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7. Property Designation (Lease Number):
1. Operations
Performed:
2. Operator Name:
3. Address:
4. Well Class Before Work:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
Susp Well Insp
Install Whipstock
Mod Artificial Lift Perforate New Pool
Perforate
Plug Perforations
Coiled Tubing Ops
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well Other:
Change Approved Program
Operations shutdown
11. Present Well Condition Summary:
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
16. Well Status after work:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
OIL GAS
WINJ WAG GINJ
WDSPL
GSTOR Suspended SPLUG
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
Wellhead Greenstick Treatment
Conductor
Surface
Intermediate
Production
Slotted Liner
2270
4760
Conductor
Total Depth
Effective Depth
measured
true vertical
feet
feet
feet
feet
measured
true vertical
measured
measured
feet
feet
feet
feet
measured
true vertical
Plugs
Junk
Packer
Measured depth
True Vertical depth
feet
feet
Perforation depth
Tubing (size, grade, measured and true vertical depth)
Packers and SSSV
(type, measured and true vertical depth)
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.Representative Daily Average Production or Injection Data
Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure
Prior to well operation:
Subsequent to operation:
15. Well Class after work:
Exploratory Development Service StratigraphicDaily Report of Well Operations
Copies of Logs and Surveys Run
Electronic Fracture Stimulation Data
Sundry Number or N/A if C.O. Exempt:
13b. Pools active after work:
Sr Pet Eng:Sr Pet Geo:
Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Sr Res Eng:
Due Within 30 days of Operations
March 29, 2023
DSR-3/31/23
RBDMS JSB 033023
WCB 11-27-2023
Repair Well
Sundry Number
Wellhead Greenstick Treatment
PRUDHOE BAY /
SCHRADER BLUFF OIL POOL, ORION DEV AREA
By James Brooks at 1:40 pm, Feb 02, 2023
Completed
1/9/2023
JSB
RBDMS JSB 021323
GMGR28JULY2023DSR-2/22/23
2.2.2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.02 11:38:12 -09'00'
Monty M
Myers
TOC 12-1/4" x 9-5/8*" casing first stage from CBL 6550' MD.
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW W-26B Date:1/1/2023
Csg Size/Wt/Grade:9.625" 47# L-80 Supervisor:Barber/ Yearout
Csg Setting Depth:8727 TMD 4992 TVD
Mud Weight:9.2 ppg LOT / FIT Press =730 psi
LOT / FIT =12.01 ppg Hole Depth =8756 md
Fluid Pumped=2.7 Bbls Volume Back =2.2 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
->0 ->00
->4 105 ->8156
->8 201 ->16 391
->12 300 ->24 606
->16 390 ->32 825
->20 460 ->40 1048
->24 516 ->48 1275
->28 582 ->56 1518
->32 640 ->64 1749
->36 686 ->72 1995
->40 720 ->80 2236
->42 730 ->88 2484
-> ->96 2730
-> ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 730 ->0 2730
->1 543 ->1 2728
->2 488 ->2 2727
->3 452 ->3 2725
->4 435 ->4 2725
->5 417 ->5 2723
->6 401 ->10 2719
->7 387 ->15 2716
->8 373 ->20 2712
->9 363 ->25 2711
->10 351 ->30 2710
-> ->
-> ->
-> ->
4
8
12
16
20
24
28
32
36 4042
0
8
16
24
32
40
48
56
64
72
80
88
96
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 102030405060708090100110
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
730
543
488452435417401387373363351
273027282727272527252723 2719 2716 2712 2711 2710
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
12/10/2022 Cont. moving rig to W-Pad pulling on location @ 08:30 hrs. Set herculite over W-26 and lay rig mats. Remove #1 shaker bed from pits. Cellar uneven pulled rig
mats and herculite. Fill in edges of cellar with gravel for rig mats, relay herculite and rig mats. Spot and level Sub over W-26. Spot catwalk while removing #2 shaker
bed and all shaker motors. Crane in 2 new beds and 4 new shaker motors. Spot pipe shed, pit mod. Lower shaker beds into position while spotting in Gen mod. Rig
up inter-connects.
