Bluff
OA sand. An 8-1/2” lateral section will be drilled. A 4-1/2” screens liner will be run in the open hole
section, followed by a 7” tieback and 3-1/2” gas lift tubing.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 26, 2023, pending rig schedule.
Surface casing will be run to 5,800’ MD / 4,218’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
Page 8
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-231. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
No variances requested at this time.
Page 9
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs and changing rams
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 10
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-231 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 and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
x Cold mud temps are necessary to mitigate hydrate breakout
9.10 Ensure 5” liners in mud pumps.
x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
Page 11
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x N/U 20” x 13-5/8” DSA
x N/U 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC with 24 hour notice to witness. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure – AOGCC Regulation requirement
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
Page 12
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
Page 13
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in
DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still
meeting tangent hold target.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at
base of perm and at TD (pending MW increase due to hydrates). This is to combat
hydrates and free gas risk, based upon offset wells.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
Page 14
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
x Gas hydrates are not present at PBU L-Pad. But be prepared for gas hydrates. In PBW
they have been encountered typically around 1660’ TVD (Base of Perm) to 2740’ TVD (Top
Ugnu) and below. Be prepared for hydrates:
x Keep mud temperature as cool as possible, Target 60-70*F.
x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold pre-made mud on trucks ready.
x Drill through hydrate sands and quickly as possible, do not backream.
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the
well. MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC, CF <1.0 :
x There are no wells with a CF < 1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.5+ (For Hydrates/Free Gas based on offset
wells)
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
ppgp
with 9.5+ ppg. MW for free gas and hydrates based upon offset wells
Page 15
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 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
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.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
Page 16
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” BTC x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.75” on the location prior to running.
x Top 2,500’ of casing 47# drift 8.525”
x Actual depth to be dependent upon base of permafrost and stage tool
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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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
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x Bowspring Centralizers only
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD, actual depth based upon base of permafrost)
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 47# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
9-5/8” 40# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”18860 20960 23060
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Drilling Procedure
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Drilling Procedure
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Drilling Procedure
12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
x Actual length of 47# may change due to depth of permafrost as drilled
x Ensure drifted to 8.525”
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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Drilling Procedure
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Casing (5,800'-1,000'-2,500') x 0.0558 bpf x 1.3 166.8 935.7
Total Lead 166.8 935.7 398.2
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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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
2500’ x 0.0732 bpf + (6,800’-120’-2500’) x .0758 bpf =
= 424.2 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.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
5800'
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Drilling Procedure
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Drilling Procedure
Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. Cement will continue to be pumped until
clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
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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Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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Drilling Procedure
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 Give AOGCC 24hr notice of BOPE test, for test witness.
14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.3 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve.
14.4 RU MPD RCD and related equipment
14.5 Run 5” BOP test plug
14.6 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 3-1/2” test joint
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.7 RD BOP test equipment
14.8 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.9 Mix 8.9 ppg Baradrill-N fluid for production 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 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum
required to drill ahead
x 9.8 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP)
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a ported float in the production hole section.
Email casing test and FIT digital data to AOGCC promptly upon completion of FIT. email: melvin.rixse@alaska.gov
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Drilling Procedure
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total Solids MBT HPH
T
Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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Drilling Procedure
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
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
x Density may change based upon TD of surface hole section
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OBd sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
n OBd sand.
OA SFD 2/8/2023
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Drilling Procedure
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OA Concretions: 5-7% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C, CF < 1.0:
x L-121A:
o CF .78, L-121 is an active Kuparuk producer, the well will be shut in, deep set
plug (~ 5000’ TVD) to isolate the reservoir, and the gas lift annulus bled off.
x L-205 L4
o CF .71, L-205 parent bore is an abandoned multi lateral, replaced by L-205A.
The only risk is damage to the bit.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
Lube 776: 1.5%
g
Schrader Bluff OA
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Drilling Procedure
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.15 Monitor the returned fluids carefully while displacing to brine.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
x Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
16.0 Run 4-1/2” Screen Liner
16.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints
16.2 Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.3 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 12.6# JFE Bear x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4 Run 4-1/2” slotted liner
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Install joints as per the Running Order (From Completion Engineer post TD).
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
4-1/2” 12.6# JFE Bear Torque – ftlbs
OD Minimum Optimum Maximum
4-1/2 4860 5400 5940
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Drilling Procedure
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Drilling Procedure
16.6. Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for gas lift
completion. Tentative liner set depth ~ 5,650’ MD
x Confirm set depth with completion engineer.
x 3-5 joints of 7” may be ran under the liner hanger for the production packer. Confirm with
completion engineer.
16.7. Ensure hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.8. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.9. M/U Baker SLZXP liner top packer to 4-1/2” liner.
x Confirm with OE any 7” joints between liner top packer and 4-1/2” liner for GLM
and packer setting depth
16.10. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.11. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
x Use HWDP as needed for running liner
16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.16. Rig up to pump down the work string with the rig pumps.
