Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
06/09/2025
Mr. Jack Lau
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor
through 06/09/2025.
Dear Mr. Lau,
Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off
with cement, corrosion inhibitor in the surface casing by conductor annulus through 06/09/2025.
Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement
fallback during the primary surface casing by conductor cement job. The remaining void space
between the top of the cement and the top of the conductor is filled with a heavier than water
corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached
spreadsheets include the well names, API and PTD numbers, treatment dates and volumes.
As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that
the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations.
If you have any additional questions, please contact me at 564-4891 or
oliver.sternicki@hilcorp.com.
Sincerely,
Oliver Sternicki
Well Integrity Supervisor
Hilcorp North Slope, LLC
Digitally signed by Oliver
Sternicki (4525)
DN: cn=Oliver Sternicki (4525)
Date: 2025.06.09 14:30:46 -
08'00'
Oliver Sternicki
(4525)
Hilcorp North Slope LLC.Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-offReport of Sundry Operations (10-404)06/09/2025Well NamePTD #API #Initial top of cement (ft)Vol. of cement pumped (gal)Final top of cement (ft)Cement top off date Corrosion inhibitor (gal)Corrosion inhibitor/ sealant dateF-10C21308650029204100365/29/25F-29B2111475002921627026.25/29/25F-33A20816350029226400145/29/25F-3619519650029226310035/29/25F-39190141500292210100175/29/25F-44A2051615002922130012.55/29/25F-47B21007950029222320215/29/25L-2512231065002923772001.8813/31/24117/29/24L-2532230485002923758004.1201.13/31/24127/29/24L-2542230305002923752003.8321.23/31/24137/29/24L-2922230255002923751003.3301.33/31/24147/29/24N-282141275002923524006.8504.711/19/242212/28/24N-302141245002923523003.5330.311/17/243.512/28/24PAVE1-122309450029237670019.910/27/24PWDW3-221908150029236340014.810/27/24S-40120607850029233130015.31130.511/15/24412/28/244.1201.13/31/247/29/24L-25322304850029237580012
By Grace Christianson at 11:37 am, Aug 23, 2023
Completed
7/25/2023
JSB
RBDMS JSB 082423
GMGR16MAY2024DSR-8/31/23
Drilling Manager
08/22/23
Monty M
Myers
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.08.23 11:13:34 -08'00'
Torin
Roschinger
(4662)
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-253 Date:7/14/2023
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Amend/Carter
Csg Setting Depth:8122 TMD 4521 TVD
Mud Weight:9.2 ppg LOT / FIT Press =687 psi
LOT / FIT =12.12 ppg Hole Depth =8150 md
Fluid Pumped=1.5 Volume Back =1.3 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->256 ->00
->4123 ->8177
->6192 ->16 374
->8256 ->24 592
->10 318 ->30 744
->12 381 ->35 898
->14 444 ->40 1015
->16 519 ->45 1153
->18 570 ->50 1294
->20 618 ->60 1584
->22 661 ->70 1881
->24 687 ->80 2183
-> ->90 2487
-> ->95 2639
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0687 ->02649
->1670 ->12647
->2660 ->22645
->3656 ->32644
->4644 ->42644
->5639 ->52643
->6634 ->10 2640
->7630 ->15 2637
->8626 ->20 2637
->9623 ->25 2635
->10 619 ->30 2634
->11 617 ->
->13 610 ->
->15 606 ->
2
4
6
8
10
12
14
16
18
20
2224
0
8
16
24
30
35
40
45
50
60
70
80
90
95
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 102030405060708090100
Pr
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(
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Strokes (# of)
LOT / FIT DATA CASING TEST DATA
687670660656644639634630626623619617 610 606
264926472645264426442643 2640 2637 2637 2635 2634
0
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1300
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0 5 10 15 20 25 30
Pr
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Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
7/3/2023 R/U tow bar and truck and mobilize sub base to L-253. Set rig down to adjust stompers. SimOps: replaces valves in pits and adjust suction valves. Walk sub base
over L-253. Set, shim and level all modules. Trucks released 01:30. Work on rig acceptance checklist. R/U interconnects. Scope derrick up. Spot cuttings box and
auxiliary equipment. Remove MPD head from BOP Stack. Set diverter 'T' and stack, secure with chain binders. Set riser.
7/4/2023 PJSM Cont rig acceptance check list. M/U Stack to Diverter Tee, install knife valve. Install 3 sections 16" Diverter between sub and catwalk. Process 5" HWDP.
Bring on 290 bbls 8.8 ppg Spud Mud. Function test MP 1 & 2, good. Install 5" hydraulic elevators. Install mouse hole in rotary table. RKB. Rig accepted at 10:00.
PJSM P/U M/U 5" 19.5# S-135 NC50 D.P. racking back in derrick 128 stands (256 jnt) Drift 3.125" OD, 17 stands (34 Jnt) 5" 49# S-135 NC50 HWDP Drift 2.75"
OD rabbit & 6 3/4" Hydra Jar. Bring on 290 bbls 8.8 ppg Spud Mud. SIMOPS Install 16" Diverter sections, released crane at 11:30. PJSM Perform Annular closure
11 sec, knife 6 sec. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and return flow. Koomey draw drown Initial System
2,959 PSI, after System 2,150 PSI, 200 PSI increase 18 Sec, full charge 45 sec. Nitrogen 6 bottle average 2,333 PSI. Witnessed waived by AOGCC Rep Sully
Sullivan. Perform Pre Spud meeting with all personnel. Discussed broaching, rig evacuation, muster area's, shutting down all sources of ignition, fire response, man
down and first aid. Also talked about H2S, hydrates and roles and responsibilities while drilling. PJSM P/U M/U 12.25" K5M633 Hybrid (1X12, 1X13, 4X14 Jet
0.8414 TFA) Rebuilt Bit, 8" 1.5 deg TerraForce Lobe 4/5 5.3 stage 800-328 motor, Bottle Neck X/O and 1 stand 5" HWDP to 97.67'. Flood lines and test to 3,000
psi, good. Wash down tag at 104' MD. Drill F/ 107' to 221' MD. 350 gpm 200-300 psi 40 rpm Trq 800-1100 ft/lb WOB 1-3k F/O 61% ROP 56-60 fpm. P/U 44k SLK
41k ROT 42k. Jet flow line & pump through bleeder. No losses. Pump out of hole F/ 221' to 31' MD 100 gpm 86 psi F/) 24%. No issue. Perform Pre Spud Meeting
and P/U BHA W/ rig crew. Discussed broaching, rig evacuation, muster area's, shutting down all sources of ignition, fire response, man down and first aid. Also
talked about H2S, hydrates and roles and responsibilities while drilling. Pull motor to surface and check bit, 2 chopped cutters on gauge row. Cont P/U remaining
BHA components. M/U 8" GWD & 8" DM collar. Perform RFO MWD to GWD 1.45" - 7.75"= 67.35 deg. Motor to MWD 1.65" - 7.75" = 76.65 deg. M/U 8" EWR-M5,
8" TM. Download MWD tools. Having connection issues w/ computer. Cont P/U 2 ea 8" NM FC, 8" Bottle Neck X/O and 1 stand 5" HWDP. Wash down F/ 164' to
221' MD 375 gpm 450 psi 40 rpm Trq 750 ft/lb no fill. Increased flow rate to 400 gpm due to trouble getting detection. Shallow pulse test MWD. Slide/ Drill 12.25"
Hole F/ 221' to 260' MD (260' TVD) Total 39' (AROP 78') 400 gpm, psi on 520, psi off 510, 40 rpm, TRQ on 1k, TRQ off 1k, wob 2-4k. ECD 9.15, MW in/out 8.8,
Max Gas 0u. P/U 52k, SLK 52k, ROT 51k. Jet flowline as needed. Daily disposal G&I: 0 bbls total 0 bbls. Daily disposal MPU G&I: 0 bbls total 0 bbls. Daily H2O
Lake 2: 560 bbls total 560 bbls. Daily DH losses: 0 bbls total 0 bbls.
7/5/2023 Slide/ Drill 12.25" Hole F/ 260' - T/ 848' MD (839' TVD) Total 588' (AROP 98') 400 gpm, psi on 997, psi off 727, 40 rpm, TRQ on 2.4k, TRQ off 2.4k, wob 8-14k.
ECD 9.62, MW in/out 8.9/9.0, Max Gas 0u. P/U 71k, S/O 71k, ROT 71k. KOP 317' MD. 4/100' DLS per WP04. Clean MWD @ 794' MD. Slide/ Drill 12.25" Hole F/
848' to 1,420' MD (1,338' TVD) Total 572' (AROP 95.3') 425/450 gpm, psi on 1201, off 1,115, 40 rpm, TRQ on 5-6k, TRQ off 2-3k, wob 8-14k. ECD 9.98, F/O 56%.
MW in/out 9.15/9.2, Max Gas 0u. P/U 78k, SLK 74k, ROT 76k. Jet flowline as needed. Cont 4deg/100 Build/Turn. Slide/ Drill 12.25" Hole F/ 1,420' to 1,612' MD
(1,474' TVD) Total 192' (AROP 96') 450 gpm, psi on 1255, off 1,181, 40 rpm, TRQ on 5-6k, off 2-3k, wob 8-14k. ECD 9.98, F/O 56%. MW in/out 9.2/9.35, Max Gas
0u. P/U 80k, SLK 75k, ROT 78k. Jet flowline as needed. Cont 4deg/100 Build/Turn. Slide as needed. Found leak F/ Pod Bore seal around and suction tube gasket.
Shut in MP #2 and C/O bore seal and gasket. Tested pump, found bad Vectolic seal. Rot/Rec W/ MP #1 F/ 1,610' to 1,578' 265 gpm 425 psi F/O 41% 20 rpm Trq 2-
3k ECD 9.96. P/U 80k SLK 74k ROT 78k. Replaced Victolic seal on MP #2. Test, good. Rot/Rec W/ MP #1 F/ 1,610' to 1,578' 265 gpm 425 psi F/O 41% 20 rpm
Trq 2-3k ECD 9.96. P/U 80k SLK 74k ROT 78k. Slide/ Drill 12.25" Hole F/ 1,612' to 1,738' MD (1,551' TVD) Total 126' (AROP 63') 450 gpm, psi on 1267, off
1,181, 40 rpm, TRQ on 5-6k, off 2-3k, wob 8-14k. ECD 10.5, F/O 56%. MW in/out 9.4, Max Gas 0u. P/U 82k, SLK 74k, ROT 76k. Jet flowline as needed. Cont 4
deg/100 Build/Turn. Slide as needed. Slide/ Drill 12.25" Hole F/ 1,738' to 1,897' MD (1,660' TVD) Total 159' (AROP 79.5') 450 gpm, psi on 1313, off 1,125, 40 rpm,
TRQ on 5-6k, off 2-3k, wob 8-14k. ECD 10.5, F/O 56%. MW in/out 9.4, Max Gas 34u. P/U 83k, SLK 74k, ROT 77k. Jet flowline as needed. End 4 deg/100 at 1,876'
MD. Increase MW F/ 9.2 to 9.5 ppg prior to BPF. At 1,897 MD heavy hole unloading and shakers blinding off. Reduced pump rate down to 300 gpm 530 psi.
Rot/Rec F/ 1,897 to 1,860 MD 300 gpm 530 psi. Increased H2O to 40 bph unable to keep up with shakers running over. Rack back 1 stand. Circ at 125 gpm 208
psi to replace 2 shaker bolts on. on shaker #2 and 1 shaker bolt on MP #1. Screened down to 120s on shaker #2. Called out for 290 bbls 9.5 ppg Spud Mud F/ mud
plant. Shakers continue to be blinding off attempting to drill ahead at 375 gpm at reduced ROP. Slide/ Drill 12.25" Hole F/ 1,897' to 2,040' MD (1,719' TVD) Total
143' (AROP 71.5') 375/450 gpm, psi on 1370, off 1,093, 40 rpm, TRQ on 4-6k, off 3-4k, wob 5-14k. ECD 10.3, F/O 45%. MW in/out 9.5, Max Gas 61u. P/U 84k,
SLK 75k, ROT 79k. Jet flowline as needed. Cont tangent 58.91 deg inc 226.70 deg azi. Distance to WP04:15.76', 15' High, 2.5' Left. ROT Hrs:0.79. SLD Hrs:
11.08. Daily disposal G&I: 627 bbls total 627 bbls. Daily disposal MPU G&I: 0 bbls total 0 bbls. Daily H2O Lake 2: 700 bbls total 1260 bbls. Daily DH losses: 0 bbls
total 0 bbls.