12/11/2022 Complete spotting in Gen mod and released trucks @ 01:00 hrs. Rig up steam, water and air and turn on throughout rig. Plug in power and swap to Gen power @
03:30 hrs. Spot in enviro-vac and break shake. Start dressing shakers. Spot and berm cuttings box. LRS is still rigged up and attempting to getCont. dressing
shakers and install motors. Scope up derrick and bridle down. Cont. working on rig acceptance check list. Sim-ops weld cutting box, pit support brace and pipe lift
column in shed. Rig accepted at 12:00 hrs. Work on wiring shakers, chink up and secure cellar due to no cellar box. Rig up gauges to I/A and TBG and observing
50 PSI on TBG- I/A= 0 PSI. Rig up bleed back tank and bleed off TBG. Total of 2 BBLS bled back. Sim-ops replace pilot valve on Koomey. Install BPV and N/D tree,
make up CTS and test sub. PT hanger threads and CTS to 5000 PSI for 10 min= good test. Function and measure each lock down screws as per well head rep.
Install spacer spool and N/U BOP's. Install choke and kill lines. Rig up hole fill, drip pan and drain lines. Install koomey lines and charge koomey system. With MP
#1 pump through bleeder for 5 min testing new oil seal on worm shaft. Clean and seal upper drip pan above stack, and cont. with shaker installation. M/U TIW and
dart valves to 5" test joint RIH seat both 5" and 4.5" test joints on rams and mark. R/U top drive for testing. Troubleshoot test pump finding Y-strainer plugged. Fill
lines and purge air from system. Perform shell test. Close lower rams and start testing BOP's. Daily disposal to PB G&I: 0 bbls, total 0 bbls. Daily disposal to MP
G&I: 0 bbls, total 0 bbls. Daily water from Lake 2: 700 bbls, total 700 bbls. Daily Metal 0# total 0#. Daily downhole losses: 0 bbls, total 0 bbls.
12/12/2022 Pressure test BOP's 250/3000 PSI for 5 min each, Test with 4.5" & 5" test Jts. F/P with Blinds-CMV's 1/2/3/14-LWR IBOP on low test- bleed air and re-test.
Accumulator PSI- Int= 2925 PSI, Final=1450 PSI, Manifold PSI- Int=1600 PSI, Final=1400 PSI. Annular PSI- Int=1050 PSI, Final= 1100 PSI. 200 PSI re-charge= 27
Sec, Full Recovery=93 Sec. Closing times- Bag=12 sec, Upper 4.5x7" VBR's= 8, LWR 5" solid body= 8 sec, HCR Choke/Kill= 1 sec each. Test all Gas alarms
lights/audible, PVT's and Flow paddle. Rig down testing equipment. Assist Vault well head rep pulling CTS and BPV. Reverse circulate 360 BBLS of 90 deg water
with Bara-clean taking returns to blow back tank through I/A. Initial rate 6 BPM, 355 PSI, Final rate 4 BPM, 115 PSI. Rig up to perform MIT-T/IA combo to 2500 PSI
for 30 charted min. Initial Pressures= TBG- 2752 PSI, I/A-2724 PSI, O/A-5 PSI, First 15 min= TBG-2729 PSI (-23), I/A-2700 PSI (-24), O/A-5 PSI, Second 15 min=
TBG-2710 PSI (-19), I/A-2681 PSI (-19), O/A-5 PSI,. Third 15 min= TBG-2693 PSI (-15), I/A-2664 PSI (-15), O/A-5 PSI. Total Pressure loss= TBG- 59 PSI, I/A- 60
PSI, O/A- 0 PSI. Pumped 3.75 BBLS bled back 3.4 BBLS. Good test- test witnessed by AOGCC Rep- Kam St.John. Rig up PWB pipe handling equipment and
power tongs. M/U landing JT with TC-II crossoveer. M/U to hanger, BOLDS and un-seat hanger. P/U 75K. Monitor well- static. Pull and L/D 4.5", 12.6#, L-80 TC-II
TBG F/4526' T/Surface. L/D a total of 109 full Jts, 1 X-nipple, 1 GLM, 2 pups 2.08'/2.42' and 1 cut jt-39.31'. Observed calculated displacement for trip. R/D PWB
tbg equipment and power tongs. Pick up jt and install wear ring ( ID-9", OD-13.45", Length 1.05' ). P/U and M/U baker stab (8.5" OD), XO and MS Cutter assembly.