16.17. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.18. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.19. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the
WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do
not allow ball to slam into ball seat.
16.20. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP 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.
16.21. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.22. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.23. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.24. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.25. 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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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation.
17.2 Notify AOGCC 24hrs prior to ram change
17.3 Install 7” solid body casing rams in the upper ram cavity. RU testing equipment. PT to
250/3,000 psi with 7” test joint. RD testing equipment.
17.4 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.5 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.6 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 JFE Bear tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
17.7 Tieback to be Torque turned.
7”, 26#, L-80, JFE Bear
=Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”11800 13110 14420
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
17.8 MU 7” to DP crossover.
17.9 MU stand of DP to string, and MU top drive.
17.10 Break circulation at 1 BPM and begin lowering string.
17.11 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.12 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
17.13 PU string & remove unnecessary 7” joints.
17.14 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.15 PU and MU the 7” casing hanger.
17.16 Ensure circulation is possible through 7” string.
17.17 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.18 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.19 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.20 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.21 RD casing running tools.
17.22 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 3-1/2”, 9.2#, L-80 JFEBEAR tubing.
x Ensure wear bushing is pulled.
x Ensure 3-1/2”, L-80, 9.2#, JFEBEAR x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RIH with the following 3-1/2” completion jewelry (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 1x X Nipple
x 4x GLM
x 1x X Nipple
x 1x Production Packer
i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval.
x 1x X Nipple
x XXX joints, 3-1/2”, 9.2#, L-80, JFEBEAR
x XX joints 3-1/2”, 9.2# 13cr JFEBEAR
x 1x WLEG
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
18.3 PU and MU the 4-1/2” tubing hanger with 3.5” XO.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel
freeze protect for both tubing and IA to 2,500’ MD.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
2. Well Tie in
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 45
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
21.0 Wellhead Schematic
Page 46
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
22.0 Days Vs Depth
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
COMMENTS
SV5 Ice 1,801 1,618.4 -1545 712 8.46
BPRF Water 1,983 1,754.4 -1681 772 8.46
SV3 Gas Hydrates 2,400 2,064.4 -1991 908 8.46 Gas Hydrates possible in SV3, SV2, & SV1 sands: ~ 2100' - 3170' MD
SV1 Gas Hydrates 2,985 2,543.4 -2470 1119 8.46
Ugnu 4A Heavy Oil 3,327 2,854.4 -2781 1256 8.46 Heavy Oil in Ugnu 4A: ~ 3327' - 3415' MD
UG3 Water 3,695 3,189.4 -3116 1403 8.46
UG1 Water 4,176 3,594.4 -3521 1582 8.46 Possible Heavy Oil Lower Ugnu: ~ 4350' - 4940' MD
Ugnu MB Heavy Oil 4,582 3,875.4 -3802 1705 8.46
Ugnu MF Heavy Oil 0
FAULT 60' Throw DTN N/A 5,140 Fault from ~SB NA sand to ~top of SB NE sand
OA (Heel) Schrader Bluff Oil 5,815 4,219.4 -4146 1857 8.46
OA (Toe) Schrader Bluff Oil 10,132 4,253.4 -4180 1871 8.46
EASTING Est.
Pressure GradientEXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING
L-231 wp02ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have not been seen on PBU L Pad. Be prepared for them. They have been reported
between 1660’ and 3140’ TVD across Prudhoe. MW has been chosen based upon successful trouble free
penetrations of offset wells.
x Be prepared for gas hydrates
o Keep mud temperature as cool as possible, Target 60-70*F
o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
o Drill through hydrate sands and quickly as possible, do not backream.
Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not
prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been
disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible
while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone.
Excessive circulation will accelerate formation thawing which can increase the amount of hydrates
released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with
both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud
cut weight. Isolate/dump contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x No well with CF < 1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific A/C:
x L-121A:
o CF .78, L-121 is an active Kuparuk producer passing through the SB sands, the
well will be shut in, deep set plug (~ 5000’ TVD) set to isolate the reservoir, and
the gas lift annulus bled off.
x L-205 L4
o CF .71, L-205 parent bore is an abandoned multi lateral, replaced by L-205A.
The only risk is damage to the bit.
L-121 is an active Kuparuk producer passing through the SB sands, the,pppgg,
well will be shut in, deep set plug (~ 5000’ TVD) set to isolate the reservoir, and,p
the gas lift annulus bled off.