7/6/2023 Slide/Drill 12.25" Hole F/2040' - T/2756' MD (2088' TVD) Total 716' (AROP 120') 450GPM, 1168/1065psi on/off. 80RPM, TRQ 5-7K/2-3Kft-lbs on/off, WOB 5-10K.
ECD 10.62, MW in/out 9.55/9.6, Max Gas 4012u, BGG 1500-3700u. P/U=90K, S/O=64K, ROT=84K. Base of Permafrost = 2,072'. Backreaming Full stands.
Reducing flow rate as necessary to 400-425GPM to mitigate shakers overflowing. Maintaining the 59 degree tangent targeting 226.70 AZM. Slide/Drill 12.25" Hole
F/2756' - T/3425' MD (2445' TVD) Total 669' (AROP 111') 450GPM, 1370/1161psi on/off. 80 RPM, TRQ 7K/5-7Kft-lbs on/off, WOB 5-10K. ECD 10.65, MW in/out
9.55/9.6, Max Gas 3888u, BGG 1500-2300u. P/U=107K, S/O=73K, ROT=84K. Continue Backreaming full stands. Slide/ Drill 12.25" Hole F/ 3,425' to 4,075' MD
(2,785' TVD) Total 650' (AROP 108') 450 gpm, psi on 1465, off 1,305, 80 rpm, TRQ on 7-8k, off 7k, wob 5-10k. ECD 10.65, F/O 62%. MW in/out 9.55/9.7, Max
Gas 3471u. P/U 116k, SLK 72k, ROT 94k. Jet flowline as needed. Back ream 60'. Slide as needed to maintain 58.91 deg inc 226.7 deg azi. Slide/ Drill 12.25" Hole
F/ 4,075' to 4,471' MD (2,984' TVD) Total 396' (AROP 66') 375/450 gpm, psi on 1783, off 1,520, 80 rpm, TRQ on 9-11k, off 8-9k, wob 6-15k. ECD 10.29, F/O 58%.
MW in/out 9.5/9.5, Max Gas 2965u. P/U 119k, SLK 71k, ROT 94k. Jet flowline as needed. Back ream 60'. At 4,180 MD (Ugnu 4) encountered shakers screens
blinding off with heavy silt and oil. Reduced flow to 375 gpm and continued drilling ahead. At 4,242 MD was able to stage pumps up to 425 gpm. Cont adjusting
flow rate to control shakers running over. Slide as needed to maintain tangent. Distance to WP04:5.43', 5.34' Low, 0.61' Right. ROT Hrs:10.75. SLD Hrs: 3.0. Daily
disposal G&I: 798 bbls total 1425 bbls. Daily disposal MPU G&I: 399 bbls total 399 bbls. Daily H2O Lake 2: 1120 bbls total 2380 bbls. Daily DH losses: 0 bbls total
0 bbls.
7/4/2023Spud Date:
Well Name:
Field:
County/State:
PBW L-253
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
50-029-23758-00-00API #:
7/7/2023 Slide/Drill 12.25" Hole F/4471' - T/5044' MD (3270' TVD) Total 573' (AROP 96') 450-500GPM, 1929/1830psi on/off. 80RPM, TRQ 10-12K/10-11Kft-lbs on/off,
WOB 7-12K. ECD 10.84, MW in/out 9.5/9.65, Max Gas 1399u, BGG 300-1300u. P/U=128K, S/O=79K, ROT=99K. Performing maintenance slides as necessary for
59 degree tangent, targeting an AZM of 224 degrees. Backreaming Full Stands. Reducing flow rate as needed to avoid over flowing the shakers. Slide/Drill 12.25"
Hole F/5044' - T/5,491' MD (3,497' TVD) Total 447' (AROP 74.5') 450-500GPM, 2125/1905psi on/off. 80RPM, TRQ 12/13Kft-lbs on/off, WOB 8-18K. ECD 10.97,
MW in/out 9.6/9.7, Max Gas 1996u, BGG 100-1200u. P/U=137K, S/O=80K, ROT=100K. Back ream 60'. Slide as needed. Slide/ Drill 12.25" Hole F/ 5,491' to
6,200' MD (3,865' TVD) Total 709' (AROP 118') 500 gpm, psi on 2,130, off 2,010, 80 rpm, TRQ on 15-16k, off 14-15k, wob 8-15k. ECD 10.74, F/O 51%. MW in/out
9.7/9.7.5, Max Gas 2407u. P/U 146k, SLK 78k, ROT 109k. Jet flowline. Back ream 60'. Slide as needed. Slide/ Drill 12.25" Hole F/ 6,200' to 6,634' MD (4,094'
TVD) Total 434' (AROP 72') 515 gpm, psi on 1,994, off 1,780, 80 rpm, TRQ on 16-18k, off 15-16k, wob 9-15k. ECD 10.69, F/O 51%. MW in/out 9.6/9.7, Max Gas
1480u BGG 1000. P/U 161k, SLK 78k, ROT 114k. Jet flowline. Back ream 60'. Slide as needed. Start Build/ Turn 4 deg/ 100' at 6,570 MD. Distance to WP04:
12.32', 10.71' High, 6.09' Right. ROT Hrs:11.57. SLD Hrs: 3.27. Daily disposal G&I: 1031 bbls total 2456 bbls. Daily disposal MPU G&I: 513 bbls total 912 bbls.
Daily H2O Lake 2: 1260 bbls total 3640 bbls. Daily DH losses: 0 bbls total 0 bbls.
7/8/2023 Slide/Drill 12.25" Hole F/6634' - T/7016' MD (4267' TVD) Total 382' (AROP 64'). 515GPM, 2263/2060psi on/off. 80RPM, TRQ 16-18K/15-17Kft-lbs on/off, WOB 5-
18K. ECD 10.91, MW in/out 9.6/9.6, Max Gas 1522u, BGG 250-600u. P/U=171K, S/O=81K, ROT=114K. Drilled T/7016' and completed a 290 bbl 9.5ppg dilution
to help cool the mud. Slide/Drill 12.25" Hole F/7016' - T/7319' MD (4375' TVD) Total 303' (AROP 50.5'). 515GPM, 2199/2035 psi on/off. 80RPM, TRQ 16-18K/15-
17Kft-lbs on/off, WOB 9-15K. ECD 10.3, MW in/out 9.4/9.55, Max Gas 1965u, BGG 350-650u. P/U=169K, S/O=82K, ROT=112K. Predominantly sliding 70% of the
time to maintain the 4deg/100' build/turn as per wp04 targeting 210 degree Azm. Backreaming full stands. Fault #1 at 7,319' MD 4,373' TVD throw 27' DTS F/ OBd
clay to OBa sand. Slide/ Drill 12.25" Hole F/ 7,319' to 7,725' MD (4,479' TVD) Total 406' (AROP 67.6') 525 gpm, psi on 2,336, off 2,095, 80 rpm, TRQ on 17-18k,
off 13-16k, wob 8-15k. ECD 10.7, MW in/out 9.5/9.6. Max Gas 1428u. P/U 170k, SLK 79k, ROT 111k. Jet as needed. Back ream 60'. Cont 4 deg/ 100' Build/Turn.
Fault #2 at 7,492' MD 4,424' TVD throw 37' F/ OBd clay to OBd sand. Slide/ Drill 12.25" Hole F/ 7,725' to 7,841' MD (4,494' TVD) Total 116' (AROP 58') 525 gpm,
psi on 2,265, off 2,160, 80 rpm, TRQ on 17-18k, off 13-16k, wob 8-15k. ECD 10.7, MW in/out 9.5/9.6. Max Gas 819u. P/U 161k, SLK 81k, ROT 114k. Jet as
needed. Back ream 60'. Cont 4 deg/ 100' Build/Turn. PJSM While making up to stand 113 Trq was off. Racked back stand and checked saver sub. Appeared to be
slightly galled. Made up to stand 112 and checked threads 112 had galled box. Decision was made to C/O Saver Sub. Monitor well 10 min, static. M/U FOV & Head
Pin. Rack back and. flag stands 112 & 113 on ODS. Circ 3 bpm 540 psi. Max Gas 765u. Remove wire ties. Break down feder rings and remove saver sub. Install
new saver sub. Install feder rings and wire tie back up. Slide/ Drill 12.25" Hole F/ 7,841' to 7,968' MD (4,504' TVD) Total 127' (AROP 50.8') 525 gpm, psi on 2,283,
off 2,100, 80 rpm, TRQ on 16-17k, off 13-16k, wob 8-15k. ECD 10.43, MW in/out 9.5/9.65, Max Gas 1,641u. P/U 162k, SLK 82k, ROT 114k. Jet as needed. Back
ream 60'. Drill ahead as per Geo. Distance to WP04: 15.31', 5.74' High 14.2' Right. ROT Hrs: 5.03. SLD Hrs: 8.16. Daily disposal G&I: 1197 bbls total 3653 bbls.
Daily disposal MPU G&I: 228 bbls total 1140 bbls. Daily H2O Lake 2: 1400 bbls total 5040 bbls. Daily DH losses: 0 bbls total 0 bbls.
7/9/2023 Slide/Drill 12.25" Surface Section F/7,968' - T/8,130' MD (4,521' TVD), Total 162' (AROP 81') Where GEO called Surface TD. 525GPM, 2342/2130psi on/off.
80RPM=18-19K/16-17Kft-lbs on/off TQ, WOB 5-18K. ECD 10.54, MW in/out 9.5/9.65, Max Gas 731u, BGG 300-600u. P/U=162K, S/O=82K, ROTW=114K.
Obtained Final survey at TD (8130'), Survey Depth 8076.86'MD (4520.40' TVD), 86.44 Inc, 180.68 Azm, TD Projection from wp04: 20.63' from plan, 12.32' Low,
16.55' Right. Pump 9.5ppg 35 bbl Hi-Vis sweep (400FV), no increase in cuttings. Racked back 1 stand for every bottoms up F/8,130' - T/7,906'. 550GPM=2135psi,
F/O=56%. 80RPM=16-18Kft-lbs TQ. Max Gas 2006u. P/U=162K, S/O=79K, ROTW=115K. ECD's before 10.57ppg, after 10.23ppg. Finished Circulating a total of
3 bottoms up after crew change. Tripped back to bottom F/7,906' - T/8,130' MD. Monitored the well for 10 mins - No flow. BROOH F/8,130' - T/ 5,220' MD at 20-
30fpm. 550GPM=2005psi, 10.25 ECD. 80RPM=14-15K ft-lbs TQ. 55% flow. Max Gas 2225u. P/U=160k, S/O=76k, ROTW=101k. Dynamic losses ~7 bph, lost
22.5 bbls. PJSM Replaced swab on MP #1 Pod #4. Rot/ Rec F/ 5,220' to 5,160' MD 250 gpm 590 psi P/U 150k SLK 68k No losses. Max Gas 804u. BROOH F/
5,220' to 3,650' MD 550 gpm 1,650 psi 80 rpm Trq 9-10k F/O 53% Max Gas 2,598u BGG 500-900u ECD 10.29 MW in/out 9.5/9.6 Pull speed 20-30 fpm. P/U 119k
SLK 71k ROT 90k. CBU F/ 4,720' to 4,540' MD Lost 22.5 bbls. BROOH F/ 3,650' to 2,160' MD 550 gpm 1,650 psi 80 rpm Trq 9-10k F/O 53% Max Gas 2,249u
BGG 500-900u ECD 10.59 MW in/out 9.6/9.6 ppg Pull speed 20-30 fpm. F/ 2,160 to 1,945 MD encountered erratic trq F/ 6-16k swings W/ 1-4k over pull, reduced
RPMs F/ 80 stepping down to 40 rpm, flow rate F/ 550. to 475 gpm 1,080 psi no packing off observed. Adjusted pull speed F/ 1-15 fpm. No real increase at shakers.
Cont BROOH F/ 1,945 to 1,667 MD. W/ 475 gpm 1,080 psi 40 rpm Trq 5.5-8k F/O 49% Max Gas 1,184 BGG 400-600u. ECD 10.48. MW in/out 9.6/9.7 ppg. Pull
Speed 10-20 fpm. P/U 94k SLK 62k ROT 78k. F/ 1,667' to 1,610' MD Adjusting pull speed (1-5 fpm) as high trq dictates, no issue with pump pressure. Same
parameters. Lost 19 bbls. Distance to WP04: 20.27', 12.58' Low 15.9' Right as per GEO. ROT Hrs: 0.97. SLD Hrs: 2.1. Fault #1 at 7,319' MD 4,373' TVD throw 27'
DTS. Fault #2 at 7,492' MD 4,424' TVD throw 37' DTS. Daily disposal G&I: 746 bbls total 4399 bbls. Daily disposal MPU G&I: 57 bbls total 1197 bbls. Daily H2O
Lake 2: 840 bbls total 5880 bbls. Daily DH losses: 43 bbls total 43 bbls.