Baker rep installed cutters. Pick up Jt M/U top drive pumping through tool @ 5 BPM verifying cutters functioned properly. Distance from btm of BHA to cutters is
2.87'. Single in the hole with 5" DP F/Surface T/2871' observing calculated displacement. Displace well over to 9.5 PPG spud mud @ 450 GPM, 1380 PSI no
rotation taking returns back to cuttings box. Pick up F/2871' T/2824' and turn on pump @ 2.5 BPM, 200 PSI. Slowly RIH F/2824' T/2879' attempting to locate collar
with no success. Shut off pump and POOH T/2828'. Pump @ 3.5 BPM, 400 PSI- slowly RIH F/2828' T/2895' attempting to locate with no success. Observed a 3-4K
bobble @ 2877'. P/U to cutter depth of 2871'. Established Rot TQ @ 100 RPM's= 4.2K TQ. Turn on pumps to 7 BPM, 996 PSI, 6-8K TQ cutting 9-5/8" CSG.
Observed pressure drop to 525 PSI and slowly increase and stabilize @ 624 PSI. Close the Bag and attempt to Circulate through the. the cut and clean/displace 9-
5/8" x 11-3/8" annulus @ 1 BPM pressuring up to 2000 PSI with no returns. Set cutters at cut depth of 2871' turn on pumps to 7 BPM, 800 PSI, 100 RPM's, 4-7K
TQ attempting to open up cut. Shut down, close bag and attempt to circulate through 9-5/8 x 11-3/8" annulus pressuring up to 1600 PSI with no returns stalling out
pumps. Shut down and blow down surface equipment, monitor well and prep to POOH. Daily disposal to PB G&I: 419 bbls, total 419 bbls. Daily disposal to MP G&I:
0 bbls, total 0 bbls. Daily water from Lake 2: 420 bbls, total 1,120 bbls. Daily Metal 0# total 0#. Daily downhole losses: 0 bbls, total 0 bbls.
12/13/2022 Grease spinners, blocks, roughneck and link tilt assembly, Check oil in TD and rotary table. POOH with stds of 5" DP F/2871' T/surface. P/U= 89K, SO=80K at
2871'. Observed calculated displacement. Inspect cutters observing good indication with wear CSG was cut. Break down Stab, XO and MS cutter assembly. Wait
on orders from town due to new information that BP performed a CMT squeeze job in 2004 with estimated TOC @ 1450'. Sim-ops remove dry hole tree from cellar
and ship with wells group. Get AKE-Line on the hook for CBL log to locate top of CMT on back side of 9 -5/8 CSG. P/U 9-58" grappling spear. Make up to a joint of
5" DP and 5 ft pup, 5' in hole and engage spear in 4.5' below hanger. Attempt to BOLDS. While BOLDS last couple of LDS became tight and hard to pull indicating
CSG was growing. Stopped and ran LDS back in. Disengaged spear and L/D. Call out Ak-Eline for CCL. Clean and clear rig floor, grease top drive, overhead
spinners, FH-80 and tongs. Clean and inspect air slips. Spot in Ak E-line and rig up. M/U CBL, GR and CCL. RIH and log up from 2100'. Estimated TOC at 1476'.
POOH and R/D E-line. M/U MSC casing cutter BHA. RIH to 1431'. Pressure up to 450 psi and attempt to locate collar at 1427' ELM, staging pressure up to 600 psi,
and slowly reciprocating pipe. Slight bobble at 1426'. Shut down pumps. Set cutters at 1410'. Establish rotary at 60rpms, 1650 ft-lbs. stage pumps up to. 7.5 bpm,
1000 psi. Observe torque increase to 5-6Kft-lbs as cutters open. After ~1 min Tq stalled out at 10Kft-lbs. Shut down pumps rotary. Pick up 5', slack back off to cut
depth 1410', and repeat with 60 rpms, 7.5 bpm until torque stalled. Pick up with 60K overpull to free cutters. Continue to observe up to 60K overpull as we pull the
bottom of the MSC above the cut, indicating casing is cut and off-center. L/D working single. Rig up hose to flowback tank and blow air through to ensure clear. R/U
head pin. Establish circulation at 1 bpm, ICP 650 psi. Pump 100 bbl 9.5 ppg heated soap pill and spot in OA, staging pumps up to 3 bpm, FCP 215 psi. Let soap
pill soak 1hr, Displace out soap pill W/9.5 PPG spud mud to flowback tank. 4 BPM, 350 PSI. Shut down and monitor well=static. Blow down and R/D surface lines.