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
25.0 Innovation Rig Layout
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
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Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 56
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
28.0 Casing Design
Page 57
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 58
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 59
Prudhoe Bay West
L-231 SB Producer
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
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-3575
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-2925 -2600 -2275 -1950 -1625 -1300 -975 -650 -325 0 325 650 975 1300 1625
West(-)/East(+) (650 usft/in)
L-231 wp01 CP2
L-231 wp01 CP1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
250
1 0 0 01250
1 5 0 0
1 7 5 0
2 0 0 0
2 2 5 025002750
3
25
0
3500
3750
4000
4 2 5 0
4 2 5 3
L -2 3 1 w p 0 2
Start Dir 3º/100' : 350' MD, 350'TVD
Start Dir 4º/100' : 500' MD, 499.85'TVD
End Dir : 1447.8' MD, 1356.12' TVD
Start Dir 4º/100' : 2452.7' MD, 2103.32'TVD
End Dir : 5468.99' MD, 4191.61' TVD
Start Dir 3º/100' : 5718.99' MD, 4213.4'TVD
End Dir : 5871.01' MD, 4220.61' TVD
Total Depth : 10132.48' MD, 4253.4' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4218.75 4145.35 5800.00 9-5/8 9 5/8" x 12 1/4"
4253.40 4180.00 10132.48 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: L
Well: Plan: L-231
Wellbore: L-231
Plan: L-231 wp02
WELL DETAILS: Plan: L-231
46.90
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5978162.850 582736.060 70° 21' 1.1642 N 149° 19' 41.7845 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-231 - Slot L-231, True North
Vertical (TVD) Reference:L-231 As staked RKB @ 73.40usft
Measured Depth Reference:L-231 As staked RKB @ 73.40usft
Calculation Method:Minimum Curvature
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
223-010
PBU
X
Schrader Bluff Oil, Orion Development Area
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5
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l
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g
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n
d
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Ye
s
6
W
e
l
l
l
o
c
a
t
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p
r
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d
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s
7
S
u
f
f
i
c
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t
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g
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a
v
a
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l
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b
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n
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r
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l
l
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n
g
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n
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t
Ye
s
8
I
f
d
e
v
i
a
t
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d
,
i
s
w
e
l
l
b
o
r
e
p
l
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t
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n
c
l
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d
e
d
Ye
s
9
O
p
e
r
a
t
o
r
o
n
l
y
a
f
f
e
c
t
e
d
p
a
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y
Ye
s
10
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p
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r
a
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h
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p
p
r
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p
r
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b
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d
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f
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c
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Ye
s
11
P
e
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m
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t
c
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n
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d
w
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t
c
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v
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Ye
s
12
P
e
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m
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c
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n
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w
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13
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v
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d
b
e
f
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1
5
-
d
a
y
w
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t
NA
14
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l
l
l
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c
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w
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n
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p
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t
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o
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NA
15
A
l
l
w
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w
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n
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4
m
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l
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r
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n
l
y
)
NA
16
P
r
e
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p
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NA
17
N
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18
C
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9
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8
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s
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19
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20
C
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v
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21
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22
C
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23
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24
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T
h
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.
25
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h
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26
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27
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28
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r
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29
B
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s
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d
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m
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p
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8
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p
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30
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p
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p
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Ye
s
31
C
h
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m
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a
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Ye
s
32
W
o
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w
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r
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w
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q
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d
33
I
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p
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s
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n
c
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o
f
H
2
S
g
a
s
p
r
o
b
a
b
l
e
NA
T
h
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s
w
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l
l
i
s
a
p
r
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d
u
c
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r
.
34
M
e
c
h
a
n
i
c
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l
c
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n
d
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t
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n
o
f
w
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s
w
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h
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n
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v
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r
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f
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d
(
F
o
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c
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w
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)
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e
a
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r
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s
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u
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d
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L
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P
a
d
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l
s
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r
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2
S
b
e
a
r
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n
g
.
35
P
e
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
i
d
e
m
e
a
s
u
r
e
s
Ye
s
N
o
r
m
a
l
p
r
e
s
s
u
r
e
(
8
.
4
6
p
p
g
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)
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p
e
c
t
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d
.
M
P
D
w
i
l
l
b
e
u
t
i
l
i
z
e
d
.
36
D
a
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
e
s
s
u
r
e
z
o
n
e
s
NA
37
S
e
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
38
S
e
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
C
o
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
SF
D
Da
t
e
2/
8
/
2
0
2
3
Ap
p
r
MG
R
Da
t
e
2/
1
4
/
2
0
2
3
Ap
p
r
SF
D
Da
t
e
2/
8
/
2
0
2
3
Ad
m
i
n
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s
t
r
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t
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n
En
g
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r
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n
g
Ge
o
l
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g
y
Ge
o
l
o
g
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c
Co
m
m
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s
s
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o
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e
r
:
Da
t
e
:
En
g
i
n
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e
r
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n
g
Co
m
m
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s
s
i
o
n
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r
:
Da
t
e
Pu
b
l
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c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
JL
C
2
/
1
6
/
2
0
2
3