7/10/2023 Continue Backreaming F/1,610 - T/723' MD. 475GPM=980psi, F/O=49%, ECD's= 10.18 MW=9.6/9.7 in/out. Max Gas=568u, BG=150-400u. P/U=78K, S/O=64K,
ROTW=69K. F/1,610' - T/1,590', Pulling speed was reduced to 1-15fpm due to TQ Stall (16K). Increased TQ and worked through. Increased Pulling speed T/20-
30fpm F/1,590 - T/723' at 475 GPM. Attempted to pull on elevators - No go, 30K overpulls. Monitored the well for 10 mins at HWDP - No Flow. Reamed out F/723 -
T/524' and attempted to pull on elevators again - No go, Shakers not unloading. Reamed out F/524' - T/410', 350-425GPM, 25 RPM=3-4Kft-lbs TQ working TQ up
to 15K. At 410' we were able to pull out on elevators. P/U=69K, S/O=60K, ROTW=64K. POOH on elevators racking back the 5" HWDP and Jar F/410' - T/164' MD.
P/U=54K, S/O=54K. Lost 30 bbls. L/D 12-1/4" Directional Assembly: NC50 x 6-5/* REG XO, Non Mag FC's and Download MWD. L/D DM, TM, GWR, PWD, 1.5
Deg Motor and Bit. Bit Grade: PDC 1-3-CT-G-X-I-ER-TD, TRI: 2-2-WT-A-F-I-ER-TD. P/U=44K, S/O=44K. Clean and Clear Rig Floor. L/D Bit and BHA Handling
Equipment. Open up hatches on Flow line and Flush. Rig Up Parker TRS. Bring up 250T 9-5/8" Elevators, Casing Tongs, Slips, Dog Collar and bail extensions.
M/U and TQ Volant to 30Kft-lbs+. Stage Shoe track in Shed and count pipe, 205 total joints in shed. Bring up 69 centralizers to the rig floor and stage ODS. Run 9-
5/8" 40# L-80 TXP-BTC Casing From Surface - T/530' MD, Torquing to 20,960ft-lbs (optimum). M/U Shoe, Blank Jt. FC (Top Hat Installed), BA and Joint #5 Forum-
Lok Connections. Run Casing as per tally installing 9-5/8"x12-1/4" Centralizers. Fill pipe every five joints, circulating every ten. Wash down 4BPM F/324' - T/406'
due to tight hole. Running Speed 40-50fpm. P/U=50K, S/O=49K. Observed calculated displacement for first 10 joints. Contt RIH 9.625" 40# L-80 TXP BTC Csg F/
530' to 3,456' MD Run speed 35-40 fpm. Fill every 5 jnts, top off 10. Trq TXP BTC 20,960 ft/lb. Install SB Centralizers as per tally. P/U 141k SLK 80k. Calc 42 bbls
Act 0 bbls, Lost 52 bbls. At 2,053 md encountered tight spots working down to block WT (36k). Pumped down F/ 2,053 to 2,247 MD (BPF 2,072 MD) (BU over 5
stands) staging up F/ 3 bpm 130 psi to 5 bpm 145 psi. Max Gas 601u. Heavy sand, silt and minor wood at shakers. Shakers cleaned up after BU. Contt RIH 9.625"
40# L-80 TXP BTC Csg F/ 3,456' to 5,103' MD Run speed 35-45 fpm. Fill every 5 jnts, top off 10. Trq TXP BTC 20,960 ft/lb. Install SB Centralizers as per tally. P/U
212k SLK 88k. Wash down Circ DS volume F/ 5,103 to 5,349 MD (6 Jnts) Staging pumps up to 7 bpm 321 psi F/O 36%. No dynamic losses. Max Gas 612u. Contt
RIH 9.625" 40# L-80 TXP BTC Csg F/ 5,349' to 5,554' MD Run speed 35-45 fpm. Fill every 5 jnts, top off 10. Trq TXP BTC 20,960 ft/lb. Install SB Centralizers as
per tally. P/U 212k SLK 88k. Calc 36 bbls Act 7 bbls, Lost 29 bbls. Daily disposal G&I: 342 bbls total 4741 bbls. Daily disposal MPU G&I: 114 bbls total 1311 bbls.
Daily H2O Lake 2: 560 bbls total 6440 bbls. Daily DH losses: 72 bbls total 115 bbls.
7/11/2023 Run 9-5/8" 40/47# L-80 Casing F/5,554' - T/8,130' CSG MD as per Tally, tagging TD on Depth. Make up ES cementer at 5,885' CSG MD, Forum-Lok both box/pin
connections and torqued to 15,000ft-lbs (diamond). Filled pipe at 5,775' and observed no returns, staged pumps up from 1BPM to 4BPM while reciprocating
gaining back returns (pumped away 12 bbls), washing F/5,775' - T/5,842' CSG MD. Continued in the hole T/ 7,797' and had to replace the cup on the Volant. 75
total Centralizers Ran. TQ 40# CSG T/20,960ft-lbs and 47# CSG T/23,820ft-lbs. Filling every 5 joints and breaking circulation every 10 joints. Total loss on trip was
57bbls, Calc=78bbls, Actual=135bbls. Circulate and condition mud, reducing YP<20cP. Staging Pumps up from 3BPM to 7BPM, observing slight seepage at
7BPM - Reduced to 6BPM. Rotate and reciprocate F/8,122' - T/8,060' CSG MD at 1-5 RPM (TQ Stall set at 14,000ft-lbs). P/U=278K, S/O=110K. SIMOPS: Remove
CSG Equipment, R/U HES Cementers, C/O Drag Chain Bearings and remove excess mud from pits. Break out of Volant ensuring break out - No issues. Rigged Up
Cement Lines and Manifold and shut in LWR IBOP. PJSM - Pumping 1st Stage Cement: HES Pump 5bbls H2O, PT Lines to 500/4000psi, Set HES Kick out to
2500psi. HES pump 60 bbls of 10.0ppg Spacer (4# Red Dye and 5# Pol-E-Flake). 4.1 BPM = 295psi, Release F/ CRT, Drop ByPass Plug. (Wet 18:00) HES pump
353 bbls (845sx) of Lead 12ppg. EconoCem I/II 2.347 yield 4.7 BPM=400psi, 82 bbls (400sx) of Tail 15.8ppg HalCem I/II 1.155 yield. 3.5BPM=525 psi, Release F/
CRT & Drop shut off plug. HES Pump 20 bbls of H2O. 7.3BPM=475psi, Rig Pump (MP 1) 405.5 bbls of 9.8ppg Mud. 6BPM=450psi, Stop Rot/ Rec gradually
losing down weight. P/U 281k SLK 95k. HES Pump 80 bbls of 10.0ppg Tuned Spacer 4.9BPM=600psi. Rig Pump 99.9 bbls of 9.8ppg Mud. Slowed to 3.5 BPM
last 15 bbls = FCP 825psi. Bump Calc = 600.7 bbls Actual = 605.27 bbls, Press up 500 psi over to 1325psi. Hold 1325psi for 5 mins,. Bleed off, check floats,
good. CIP at 21:50. Rig pumped 6BPM shifting ES open at 2,991 psi. No losses during job. Circulate through ES at 6 bpm adjusting flow rates due to cement and
clabbered up mud. Circ 1-7 bpm 630 psi Started dumping over board after 2 BU. Cont adjusting flow rates as needed due to clabbered up mud. After 6 BU was able
to shut down. Dumped total 529 bbls, 60 bbls spacer,~ 80 bbls cement & 389 bbls Spud Mud and black H2O.Shut down. Blow down TD. Disconnect Knife Valve.
Drain stack and flush W/ Black H2O cycle Annular 3X. Connect Knife Valve. Line back up and break Circ at 6 bpm increased to 7 bpm 615 psi cycling pumps up to.
8 bpm intermittently dumping clabbered mud. Prep for 2nd stage. Haul off surface mud. Daily disposal G&I: 421 bbls total 5162 bbls. Daily disposal MPU G&I: 699
bbls total 2010 bbls. Daily H2O Lake 2: 980 bbls total 7420 bbls. Daily DH losses: 57 bbls total 172 bbls.
7/12/2023 Circulated and conditioned the mud for the 2nd stage Cement job, MW 9.6ppg, YP 14cP, 7BPM=575psi. Pumped a 30bbl Hi-Vis Sweep. sweep returned on time
with no increase in cuttings. PJSM - Pumping 2nd Stage Cement. HES Pump 5bbls H2O, PT Lines to 1550/3000psi, Set Kickouts to 2200psi. HES Pump 60bbls of
10.0ppg Tuned Spacer (4# Red Dye & 5# Pol-E-Flake). 4.1BPM=245psi, HES Pump 356bbls (701sxs) 10.7ppg Lead ArcticCem Type H (Wet 08:28) Yield 2.855
4.9BPM=400psi. HES Pumped 56bbls (400sxs) 15.8ppg Tail Cement HalCem Type I/II (Wet 09:57) Yield 1.165 3.5BPM=400psi. Release F/CRT and drop closing
plug. Rig Pump (MP1) 144.5bbls (Calc=145.3bbls) of 9.6ppg Mud at 5BPM ICP=301psi FCP=761psi. Slowed to 4BPM last 14 bbls FCP=685psi. Engaged Plug on
depth increasing pressure to 1,696psi observing ES Cementer shifting closed. CIP 10:52. Held pressure for 5 minutes - Bled off and observed no flow back.
Overboarded 60 bbls of Spacer and 281bbls of Cement. Drain stack and flush with black water while functioning bag x3. Disconnect first section of diverter from
stack. Lift Stack and set Emergency slips. Lower Stack and wait on cement. SIMOPs: Blow down to cementers and R/D Volant. N/D 16" Diverter. Clear and clean rig
floor. Haul off excess mud and clean pits. Work on boiler #2. Clean and clear flow line. PJSM Lift and drain stack. Prep for Vault rep cutting 9.625" Csg. Clean out
cellar. Vault rep rough cut 9.625" Csg (28.81') Set down stack and johnny whack W/ black H2O. C/O 9.625" elevators to 5" hydraulic. PJSM Drain stack. N/D knife
valve, bell nipple & stack. Remove grub screws on bottom of diverter Tee and lift off conductor. Clean set down diverter tee in cellar. PJSM Clean cellar box. Vault
rep dress 9.625" csg stump. N/U tubing spool. SIMOPS P/U RCD head and set on stack. Set stack on pedestal. Daily disposal G&I: 921 bbls total 6083 bbls. Daily
disposal MPU G&I: 920 bbls total 2930 bbls. Daily H2O Lake 2: 980 bbls total 8400 bbls. Daily DH losses: 0 bbls total 172 bbls.
7/13/2023 Finish installing wellhead and test void to 500/3750psi for 5/5 mins - Good. N/U BOP. Install DSA and Set stack on DSA - Torque. Hook up Choke and Kill Lines.
Install MPD riser, center and chain down BOP stack. SIMOPS: Clean Pits, Change out seats/valves on MP#2 and Welder repair degasser discharge. Open doors to
inspect and clean/grease rams - bolt back up. 2-7/8x5-1/2" in UPR and 7" Solid in LPR. Dress shaker screens with API 140. Set Test Plug. Stage 4.5", 5" and 7"
Test joints in shed. M/U Test Joint, side entry sub, 5" TIW and 5" Dart. Energize accumulator and fill stack. PJSM Purge air and function annular, rams, Choke
Manifold valves and top drive. Perform a Safety Meeting with Hilcorp representative Taylor Wellman to talk about incidents within the field. Perform shell test
250/3,000 psi 5 min found 5" Dart leaking. Replaced and re flooded lines. Pressure up again and still slight bled down, trouble shoot. Found Mezz Kill leaking, work
on off line. Performed shell test, good. SIMOPS: Changing bearings on drag chain and MP#1 inspection. PJSM Perform BOPE test W/ 4.5", 5" & 7 to 250 PSI low
and 3,000 PSI high for 5 Min. Tested Choke Manifold 1-15, 5" Dart, 2 ea 5" TIW, 4 TIW, Upper and lower IBOP, Mez Kill, HCR Choke, HCR Kill, manual Choke and
Kill, Super Choke and manual to 1,800 PSI, Use 7 for LPRs (7 solid body), Use 4.5. & 5 for Upper VBR (2.875 X 5.5 VBRs) & 4.5 Annular. Checked PVT sensors
and return flow. PVT high/ low level alarms. Test H2S 10-20 ppm, LEL 20-40%, Koomey draw drown initial System 3,150 PSI, Manifold 1,400 PSI, Annular 1,225
PSI, after System 1,500 PSI, Man 1,500 PSI, Annular 1,200 PSI. 200 PSI increase 29 Sec, full charge 104 sec. Nitrogen 6 bottle average 2,305 PSI. Closing times
Ann 11 sec, UPR & Blinds 9/10 sec, LPR 9 sec, HCR Choke & Kill 1/1 sec. Used H2O for test. Witnessed waived by AOGCC Rep Kam StJohn. SIMOPS Bring on
580 bbls 9.2 ppg BaraDril N to Pits. PJSM Break down Dart, TIW, pump in sub and X/O. L/D Test Jnt. PJSM Drain stack and pull test plug. L/D test plug. Blow
down choke manifold and lines. Line choke manifold for drilling. L/D bad jnt in derrick. PJSM M/U wear ring running tool and set wear ring. (48" lg, 10.75" OD, 9"
ID) L/D running tool. PJSM P/U M/U BHA 2 Clean Out 12.25" RR TriCone XR+CPS and 6.75" 1.5 deg TarraForce motor. RIH W/ 5" 49# S-135 NC50 HWDP and
6.5" HydraJar to 590.69' MD. PJSM Single in hole BHA #2 W/ 5" 19.5# S-135 NC50 D.P. F/ 590' to 2,147' MD. Drift 3.125" OD. P/U 82k SLK 63k Take returns to
drag chain. Fill pipe and wash down F/ 2,147' to 2,274' MD. 2,228' seeing cement stringers. Cont Wash down and drill ES on depth at 2,256' MD Washed and
reamed W/ and without rotary, no issue. 400 gpm 690 psi 30 rpm Trq 4-6k WOB 2-6k F/O 41%. P/U 86k SLK 61 ROT 73k. Daily disposal G&I: 171 bbls total 6254
bbls. Daily disposal MPU G&I: 0 bbls total 2930 bbls. Daily H2O Lake 2: 0 bbls total 8400 bbls. Daily DH losses: 0 bbls total o bbls. Total Surface loss 172 bbls.
7/14/2023 Continue singling in the hole with 5" 19.5# NC50 F/2,274' - T/5,357' MD. Dumping highly viscosified fluid to cuttings box. P/U=138K, S/O=66K. RIH on elevators
with 5" DP out of the derrick F/5,357' - T/7,838' MD. P/U=155k, S/O=62K. Wash down F/7,838' - T/7,964' MD last coupled connection before Baffle Adapter -
racked back one stand. Staged pumps up to 6BPM (600psi). Circulated a total of 3x bottoms up while rotating and reciprocating fighting clabbered up mud and
overboarding as necessary. Treated system with 1 drum of 776-lube due to high torque on the upstroke 8RPM=19-20Kft-lbs. Torque reduced by 3-4Kft-lbs and
getting 40RPM on the upstroke at 14-17Kft-lbs. 450GPM=1175psi, RF=42%, P/U=180K, S/O=80K. Blow down the choke while pumping down the kill. Shut UPR
and flood Choke purging air from system. Conduct 9-5/8" Casing test to 2,649psi (MP#1) for 30 mins (charted). Lost 12 psi in first 15 mins and 3psi on last 15
mins. 5.8bbls pumped, 5.8bbls bled back. R/D Testing Equipment. Wash down F/7,958' - T/8,001' MD engaging Plug and Baffle Adapter on depth. Drill out Plug
and baffle, wiping back over profile without pumps or rotary without issue. Continue drilling shoe track T/8,020' and lost charge pressure, troubleshooted and back
online. Continue drilling Shoe track F/8,020' - T/8,052 MD, Tag FC/Bypass Plug on depth (8,042'). 500GPM=1630psi, RF=45%. WOB=3-5k, 40RPM=16-17Kft-lbs
TQ. P/U=180K, S/O=80K, ROTW=118K.Dumping contaminated mud as necessary. Cont drilling show track F/ 8,052' to 8,137' MD. Shoe on depth 8,122' MD.
Ream 2X ea with/ without rotary, no issue. 425 gpm 1,150 psi 40 rpm Trq 16-17k WOB 3-8k P/U 178k SLK 80k ROT 120k. Dumping clabbered mud as needed.
Total over board 527 bbls. PJSM Drill and displace F/ 8,137' to 8,150' MD. Pump 40 bbl 300+ high vis sweep, chase W/ 9.2 ppg BaraDril N. ROT/ REC F/ 8,150' to
8,090' MD 450 gpm 976 psi 40 rpm Trq 16.5k F/O 43% WOB 3-6k P/U 176k SLK 80k ROT 120k. Monitor well 10 min, static. SPR's. PJSM Blow down choke
manifold. Flood stack and pump through choke manifold. Close UPR'S and use MP #1. Perform FIT to 12.1 ppg EMW on chart. Pressure up to 687 psi after 15 min
606 psi. Pumped 1.5 bbls, bled 1.3 bbls. Blow down all lines & R/D. PJSM Service rig. Grease TD, Blocks, Spinners, PH8 and check Drawworks. PJSM POOH 5
stands F/ 8,090' to 7,710' MD no swabbing. Pump Dry Job. Cont POOH racking back 5" D.P. F/ 7,710' to 6,164' MD. P/U 160k SLK 83k Max gas 49u. Calc
Displacement. PJSM Cont POOH racking back 5" D.P. F/ 6,164' to 590 MD. P/U 142k SLK 85k Calc 59.4 Act 63.2 Lost 3.8 bbls. PJSM L/D 11 jnts 5" HWDP & Jar.
Rack back 2 stands 5" HWDP. Drain Motor and break bit. Bit Grade 1-1-WT-A-E-I-NO-TD. M/U New Jar stand and rack back. P/U M/U 2 ea FS (Non Ported
Plunger) and 2 NM FC rack back in derrick. PJSM P/U M/U 8.5" Bit TK66 (0.7777 TFA) 8.5" NRP, 7.625" Geo Pilot 7600 XL, 6.75" ADR, 8.25" ILS, 6.75" DGR,
6.75" PWD, 6.75" DM, 6.75" ALD and 6.75" CTN. 103.32' MD. Daily disposal G&I: 865 bbls total 7119 bbls. Daily disposal MPU G&I: 741 bbls total 3671 bbls.
Daily H2O Lake 2: 870 bbls total 9270 bbls. Daily DH losses: 0 bbls total o bbls. Total Surface loss 172 bbls.
7/15/2023 PJSM - Continue to M/U BHA, 6.75" TM Collar. Download MWD, Pulse test MWD - Good. Load Nuclear sources (Cleared Rig floor of Non-essential Personnel).
RIH with NMFC and float subs. RIH with 5" HWDP and Jars T/430' MD. P/U 5" DP F/430' - T/8,120' MD from shed. Break in GEO-Pilot at 3,290'. increasing RPM's
in increments of 10RPM up to 60RPM while increasing flow rate F/125GPM - T/400GPM. P/U=87K, S/O=60K. Calculated displacement = 126, Actual = 126.
P/U=180k, S/O=69. PJSM Install RCD Bearing. Drain Stack, remove trip nipple. Stab RCD Bearing, tighten Clamp, Pressure test MPD lines to 250/1250psi for
5/5mins - Good. PJSM - Slip and Cut Drilling line. Set TD in slips and hang blocks. Remove 14 wraps (88'). SIMOPS: Pump at 350GPM=785psi, Beyond
F/O=350GPM. Re-calibrate draw works and crown/floor saver. Service Rig: Grease Crown, blocks, Tope Drive, RLA and Link tilt. Check Gear oil on Top drive.
Completed Crown and Wobble EAM. SIMOPS: Continue to pump at 350GPM=780psi, Beyond F/O=350GPM, shearing Mud. 9.2ppg MW and shakers are dressed
with API 140. RIH F/8,120' - T/8,150' MD exiting the shoe without issue. Obtained Slow Pump rates. Washed down at 450GPM=1245psi, Beyond=447GPM,
ECD=10.08ppg, 60RPM=15Kft-lbs TQ. P/U=178K, S/O=81K, ROTW=114K. Tagged bottom with 3-4K, Begin Drilling 8.5" Production Lateral. Drill 8.5" Hole F/
8,150' to 8,598' MD (4,517' TVD) Total 448' (AROP 74.6') 475 gpm/ mpd 472, 1,475 psi on, 1,435 psi off, 90 rpm, TRQ on 16-19k, TRQ off 15-18k, wob 8-12k.
ECD 10.49, MW in/out 9.25/9.3, Max Gas 2,489u. P/U 182kk, SLK 64kk, ROT 110k. MPD 100% open. Drill 8.5" Hole F/ 8,598' to 9,350' MD (4,506' TVD) Total
752' (AROP 125.3') 450/500 gpm/ mpd 499, 1,750 psi on, 1,690 psi off, 120 rpm, TRQ on 13.5k, TRQ off 11k, wob 10-14k. ECD 10.77, MW in/out 9.2/9.25, Max
Gas 2,782u BGG 400-600u. P/U 146kk, SLK 78kk, ROT 106k. MPD 100% open. Back ream 60'. Adjust flow rate to control shakers running over due to gas.
Distance to WP09: 20.5', 9.95' Low 17.92' Right. 6 concretions drilled, total footage of 25 (2.2% of the lateral). Footage OBd 2=53' OBd 3=428' OBd 4=424' OBd
5=236'. Total OBd=1,141'. Daily disposal G&I: 171 bbls total 7290 bbls. Daily disposal MPU G&I: 0 bbls total 3671 bbls. Daily H2O Lake 2: 290 bbls total 9560
bbls. Daily DH losses: 5 bbls total 5 bbls. Total Surface loss 172 bbls.
7/16/2023 Drill 8.5" Hole F/9,350' -T/9,965' MD (4,480' TVD) Total 615' (AROP 103') 500GPM=1850/1760psi on/off, MPD=499GPM F/O.120RPM=13.5K/12K TQ on/off,
WOB=9-13k. MW in/out 9.3/9.3, ECD=10.98ppg. Max Gas 2220u BGG 350-700u. P/U 147K, S/O 76K, ROTW 106K. MPD 100% open. Backreaming Full Stands
(60'). Drill 8.5" Hole F/9,965' -T/10,765' MD (4,456' TVD) Total 800' (AROP 134') 500GPM=1875/1810psi on/off, MPD=499GPM F/O.120RPM=12-11K/11K TQ
on/off, WOB=6-12k. MW in/out 9.25/9.3, ECD=10.97ppg. Max Gas 1686u BGG 300-600u. P/U 138K, S/O 76K, ROTW 104K. MPD 100% open. Backreaming Full
Stands (60'). Drill 8.5" Hole F/ 10,765' to 11,108' MD (4,459' TVD) Total 343' (AROP 98') 550 gpm/ mpd 545, 2,305 psi on, 2,205 psi off, 120 rpm, TRQ on 12-13k,
TRQ off 11-12k, wob 6-15k. ECD 11.2, MW in/out 9.3/9.35, Max Gas 824u BGG 400-800u. P/U 138kk, SLK 76kk, ROT 104k. MPD 100% open. Back ream 60'.
Drilled out the top of OBd at 10,949' MD. Had a leak on MP #2 Pod 1 suction flange seal. Replaced flange seal. ROT/REC F/ 11,108' to 11,040' MD 290 gpm/ MPD
290, 830 psi 60 rpm Trq 8k. P/U 138 SLK 79k ROT 105k Max Gas 919u. Drill 8.5" Hole F/ 11,108' to 11,374' MD (4,447' TVD) Total 266' (AROP 177') 550 gpm/
mpd 545, 2,330 psi on, 2,205 psi off, 120 rpm, TRQ on 12-14k, TRQ off 12-13k, wob 10-15k. ECD 11.4, MW in/out 9.3/9.35, Max Gas 1481u BGG 400-800u. P/U
136kk, SLK 77kk, ROT 105k. MPD 100% open. Back ream 60'. Reentered OBd sand at 11,192' MD. Lost power on rig 23:20. Was bale to get Gen #1 & #2 online
at 23:50. Reset VFD House and MP Diodes. Bring pumps on at 3 bpm 335 psi. Trouble shot and found Turbo failure on Gen #3. Due to flushing of Gen #4 decision
was made to fix Turbo right side on Gen #3 prior to drilling ahead. Establish drilling parameters and run all Equip to check power draw on Gen #1, #2 & 3. CBU
ROT/REC F/ 11,371' to 11,357' MD staging pumps up to 550 gpm/ MPD 545, 1,290 psi 120 rpm Trq 14k ECD 11.08. Max Gas 1332u. Drill 8.5" Hole F/ 11,374' to
11,742' MD (4,446' TVD) Total 368' (AROP 73.6') 550 gpm/ mpd 535, 2,530 psi on, 2,460 psi off, 120 rpm, TRQ on 11.5-14k, TRQ off 8-11k, wob 10-15k. ECD
11.48, MW in/out 9.3/9.4, Max Gas 1773u BGG 400-800u. P/U 134kk, SLK 77kk, ROT 77k. MPD 100% open. Back ream 60'. Distance to WP04: 20.09', 18.29'
Low 8.32' Right. 48 concretions drilled, total footage of 300' (5.8% of the lateral). Footage OBd 1= 793' OBd 2=379' OBd 3=1469' OBd 4=1042' OBd 5=1219'. Total
OBd= 4902'. Footage Out 243'. Daily disposal G&I: 171 bbls total 7290 bbls. Daily disposal MPU G&I: 0 bbls total 3671 bbls. Daily H2O Lake 2: 290 bbls total 9560
bbls. Daily DH losses: 5 bbls total 5 bbls. Total Surface loss 172 bbls.
7/17/2023 Drill 8.5" Hole F/11,742' -T/12,507' MD (4,439' TVD) Total 765' (AROP 128') 500GPM=2080/2020psi on/off, MPD=486GPM F/O.120RPM=11K/9-11K TQ on/off,
WOB=5-11k. MW in/out 9.3/9.4, ECD=10.97ppg. Max Gas 2209u BGG 150-400u. P/U 142K, S/O 81K, ROTW 107K. MPD 100% open. Backreaming Full Stands
(60'). Drill 8.5" Hole F/12,507' -T/13,204' MD (4,428' TVD) Total 697' (AROP 117') 400GPM=1505/1445psi on/off, MPD=398GPM F/O.120RPM=11-13K/11-12K
TQ on/off, WOB=8-10k. MW in/out 9.3/9.5, ECD=10.97ppg. Max Gas 2318u BGG 350-550u. P/U 145K, S/O 77K, ROTW 106K. MPD 100% open. Backreaming
Full Stands (60'). Completed a 290bbl dilution at 12,898' with 9.2ppg BARADRIL-N to help aid in the reduction of MBT levels. Drill 8.5" Hole F/ 13,204 to 13,532'
MD (4,411' TVD) Total 328' (AROP 109.3') 550 gpm/ mpd 525, 2,445 psi on, 2,415 psi off, 120 rpm, TRQ on 12-14k, TRQ off 11-13k, wob 8-14k. ECD 11.5, MW
in/out 9..25/9.45, Max Gas 2555u BGG 700-900u. P/U 1148kk, SLK 69kk, ROT 102k. MPD 100% open. Back ream 60'. Drilled out the top of OBd-1 at 13,429 to
13,523' MD targeting 93 deg azi as per geo. Decision was made to perform open hole side track at 13,030' MD to drop down from the OBd-3 sand to the OBd-5
sand. PJSM BROOH F/ 13,532' to 13,030' MD 525 gpm/ mpd 515, 2,270 psi 120 rpm Trq 12k ECD 11.43 Max Gas 391u P/U 140k SLK 85k ROT 100k. PJSM
Perform open hole side track. Side track F/ 13,030' to 13,070' MD (4,431' TVD). Time drill 25 fph W/ 100% deflection 500 gpm/ mpd 492, 2,145 psi 120 rpm Trq 11-
11.5k WOB 1-3k Max Gas 482u. Starting ABI 90.72 deg Azi dropping to 88.5 deg azi showing good separation. BROOH to 13,030' MD & increased to 75 fph to
13,111' MD on 2nd pass. BROOH to 13,007' MD shut down ROT & pumps. Trip trip in to 13,111' MD and shot survey to verify separation, Initial survey 90.22 deg
azi new survey 88.5 deg azi, good separation. Drill 8.5" Hole F/ 13,070 to 13,331' MD (4,436' TVD) Total 261' (AROP 74.5') 550 gpm/ mpd 525, 2,310 psi on,
2,280 psi off, 120 rpm, TRQ on 14k, TRQ off 11-13k, wob 9-12k. ECD 11.16, MW in/out 9..2/9.25, Max Gas 1995u BGG 600u. P/U 146kk, SLK 71kk, ROT 103k.
MPD 100% open. Back ream 60'. Distance to WP04: 35.83', 32.41' Low 15.29' Left. 48 concretions drilled, total footage of 300' (5.8% of the lateral). Footage OBd
1= 793' OBd 2=379' OBd 3=1469' OBd 4= 1042' OBd 5=1219'. Total OBd= 4902'. Footage Out 243'. Daily disposal G&I: 1321 bbls total 9595 bbls. Daily disposal
MPU G&I: 0 bbls total 3671 bbls. Daily H2O Lake 2: 1160 bbls total 10720 bbls. Daily DH losses: 0 bbls total 5 bbls. Total Surface loss 172 bbls.
7/18/2023 Drill 8.5" Hole F/13,331' -T/14,288' MD (4,415' TVD) Total 957' (AROP 160') 525GPM=2460/2400psi on/off, MPD=522GPM F/O.120RPM=13-16K/10-12K TQ
on/off, WOB=10-14k. MW in/out 9.2/9.2, ECD=11.48ppg. Max Gas 2854u BGG 150-550u. P/U 147K, S/O 55K, ROTW 101K. MPD 100% open. Backreaming Full
Stands (60'). Drill 8.5" Hole F/14,288' -T/14,973' MD. Total 685' (AROP 114') 500GPM=2560/2505psi on/off, MPD=489GPM F/O.120RPM=13-15K/12-13K TQ
on/off, WOB=10-12k. MW in/out 9.25/9.35, ECD=11.6ppg. Max Gas 2469u BGG 150-700u. P/U 152K, S/O 56K, ROTW 102K. MPD 100% open. Backreaming
Full Stands (60'). Drill 8.5" Hole F/14,973' -T/15,618' MD. Total 645' (AROP 108') 500GPM=2470/2405psi on/off, MPD=496GPM F/O.120RPM=14-15K/12-13K
TQ on/off, WOB=10-13k. MW in/out 9.25/9.35, ECD=11.75ppg. Max Gas 2575u. P/U 152K, S/O 45K, ROTW 100K. MPD 100% open. Backreaming Full Stands
(60'). Drill 8.5" Hole F/15,618' -T/15,746' MD. Total 128' (AROP 128') 500GPM=2470/2410psi on/off, MPD=496GPM F/O.120RPM=14-15K/11-13K TQ on/off,
WOB=8-12k. MW in/out 9.25/9.35, ECD=11.75ppg. Max Gas 1895u. P/U 154K, S/O 51K, ROTW 100K. MPD 100% open. Backreaming Full Stands (60'). Obtain
final survey. Rack back stand. Pump tandem sweep (10% increase, on time) and circulate 4x BU racking back stand every bottoms up. At 500 gpm, 2460 psi, 120
rpms, 13-15Kft-lbs, max gas 1977u, ECD 11.65 ppg. Wash and ream to 15746'. Distance to WP4 (projected to TD): 27.0', 26.24' low, 6.36' left. Daily fluid lost on
production hole 0 bbls, total 5 bbls. No faults were crossed. One plugback was drilled: 13030' - 14532'. 73 concretions were drilled for a total footage of 399 (5.2%
of the lateral). Total footage in OBd-1: 793', OBd-2: 379', OBd-3 2254', OBd-4: 1167', OBd-5 2788, Out of zone 243'.
7/19/2023 Pump SAPP train (3 x 40 bbls) followed by 9.1 ppg Quikdrl at 320 gpm, 110 rpms, 15-17Kft-lbs, max gas 128u, ECD 10.88, reciprocating pipe. Drop drift. BROOH
from 15746' to 14841' at 500 gpm, 1750 psi, 120 rpms, 19-21Kft-lbs. Max gas 115u, ECD 11.71 ppg with 9.1 ppg mud. Pull speed 10-35 fpm as hole dictates. P/U
162K, S/O 43K, ROT 108K. BROOH from 14841' to 12350' at 500 gpm, 1710 psi, 120 rpms, 16-19Kft-lbs. Max gas 473u, ECD 11.71 ppg with 9.1 ppg mud. Pull
speed 10-35 fpm as hole dictates. P/U 164K, S/O 62K, ROT 102K. At 13,030' (sidetrack point) trip in hole on elevators and verify in motherbore with ABI's. From
12500'-12400' observe slight pack offs, slow pulling speed to 2-5 fpm to allow hole to clean up. BROOH from 12350' to 10380' at 500 gpm, 1600 psi, 120 rpms, 13-
15Kft-lbs. Max gas 773u, ECD 11.71 ppg with 9.2 ppg mud. Pull speed 10-35 fpm as hole dictates. P/U 149K, S/O 71K, ROT 100K. Slow pulling speed to 1-8 fpm
from 11,000' -10850', and 10420' - 10380' due to slight pack offs and erratic Tq. BROOH from 10380' to 8247' at 500 gpm, 1575 psi, 120 rpms, 12-14Kft-lbs. Max
gas 530u, ECD 10.06 ppg with 9.2 ppg mud. Pull speed 10-35 fpm as hole dictates. P/U 168K, S/O 72K, ROT 115K. Observe slight packoff and erratic tq as BHA
enters show, slow pull speed to 1-6 fpm to allow and clean up. slow rotary to 60 rpms as MWD tools come through shoe.
7/20/2023 BROOH from 8247'' to 8,120'' at 500 gpm, 1500 psi, 60 rpms, 10-12Kft-lbs. Max gas 530u, ECD 10.06 ppg with 9.2 ppg mud. Pull speed 10-35 fpm as hole
dictates. P/U 168K, S/O 72K, ROT 115K. Observe slight packoff and erratic tq as BHA enters shoe, slow pull speed to 1-6 fpm to allow and clean up.
Rotate/Reciprocate from 8,120 to 8,057 while pumping Tandem sweeps, circulating casing clean with 25% increase at shakers. Sweeps back on time. Shut down
and monitor well with MPD chokes, no PSI build. Rig up and remove MPD RCD Bearing and install flow nipple. POOH on elevators racking back 2 stands in Derrick
from 8057' to 7675', no swabbing, pump 25 bbls dry job with corrosion inhibitor. B/D Top Drive and Geo Span. Continue to POOH L/D 5" DP to pipe shed from
7675' to 4200'. Cull pipe for Cat 5 inspection and hard band inspection. Continue to POOH L/D 5" DP to pipe shed from 4200' to 430'. Cull pipe for Cat 5 inspection
and hard band inspection. PUW 64K, SOW 55K. Monitor well, static. L/D BHA, unload sources, download MWD. Bit grade 1-2-CT-N-X-I-NO-TD. Clean and clear
rig floor of BHA components. R/U to run liner. C/O pipe handling equipment, count/verify pipe in shed. Rig up Parker TRS power tongs, M/U safety joint. Inspect
and verify 3rd party equipment. RIH with 6-5/8", 20#, L-80, W563 slotted liner as per detail to 3215'. M/U TQ 7100 ft-lbs. Calculated displacement 17.4 bbls, actual
13.2 bbls. Cont. RIH with 6-5/8", 20#, L-80, W563 slotted liner as per detail from 3215' to 7597'. M/U TQ 7100 ft-lbs. Change out pipe handling equipment to 7".
RIH with 7", 26#, L-80, W563 from 7597' to 7930'. TQ to 9400 ft-lbs. M/U SLZXP liner hanger and 1 stand drill pipe to 8023'. Pump through liner top to ensure clear
at 2 bpm, 56 psi. Obtain parameters 10 & 20 rpms 6500 ft-lbs. P/U 129K, S/O 86K. Calc disp 37.7 bbls, actual 31.6 bbls. R/D Parker casing equipment and clear
rig floor. Rig service: Open TD coffin due to leak. C/O boss fitting o-ring seal on hydraulic system.
7/21/2023 RIH with 6-5/8", 20#, L-80, W563 slotted liner as per detail conveyed on drill pipe from 8023' to 15746' (TD). Set down 10K. P/U 185K, S/O 68K. Calculated
displacement 68.2 bbls, actual 60 bbls. Break circulation. Pump string volume at 6 bpm, 816 psi. Drop 1-1/8" phenolic ball and pump down at 3 bpm, 270 psi. Once
on seat pressure up to 1200 psi and hold for 5 minutes. P/U to 150K and pressure up ot 2200 psi for five minutes. Set down 25K and pressure up to shear out ball
seat at 3804 psi. TOL at 7794.48'. Flood lines and purge air. PT liner top to 1500 psi for 10 minutes - good. POOH laying down drill pipe from 7783' to 4596', cull
pipe for cat 5 inspection. P/U 109K, S/O 81K. Cont. POOH laying down drill pipe from 4596' to surface. L/D liner running tool. Cull pipe for cat 5 inspection. P/U
109K, S/O 81K. RIH with excess drill pipe from derrick to 476', P/U 45K, S/O 44k. POOH laying down drill pipe to surface. Pull wear bushing. Clean and clear rig
floor. Break down safety joint. M/U TIW to VAMTOP XO. Rig up to RIH with 7" tie-back string. R/U power tongs and Tq Turn system. C/O pipe handling equipment.
Service rig: grease and inspect crown sheaves. Grease top drive and blocks. P/U Baker bullet seals. RIH with 7", 29#, L-80, VAMTOP tie-back casing to 1486', Tq
turn connections to 9400 ft-lbs. P/U 65K, S/O 63K. calc displacement 13.2 Actual 9.3 bbls. L/D joints 4, 5. Final drilling report.
60'). Drill 8.5" Hole F/15,618' -T/15,746' MD.
Activity Date Ops Summary
7/22/2023 Continue to RIH with 7", 29#, L-80, VAMTOP Tie Back Csg from 1486' to 4250'. Trq Turn connections to 9,400 ft/lbs. PUW 106K, SOW 87K, Calc 39.6 bbls, Actual
28.9 bbls, Lost 10.7 bbls. L/D Bad Jts #43 to #46. Bad threads. Continue to RIH with 7", 29#, L-80, VAMTOP Tie Back Csg from 4250' and no-go on depth at
7804', observing 3K drag as seals enter. Trq Turn connections to 9,400 ft/lbs. PUW 170K, SOW 110K,,Calculate spaceout: L/D 3 joints. Pick up pup joints 2.89',
19.75' and space out 1.32' off no-go. Land hanger. P/U 170K, S/O 110K. Calc tot disp 39.6 bbls, actual 39.1 bbls,Close bag and apply 500 psi on OA. Strip up until
pressure dumps indicated circ holes on seals are exposed. Displace 9-5/8" x 7" annulus with 162 bbls corrosion inhibited at 4 bpm 198 psi brine followed by 60
bbls diesel for freeze protect at 4 bpm, 500 psi (LRS). Strip down and land tie-back. Drain stack. C/O elevators and M/U pack-off running tool. Set pack off. RILDS.
PT packoff void 500/3000 psi for 10 minutes - good. Rig up LRS on 9-5/8" x 7" annulus. Flood lines. PT annulus to 1500 psi for 30 minutes - good (starting
pressure 1695, 15 min 1644 psi, final 1627 psi). Pumped 2.17 bbls, bled back 2.1 bbls,Clean and clear rig floor of 7" handling equipment. Rig up to RIH with upper
completion, C/O pipe handling equipment. R/U power tongs. Bring Centrilift and spooler to rig floor. Hang sheave in derrick. Bring 100 cannon clamps to rig floor.
Put jewelry in shed in order. RIH with 4-1/2" upper completion. P/U WLEG, RIH with 4-1/2", 12.6#, 13Cr-80, VAMTOP from surface to 715'. Tq turn connection to
4400 ft-lbs. L/D Joint 1 (box) and 2 and swap for 31 and 34. Daily fluid lost to formation 17 bbls, total lost 51 bbls.
7/23/2023 RIH with 4-1/2" upper completion. P/U WLEG, RIH with 4-1/2", 12.6#, 13Cr-80, VAMTOP from 715' to 1205'. M/U 'X' nipple, AHR packer assembly, 'X' nipple and
gauge carrier. Connect TEK wire to gauge carrier. Cont to RIH with 4-1/2" upper completion to 2374' testing gauge carrier every 1000'. Cannon clamps every joint
for first 10, then every other joint. Tq turn connection to 5940 ft-lbs. P/U 58K, S/O 45K. At 2,374' attempt to test Gauge carrier - test failed. Trouble shoot and C/O
testing equipment. Test failed. POOH with 4-1/2" tubing from 2,374' to 1,584', observe 5-8K overpull. At 2,211' drained stack and observed TEK wire parted. Fish
out TEK wire from stack and continue POOH spooling TEK wire. Cont POOH with 4-1/2" tubing spooling up TEK wire to 1307', laying down Gauge Carrier and 'X'
nipple below. Observe balled up parted TEK wire at 1476'. All cannon clamps recovered. P/U 56K, S/O 45K. Calc disp 9.7 bbls, actual 7.2 bbls. RIH with 4-1/2"
upper completion from 1307' to 4097'. Replace gauge carrier with full joint. Replace 'X' Nipple with RHC-M with one with no RHC-M. Call out slickline to pull RHC-
M from assembly. Tq Turn connections to 5940 ft-lbs. P/U 62K, S/O 54K. Calc disp 9.5 bbls, actual 7.1 bbls. Cont. RIH with upper completion on 4-1/2", L-80, JFE
Bear, 12.6# tubing from 4097' making up hanger and land tubing at 8204'. P/U 93K, S/O 66K. Tq turn connections to 5940 ft-lbs. Calc disp 21.8 bbls actual 17.2
bbls. RILDS,Rig up circulating hoses. L/D landing joint. R/D power tongs.
7/24/2023 Displace well to 9.1 ppg corrosion inhibited brine in IA and clean brine down tubing at 3 bpm, 320 psi. Drop ball and rod. Pressure up on tubing to set packer,
observe indication of set at 1800 psi. MIT-T 3500 psi, bleed down to 2000 psi and MIT-IA to 3500 psi. Bleed tubing and observe GLM shear out. Set BPV. Pick up
stack washing tool and flush stack. Blow down top drive, choke and kill lines. N/D BOPE: suck out stack. R/D split bushings, trip nipple, MPD lines, and hole fill line.
T/D choke and kill lines. Hook up bridge cranes and remove binders/chains. Disconnect accumulator lines, pull stack and DSA and rack back. N/U tree. PT hanger
void 500/5000 psi - good. Attempt to PT tree 500/5000 psi. Observe steady drop in pressure on high. Vault rep mobilize TWC. Pull CTS and BPV. PT tree
500/5000 psi. Sim Ops : prep to scope derrick. Load pipe in shed, move break shack, check camp tires. Prep rig floor for move. Pull TWC. R/U squeeze manifold.
Freeze protect well with 95 bbls of diesel and allow to U-tube. Final tubing and IA pressure 130 psi. SimOps: bridal up and install jump pins. Pick up lubricator.
Wells group lubricate in BPV.
7/25/2023 Disconnect interconnects. Scope derrick down. Safe out walkways and prep for rig move. Trucks on location at 01:30,Break rig modules apart and stage on location.
Mobilize Gen mod, mud mod, and pipe shed to Z pad. Walk sub base off L-253. Rig released at 06:00.
Well Name:
Field:
County/State:
PBW L-253
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
50-029-23758-00-00API #:
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
139
55
X Yes No X Yes No 7.5
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes X No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns ?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns ?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
1.17
7/12/2023 Surface
Spud Mud
EconoCem I/II 845 2.35
HalCem I/II 400 1.16
4.7
2,237.85
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 2,212.28 2,237.85
2,258.64 2,255.91
Pup 9 5/8 40.0 L-80 BTC 18.06 2,255.91
17.57 2,276.21 2,258.64
ES Cementer 10 BTC Halliburton 2.73
Pup 9 5/8 40.0 L-80 BTC
8,001.39
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 5,725.18 8,001.39 2,276.21
8,042.43 8,002.82
Baffle Adapter 10 BTC Halliburton 1.43 8,002.82
1.40 8,043.83 8,042.43
9.625" Csg 9 5/8 40.0 L-80 BTC 39.61
FC 10 BTC OSP
Jnt 1 2 ea BS & 4 ea SR 10' from end, 1 ea BS & 2 ea SR jnt 2 & 3. Solid Body Every jnt F/ 4-25, every other F/ jnt
27-73, 1 ea 139-142, 1 ea BS & 1ea SR ES pups, SB 1 ea jnt 144-192, 7 bow springs, 6 stop rings, 69 solid body.
9.625" Csg 9 5/8 40.0 L-80 BTC 76.43 8,120.26 8,043.83
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
Ftg. Returned 283.00
Ftg. Cut Jt.28.81 Ftg. Balance
No. Jts. Delivered 205 No. Jts. Run 198 7
Length Measurements W/O
Threads
Ftg. Delivered 8,405.00 Ftg. Run 8,122.00
26.80 RKB to CHF
Type of Shoe:Conventional Casing Crew:Parker Wellbore
12 353
ES Cementer Closure OK
56
Lead ArcticCem Type H
Type
HalCem Type I/II 400
Tuned Spacer 4# Red Dye & 5# Pol-E-Flake
701 2.85
Stage Collar @
60
Bump press
100
281
8,122.008,130.00
CEMENTING REPORT
Csg Wt. On Slips:50,000
Spud Mud
21:50 7/12/2023 2,256
2255.81
15.8 82
Bump press
ES Cementer
Bump Plug?
3.5
9.6 5 144.5/145.3
605.27/600.7
1325
80
MP #1
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 4# Red Dye and 5# Pol-E-F 60
15.8
761
9.8 6
1696
10
10.7 356 4.9
100
825
Bump Plug?
Csg Wt. On Hook:281,000 Type Float Collar:ES Cementer No. Hrs to Run:18
BTC OSP 1.74 8,122.00 8,120.26
25.47
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-253 Date Run 10-Jul-23
CASING RECORD
County State Alaska Supv.S Barber / O Amend
8,042.43
Floats Held
30 847
361 486
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.8
Shoe @ 8122 FC @ Top of Liner
SE
C
O
N
D
S
T
A
G
E
MP #1
10:52
Cement Returns to Surface
472.3 486 3
Casing (Or Liner) Detail
Shoe
RKB
10
100
281
X
2,256
100
Surface
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: 08/15/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: PBU L-253
PTD: 223-048
API: 50-029-23758-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (07/04/2023 to 07/19/2023)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU L-253 LWD Subfolders:
PBU L-253 Geosteering Subfolders:g
Please include current contact information if different from above.
PTD: 223-048
T37932
8/16/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.08.16
08:54:16 -08'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
WELL: PBU L-253PB1
PTD: 223-048
API: 50-029-23758-70-00
FINAL LWD FORMATION EVALUATION LOGS (07/04/2023 to 07/17/2023)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
PBU L-253PB1 LWD Subfolders:
Please include current contact information if different from above.
8/16/2023
PTD:223-048
T37933
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.08.16
08:53:47 -08'00'
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
July 10, 2023
Ms. Natalie Brent
Senior Reservoir Engineer, Prudhoe Bay West
Hilcorp North Slope, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99519-6612
Re: Docket Number: CO-23-008
Request for a waiver of the gas oil ratio limitations in 20 AAC 25.240(a) for the Prudhoe Bay Unit
L-253 (PTD 223-048) and L-254 (PTD 223-030) wells
Dear Ms. Brent:
By letter dated May 24, 2023. Hilcorp North Slope, LLC (Hilcorp) requested a temporary waiver of the
gas-oil ratio (GOR) limitations in 20 AAC 25.240(a) for the two subject wells to allow the wells to be put
on production to gather performance data and fluid properties while the application to expand the Schrader
Bluff Oil Pool (SBOP) in the Prudhoe Bay Unit (PBU) is being adjudicated by the Alaska Oil and Gas
Conservation Commission (AOGCC). The PBU L-254 is an injector that will be pre-produced for up to
30 days. This pre-production period will help evaluate the potential for drilling additional wells west of
the existing SBOP development wells. The PBU L-253 will also add to the knowledge in that area. Being
able to collect this information while the AOGCC completes its adjudication of the application to expand
the SBOP will allow for the collection of information necessary to determine future development of the
SBOP which is an allowable reason for a waiver pursuant to 20 AAC 25.240(b)(3).
Hilcorp’s request is hereby granted. This waiver shall expire 6 months after date of issuance or
upon the acreage these wells are located on is added to the SBOP, which ever occurs first.
DONE at Anchorage, Alaska and dated July 10, 2023.
Brett W. Huber, Sr. Gregory C. Wilson
Chair, Commissioner Commissioner
Gregory
Wilson
Digitally signed by Gregory
Wilson
Date: 2023.07.10 13:39:12
-08'00'
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.10
13:41:27 -08'00'
Ms. Natalie Brent
July 10, 2023
Page 2 of 2
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the
AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter
determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out
the respect in which the order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act
on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the
denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date
on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS
the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for
reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be
filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision
on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in
the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until
5:00 p.m. on the next day that does not fall on a weekend or state holiday.
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Phone: 907/777-8300 hilcorp.com
Hilcorp North Slope, LLC
May 24, 2023
Brett Huber, Sr., Chair
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, AK 99501
RE: Request for a Temporary Waiver of the Gas-Oil Ratio requirement of 20 AAC 25.240
Chair Huber,
Hilcorp North Slope, LLC, as operator of the Prudhoe Bay Unit, requests a Temporary Waiver of the Gas-
Oil Ratio requirement of 20 AAC 25.240 for wells L-253 and L-254. Initially, these wells will not be part
of the existing Orion PA or Schrader Bluff Oil Pool and will be operating under a tract operation and thus
statewide regulations. We are concurrently working with the AOGCC to expand the Schrader Bluff Oil
pool to include these wells. We plan to work with the DNR to expand the Orion PA shortly after.
As operator, Hilcorp plans to operate these wells similar to other producers in the Schrader Bluff Oil
Pool, Orion Development Area. We will pre-produce L-254 (injector) for 30 days to gather initial
potential and fluid quality data to determine the viability of additional drilling to the west of the existing
Schrader Bluff Oil Pool, Orion Development Area. The L-253 (producer) will be put online to gather
initial potential and fluid quality data. During this flow time, the near wellbore region will see a pressure
drop which will cause the GOR to increase, possibly above the current GOR limitations. This is expected
to be temporary because as soon as the Schrader Bluff Oil Pool, Orion Development Area pool
expansion is approved, L-254 will be converted to an injector and put on produced water and miscible
injectant to maintain reservoir pressure.
Thank you,
Natalie Brent
Senior Reservoir Engineer, Prudhoe Bay West
Hilcorp North Slope, LLC
Digitally signed by Natalie Brent (1028)
DN: cn=Natalie Brent (1028)
Date: 2023.05.24 15:26:42 -08'00'
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp North Slope, LLC
3800 Centerpoint Dr. Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay, Schrader Bluff Undefined Oil Pool, PBU L-253
Hilcorp North Slope, LLC
Permit to Drill Number: 223-048
Surface Location: 2450' FSL, 4165' FEL, Sec. 34, T12N, R11E, UM, AK
Bottomhole Location: 654' FSL, 2532' FWL, Sec. 09, T11N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie Chmielowski
Commissioner
DATED this ___ day of June 2023. 13
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.06.13 10:34:10
-08'00'
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-253
TVD:15887'4388'
12. Field/Pool(s):
MD:
ADL 028239 & 028241
00-001 June 26, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
2450' FSL, 4165' FEL, Sec. 34, T12N, R11E, UM, AK
2120' FNL, 2539' FWL, Sec. 04, T11N, R11E, UM, AK
Kickoff Depth:350'feet
Maximum Hole Angle: 92 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:1984 1533
17.Deviated wells:16.
Surface: x-y- Zone -582751 5978167 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
73.7'
47.2'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
1960'
Surface
15887'
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#
6950'8937'
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
654' FSL, 2532' FWL, Sec. 09, T11N, R11E, UM, AK
Time v. Depth Plot555 5Drilling Program
684'
Stg 2 L - 679 sx / T - 268 sx
(To be completed for Redrill and Re-Entry Operations)
8-1/2"
7"
L-8026#/20#7"x6-5/8"
9-5/8"
4242'
12-1/4"
6950'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
1014'
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 BTC
Vam 21
Vam Top
Hyd 563
2500'
5650'
6950'
Surface
2500'
Surface
2500'
8150'
4242'
1960'
4510'
4388'
Stg 1 L - 805 sx / T - 395 sx
Uncemented Slotted Liner
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured):
Casing Length Size MD
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
80'80'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
UNDEFINED OIL POOL
5.11.2023
By Kayla Junke at 4:07 pm, May 11, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.05.11 15:27:59 -08'00'
Monty M
Myers
DSR-5/12/23
223-048
<-->
SFD 6/10/2023
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing test and FIT digital data to AOGCC immediately
upon completion of performing FIT.
MGR01JUNE2023
50-029-23758-00-00
GCW 06/12/2023
06/13/23
06/13/23
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2023.06.13 10:34:36 -08'00'
Prudhoe Bay West
(PBU) L-253
Drilling Permit
Version 1
5/10/2023
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 6-5/8” Liner ...................................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 40
19.0 Innovation Rig Diverter Schematic ......................................................................................... 44
20.0 Innovation Rig BOP Schematic ............................................................................................... 45
21.0 Wellhead Schematic ................................................................................................................. 46
22.0 Days Vs Depth .......................................................................................................................... 47
23.0 Formation Tops & Information............................................................................................... 48
24.0 Anticipated Drilling Hazards .................................................................................................. 50
25.0 Innovation Rig Layout ............................................................................................................. 54
26.0 FIT Procedure .......................................................................................................................... 55
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 56
28.0 Casing Design ........................................................................................................................... 57
29.0 8-1/2” Hole Section MASP ....................................................................................................... 58
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 59
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 60
Page 2
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU L-253
Pad Prudhoe Bay L Pad
Planned Completion Type 4-1/2” Gas Lift
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 15,887’ MD / 4388’ TVD
PBTD, MD / TVD 15,877’ MD / 4388’ TVD
Surface Location (Governmental) 2,450' FSL, 4165' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582,750.5, Y=5,978,166.7
Top of Productive Horizon
(Governmental)2120' FNL, 2539' FWL, Sec 04, T11N, R11E, UM, AK
TPH Location (NAD 27) X=578,954.8, Y= 5,973,555.3
BHL (Governmental) 654' FSL, 2532' FWL, Sec 9, T11N, R11E, UM, AK
BHL (NAD 27) X= 579,049, Y= 5,965,771
AFE Number 231-00051
AFE Drilling Days 22
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1533 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1984 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 46.9 ft = 73.4 ft
GL/ Pad Elevation above MSL: 46.9 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-253 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” 6.184 6.125 7.644 29 L-80 VAMtop 8160 7030 676
8-1/2” 6-5/8” 6.049 5.924 7.3980 20 L-80 H563 6090 3470 439
Tubing
4-1/2” 3.958 3.833 4.937 12.6 L-80 JFE Bear 8,430 7,500 288
4-1/2” 3.958 3.833 4.937 12.6
L-80
13Cr VAMTOP 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-253 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
_____________________________________________________________________________________
Revised By: JNL 5/11/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-253
Last Completed: TBD
PTD: TBD
TD =15,887’(MD) / TD =4,388’ (TVD)
5
20”
Orig. KB Elev.: 73.7’ / GL Elev.: 47.2’
7”
4
13
9-5/8”
1
2
3
See
Slotted
Liner
Detail
7”x
6-5/8”
XO
PBTD =15,887’(MD) / PBTD = 4,388’ (TVD)
9-5/8” ‘ES’
Cementer @
±2,500’
6-5/8”
Shoe @
15,887’
12
11
10
9
6 87
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 80’ N/A
9-5/8" Surface 47/ L-80 / BTC 8.681 Surface 2,500’ 0.0732
9-5/8” Surface 40 / L-80 / VAM 21 8.835 2,500’ 8,150’ 0.0758
7” Tieback 29 / L-80 / VAMtop 6.184 Surface 6,950’ 0.0383
7” Liner 26 / L-80 / Hyd 563 6.276 6,950’ 8,150 0.0383
6-5/8” Liner 20 / L-80 / Hyd 563 6.049 8,150’ 15,887’ 0.0355
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / JFE Bear 3.958 Surface 8,200’ 0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 1892 ft3 / Tail – 458 ft3
Stg 2 – Lead – 1935 ft3 / Tail – 313 ft3
8-1/2” Cementless Slotted Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 8,200’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. Est Top MD Item ID
1 2,200’ X Nipple 3.813”
2 TBD GLM (2375’ TVD)
3 TBD GLM (3500’ TVD)
4 TBD GLM (4000’ TVD)
5 TBD GLM
6 ~6,950’ 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve
7 ~6,950’ X Nipple (1 full jt plus pups above Production Packer) 3.813”
8 ~6,950’ Liner Top Packer
9 ~6,990’ Production Packer (first full jt below LH/LTP)
10 ~6,950 X Nipple (1 full jt plus pups above lower X-nip)3.813”
11 ~7,000 X Nipple (at 65 degs inc)3.813”
12 TBD WLEG – Bottom @ TBD
13 ~15,887’ Shoe
6-5/8” SLOTTED LINER DETAIL
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
Page 7
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-253 is a grassroots producer planned to be drilled in the Schrader Bluff OBd sands. L-253 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
OBd sand. An 8-1/2” lateral section will be drilled. A 6-5/8” slotted liner will be run in the open hole
section, followed by a 7” tieback and 4-1/2” gas lift tubing.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately June 15, 2023, pending rig schedule.
Surface casing will be run to 8,150’ MD / 4,510’ 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 6-5/8” production 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)
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Prudhoe Bay West
L-253 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-253. 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.
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Prudhoe Bay West
L-253 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-253 SB Producer
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-253 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-253 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.
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Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
Page 13
Prudhoe Bay West
L-253 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 OBd sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in
DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still
meeting tangent hold target.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at
base of perm and at TD (pending MW increase due to hydrates). This is to combat
hydrates and free gas risk, based upon offset wells.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
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Prudhoe Bay West
L-253 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 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.
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Prudhoe Bay West
L-253 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.
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Prudhoe Bay West
L-253 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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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 (8,150'-1,000'-2,500') x 0.0558 bpf x 1.3 337.2 1891.7
Total Lead 337.2 1891.7 805.0
12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.8
9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0
Total Tail 81.6 457.8 394.7LeadTail
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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 + (8,150’-120’-2500’) x .0758 bpf =
= 602.3 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
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
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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):
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 1935.5 679.1
12-1/4" OH x 9-5/8" Casing (2500 - 2000') x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6LeadTail
Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.85 ft3/sk 1.17 ft3/sk
Mixed
Water 14.6 gal/sk 5.08 gal/sk
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Drilling Procedure
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
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 9.85 ppg FIT is the minimum
required to drill ahead
x 9.85 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 digital data for casing test and FIT to AOGCC immediately upon completion of FIT.
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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.
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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 OBd Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C, CF < 1.0:
x There are no wells with CF <1.0
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (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%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
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Drilling Procedure
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 6-5/8” 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 6-
5/8” liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 6-5/8” crossover installed on bottom, TIW valve in open
position on top, 6-5/8” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 6-5/8” 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 6-5/8” liner running equipment.
x Ensure 6-5/8” 24# H563 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 6-5/8” 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
6-5/8” 20# H563 Torque – ftlbs
OD Minimum Optimum Maximum Yield Torque
6-5/8 5900 7100 10300 36000
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Drilling Procedure
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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 ~ 8,000’ 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 6-5/8” liner.
x Confirm with OE any 7” joints between liner top packer and 6-5/8” 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.
Page 36
Prudhoe Bay West
L-253 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.
Page 37
Prudhoe Bay West
L-253 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 if needed. 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”, 29#, L-80 VAMTOP 6.125” Drift tieback to position seal assembly two joints above
tieback sleeve. Record PU and SO weights.
17.7 Tieback to be Torque turned.
7”, 29#, L-80, VAMTOP 6.125” drift
=Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”8460 9400 10340
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Prudhoe Bay West
L-253 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”.
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.
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Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
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.
Page 40
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 4-1/2”, 12.6#, L-80 JFEBEAR tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, JFEBEAR x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RIH with the following 4-1/2” completion jewelry (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 1x X Nipple
x 5x 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 2x X Nipple
x XXX joints, 4-1/2”, 12.6#, L-80, JFEBEAR
x XX joints 4-1/2”, 12.6# 13cr VAMTOP
x 1x WLEG
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Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
Page 42
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
18.3 PU and MU the 4-1/2” tubing hanger.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited 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
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Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. 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-253 SB Producer
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 45
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
20.0 Innovation Rig BOP Schematic
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Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
21.0 Wellhead Schematic
Page 47
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Drilling Procedure
22.0 Days Vs Depth
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Prudhoe Bay West
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Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
COMMENTS
SV5 Ice 0
BPRF Water 2,024 1,714.5 -1641 754 8.46
SV3 Gas Hydrates 2,692 2,059.5 -1986 906 8.46 Gas Hydrates expected SV3, SV2, & SV1 sands: ~2600' - 3600' MD
SV1 Gas Hydrates 3,552 2,503.5 -2430 1102 8.46
Ugnu 4A Heavy Oil 4,096 2,784.5 -2711 1225 8.46 Possible Heavy Oil in Ugnu 4A: ~ 4100' - 4300' MD
UG3 Water 4,720 3,105.8 -3032 1367 8.46
Ugnu LA Heavy Oil 5,837 3,683.5 -3610 1621 8.46 Possible Heavy Oil Lower Ugnu: ~5830' - 6500' MD
Ugnu MB Heavy Oil 6,213 3,877.5 -3804 1706 8.46
NB Schrader Bluff Water 6,665 4,110.5 -4037 1809 8.46
OA Top Schrader Bluff Oil 6,959 4,247.5 -4174 1869 8.46
FAULT 40' -50' DTS Throw 7,360 Fault Zone on the seismic is between 7280' & 7,500' MD
Obc Top Schrader Bluff Oil 7,651 4,460.5 -4387 1963 8.46
OBd Top (Heel) Schrader Bluff Oil 8,116 4,509.5 -4436 1984 8.46
OBd (Toe) Schrader Bluff Oil 15,887 4,388.5 -4315
EASTING Est.
Pressure GradientEXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING
L-253 wp04ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY
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Drilling Procedure
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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 wells with CF < 1.0
Preceding page clearly states that gas hydrates are present at L-Pad from SV4 to UG4. SFD 6/10/23
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Prudhoe Bay West
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Drilling Procedure
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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Prudhoe Bay West
L-253 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 No wells with CF < 1.0
Page 54
Prudhoe Bay West
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Drilling Procedure
25.0 Innovation Rig Layout
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Prudhoe Bay West
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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-253 SB Producer
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 57
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
28.0 Casing Design
Page 58
Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
29.0 8-1/2” Hole Section MASP
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Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
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Prudhoe Bay West
L-253 SB Producer
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
0D\
3ODQ /ZS
+LOFRUS1RUWK6ORSH//&
3UXGKRH%D\
/
3ODQ /
/
0750150022503000375045005250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 197.26° (1500 usft/in)L-253 wp01 CP1L-253 wp01 CP2L-253 wp01 CP3L-253 wp01 CP4L-253 wp01 CP59 5/8" x 12 1/4"6 5/8" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500
9000
9500
10000
10500
11000
115 00
12000
12500
13000
13500
1400014500150001550015887L-253 wp04Start Dir 3º/100' : 350' MD, 350'TVDStart Dir 4º/100' : 600' MD, 599.29'TVDEnd Dir : 1893.91' MD, 1647.00' TVDStart Dir 4º/100' : 6602.99' MD, 4078.58'TVDFault #1 (40-50' DTS Throw)End Dir : 7877.23' MD, 4490.63' TVDStart Dir 3º/100' : 8027.23' MD, 4503.7'TVDEnd Dir : 8225.65' MD, 4510.7' TVDStart Dir 2º/100' : 9849.96' MD, 4483.7'TVDEnd Dir : 9898.71' MD, 4482.48' TVDStart Dir 2º/100' : 11947.43' MD, 4413.7'TVDEnd Dir : 12012.04' MD, 4412.24' TVDStart Dir 2º/100' : 14023.02' MD, 4388.7'TVDEnd Dir : 14059.03' MD, 4388.49' TVDTotal Depth : 15887.34' MD, 4388.7' TVDBPRFSV3SV1Ugnu 4AUG3Ugnu LAUgnu MBNBOAObcObdHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: L-25347.20+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005978166.70582750.50 70° 21' 1.2005 N 149° 19' 41.3612 WSURVEY PROGRAMDate: 2022-12-29T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 1200.00 L-253 wp04 (L-253) GYD_Quest GWD1200.00 8150.00 L-253 wp04 (L-253) 3_MWD+IFR2+MS+Sag8150.00 15887.31 L-253 wp04 (L-253) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1714.40 1640.70 2024.44 BPRF2059.40 1985.70 2692.58 SV32503.40 2429.70 3552.44 SV12784.40 2710.70 4096.64 Ugnu 4A3106.28 3032.58 4720.00 UG33683.40 3609.70 5837.68 Ugnu LA3877.40 3803.70 6213.38 Ugnu MB4110.40 4036.70 6665.45 NB4247.40 4173.70 6959.86 OA4460.40 4386.70 7651.00 Obc4509.40 4435.70 8116.51 ObdREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-253, True NorthVertical (TVD) Reference:L-253 As-Built @ 73.70usftMeasured Depth Reference:L-253 As-Built @ 73.70usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:LWell:Plan: L-253Wellbore:L-253Design:L-253 wp04CASING DETAILSTVD TVDSS MD SizeName4510.46 4436.76 8150.00 9-5/8 9 5/8" x 12 1/4"4388.70 4315.00 15887.31 6-5/8 6 5/8" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 350' MD, 350'TVD3 600.00 7.50 210.00 599.29 -14.15 -8.17 3.00 210.00 15.94 Start Dir 4º/100' : 600' MD, 599.29'TVD4 1893.91 58.91 226.70 1647.00 -500.78 -486.61 4.00 18.26 622.60 End Dir : 1893.91' MD, 1647.00' TVD5 6602.99 58.91 226.70 4078.58 -3266.36 -3421.64 0.00 0.00 4134.46 Start Dir 4º/100' : 6602.99' MD, 4078.58'TVD6 7877.23 85.00 179.97 4490.63 -4347.48 -3846.82 4.00 -69.04 5293.06 End Dir : 7877.23' MD, 4490.63' TVD7 8027.23 85.00 179.97 4503.70 -4496.91 -3846.74 0.00 0.00 5435.73 L-253 wp01 CP1 Start Dir 3º/100' : 8027.23' MD, 4503.7'TVD8 8225.65 90.95 179.97 4510.70 -4695.12 -3846.65 3.00 0.02 5624.99 End Dir : 8225.65' MD, 4510.7' TVD9 9849.96 90.95 179.97 4483.70 -6319.20 -3845.87 0.00 0.00 7175.71 L-253 wp01 CP2 Start Dir 2º/100' : 9849.96' MD, 4483.7'TVD10 9898.71 91.92 180.06 4482.48 -6367.94 -3845.88 2.00 5.13 7222.26 End Dir : 9898.71' MD, 4482.48' TVD11 11947.43 91.92 180.06 4413.70 -8415.50 -3848.01 0.00 0.00 9178.25 L-253 wp01 CP3 Start Dir 2º/100' : 11947.43' MD, 4413.7'TVD12 12012.04 90.67 179.74 4412.24 -8480.09 -3847.90 2.00 -165.87 9239.91 End Dir : 12012.04' MD, 4412.24' TVD13 14023.02 90.67 179.74 4388.70 -10490.92 -3838.93 0.00 0.00 11157.53 L-253 wp01 CP4 Start Dir 2º/100' : 14023.02' MD, 4388.7'TVD14 14059.03 89.99 179.99 4388.49 -10526.93 -3838.85 2.00 160.08 11191.89 End Dir : 14059.03' MD, 4388.49' TVD15 15887.31 89.99179.99 4388.70 -12355.21 -3838.51 0.00 0.00 12937.75 L-253 wp01 CP5 Total Depth : 15887.34' MD, 4388.7' TVD
-13500
-12750
-12000
-11250
-10500
-9750
-9000
-8250
-7500
-6750
-6000
-5250
-4500
-3750
-3000
-2250
-1500
-750
0
750
South(-)/North(+) (1500 usft/in)-6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000
West(-)/East(+) (1500 usft/in)
L-253 wp01 CP5
L-253 wp01 CP4
L-253 wp01 CP3
L-253 wp01 CP2
L-253 wp01 CP1
9 5/8" x 12 1/4"
6 5/8" x 8 1/2"
1
0
0
0
1
5
0
0
1
7
5
0
2
0
0
0
2
2
5
0
2
5
0
0
2
7
5
0
3
0
0
0
3
2
5
0
3
5
0
0
3
7
5
0
4
0
0
0
4250
4500
4389
L-253 wp04
Start Dir 3º/100' : 350' MD, 350'TVD
Start Dir 4º/100' : 600' MD, 599.29'TVD
End Dir : 1893.91' MD, 1647.00' TVD
Start Dir 4º/100' : 6602.99' MD, 4078.58'TVD
Fault #1 (40-50' DTS Throw)
End Dir : 7877.23' MD, 4490.63' TVD
Start Dir 3º/100' : 8027.23' MD, 4503.7'TVD
End Dir : 8225.65' MD, 4510.7' TVD
Start Dir 2º/100' : 9849.96' MD, 4483.7'TVD
End Dir : 9898.71' MD, 4482.48' TVD
Start Dir 2º/100' : 11947.43' MD, 4413.7'TVD
End Dir : 12012.04' MD, 4412.24' TVD
Start Dir 2º/100' : 14023.02' MD, 4388.7'TVD
End Dir : 14059.03' MD, 4388.49' TVD
Total Depth : 15887.34' MD, 4388.7' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4510.46 4436.76 8150.00 9-5/8 9 5/8" x 12 1/4"
4388.70 4315.00 15887.31 6-5/8 6 5/8" x 8 1/2"
Project: Prudhoe Bay
Site: L
Well: Plan: L-253
Wellbore: L-253
Plan: L-253 wp04
WELL DETAILS: Plan: L-253
47.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
5978166.70 582750.50 70° 21' 1.2005 N 149° 19' 41.3612 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-253, True North
Vertical (TVD) Reference:L-253 As-Built @ 73.70usft
Measured Depth Reference:L-253 As-Built @ 73.70usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)L-05 wp06No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: L-253 NAD 1927 (NADCON CONUS)Alaska Zone 0447.20+N/-S +E/-W Northing EastingLatitudeLongitude0.00-0.05978166.70582750.5070° 21' 1.2005 N149° 19' 41.3612 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-253, True NorthVertical (TVD) Reference:L-253 As-Built @ 73.70usftMeasured Depth Reference:L-253 As-Built @ 73.70usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2022-12-29T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 1200.00 L-253 wp04 (L-253) GYD_Quest GWD1200.00 8150.00 L-253 wp04 (L-253) 3_MWD+IFR2+MS+Sag8150.00 15887.31 L-253 wp04 (L-253) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)L-231L-233L-100NWE1-01L-05 wp06L-294 wp03L-232 wp03L-292L-292 wp06NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 15887.31Project: Prudhoe BaySite: LWell: Plan: L-253Wellbore: L-253Plan: L-253 wp04Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4510.46 4436.76 8150.00 9-5/8 9 5/8" x 12 1/4"4388.70 4315.00 15887.31 6-5/8 6 5/8" x 8 1/2"
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0.001.002.003.004.00Separation Factor8075 8500 8925 9350 9775 10200 10625 11050 11475 11900 12325 12750 13175 13600 14025 14450 14875 15300 15725 16150Measured Depth (850 usft/in)L-121L-254 wp04No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: L-253 NAD 1927 (NADCON CONUS)Alaska Zone 0447.20+N/-S +E/-W Northing EastingLatitudeLongitude0.00-0.05978166.70582750.5070° 21' 1.2005 N149° 19' 41.3612 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-253, True NorthVertical (TVD) Reference:L-253 As-Built @ 73.70usftMeasured Depth Reference:L-253 As-Built @ 73.70usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2022-12-29T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 1200.00 L-253 wp04 (L-253) GYD_Quest GWD1200.00 8150.00 L-253 wp04 (L-253) 3_MWD+IFR2+MS+Sag8150.00 15887.31 L-253 wp04 (L-253) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)8075 8500 8925 9350 9775 10200 10625 11050 11475 11900 12325 12750 13175 13600 14025 14450 14875 15300 15725 16150Measured Depth (850 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 15887.31Project: Prudhoe BaySite: LWell: Plan: L-253Wellbore: L-253Plan: L-253 wp04Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4510.46 4436.76 8150.00 9-5/8 9 5/8" x 12 1/4"4388.70 4315.00 15887.31 6-5/8 6 5/8" x 8 1/2"
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.
223-048
PRUDHOE BAY SCHRADER BLUFF UNDEFINED OIL
PBU L-253
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT L-253Initial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230480PRUDHOE BAY, SCHR BLUF UND OIL - 640190NA1 Permit fee attachedYes Surface Location lies within ADL0028239; Top Prod Int & TD lie within ADL0028241.2 Lease number appropriateYes3 Unique well name and numberNo PRUDHOE BAY, SCHR BLUF UND OIL - 6401904 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 80'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches.26 Adequate wellbore separation proposedYes 16" Diverter below BOPE27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Monitoring will be required.33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No Measures required: H2S risk high ; see p. 53.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected Pressure Range is 0.437 to 0.44 psi/ft (8.4 to 8.5 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA with MPD appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/10/2023ApprMGRDate6/13/2023ApprSFDDate6/10/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 6/13/2023