POOH racking back stds of 5" DP F/1410' T/Surface. L/D MS cutter assembly. PU =61K, SO=60K @ 1400'. Observed calculated displacement during trip. P/U
working single and pull wearing. P/U test plug and RIH. RILDS pull and L/D working single. Close blinds, bleed off koomey and open upper ram doors and change
rams from 4.5 x7" VBR's to 9-5/8" solid bodies. Close and tighten ram doors. Daily disposal to PB G&I: 228 bbls, total 647 bbls. Daily disposal to MP G&I: 0 bbls,
total 0 bbls. Daily water from Lake 2: 140 bbls, total 1,260 bbls. Daily Metal 0# total 0#. Daily downhole losses: 0 bbls, total 0 bbls.
12/16/2022Spud Date:
Well Name:
Field:
County/State:
PBW W-26B
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
50-029-21964-02-00API #:
12/14/2022 R/U test equipment. P/T 9-5/8" upper rams 250/3000 PSI for 5 min each. Witness waived by AOGCC rep Kam St.John. B/D test equipment. BOLDS and pull test
plug. L/D test jt. Swap out split bushings for masters. P/U PWB CSG. power tongs, 150T side door elevators, slips and dog collar. M/U pack-off running tool and
RIH on top of hanger setting 25K down on hanger and BOLDS with no issues. L/D running tool. M/U baker 9-5/8" grappling spear and 5 ft in hole 30' ( 4.5' inside
hanger ). Pull hanger breaking free at 107K, 86K free travel. Release spear and Lay down. R/D 5" hydraulic elevators and install 150T side doors elevators. Swap
heads in power tong. Attempt to break hanger with power tongs. Collar broke from Jt below. Rigged up rig tongs- swapped heads and broke connection L/D hanger.
POOH L/D 9-5/8" CSG T/1200'. Cont. POOH laying down 9-5/8" 47#, L-80 NSCC CSG. F/1200' T/Surface. L/D 35 Jts and 1 cut jt ( 24.06' ). 11 Centralizers
recovered. R/D PWB CSG equipment. P/U and M/U bit sub, 13-3/8 72# scrapper and 12-1/4" junk mill. TQ 6-5/8 connections to 52K. RIH out of derrick F/11'
T/1251', encountered hard spot @ 1251'. PU 59K SO 59K. M/U TD and attempt to wash and ream through @ 10 BPM, 135 PSI, 60 RPM, 2.2K TQ. Worked pipe
up and down multiple times down to 1253' tagging hard with TQ spikes to 10K. CBU at 500 GPM, 185 PSI. Blow down surface equipment. Monitor well for 10 min-
static. POOH racking back DP F/1253' T/11' observing calculated displacement. PU 59K, SO 59K @ 1253'. Break down junk mill, CSG scrapper and bit sub.
Observed junk mill with slight wear on outside edge of BTM, Clear and clean rig floor. R/U AKE-line and RIH W/CCL T/1200', POOH and R/D E-line. P/U CICR and
inspect as per baker rep. Make up to first std of 5" DP and RIH. RIH on DP 60 FPM to 1170' observing calculated displacement. PU 58K, SO 58K. ROT 15 turns to
the right. P/U to 80K, S/O to set weight observing plug sliding down hole. Cycled up and down 3 more times pulling 90K, 100K, then to 110K setting CICR with
good indication felt at surface. S/O setting 23K down on CICR, Verify release and confirm top of CICR @ 1170' by tagging with 10K down. Top of CICR 1170', BTM
1172', Collar depth. POOH racking 5" DP in the derrick F/1170' pulling CICR quick latch running tool. Inspect as per backer rep. L/D. Close blinds and line up to PT
13-3/8" CSG. P/T CSG to 2500 PSI for 30 charted min- good test. Pumped 2 BBLS bled back 2 BBLS. Bled off koomey. R/D MPD lines and drip pan. Install MPD
lift cap. Install bridge cranes. Remove Choke/Kill lines. Pull hole fill lines and remove MPD head from stack. N/D BOPs and rack back. Pull TBG spool and stage in
cellar. Using loader sting Diverter-T and knife valve in cellar assisted with tuggers. Daily disposal to PB G&I: 290 bbls, total 937 bbls. Daily disposal to MP G&I: 0
bbls, total 0 bbls. Daily water from Lake 2: 140 bbls, total 1,400 bbls. Daily Metal 0# total 0#. Daily downhole losses: 0 bbls, total 0 bbls.
12/15/2022 N/U Diverter system. Install diverter T, install stack, and knife valve. Torque up all flanges. Cross chain and center stack. Install diverter vent line. Install flow riser,
inflate airboots. Hook up accumulator lines to annular and Knife valve. Test diverter system. Witnessed by AOGCC Bob Noble. Annular close in 12 seconds, Knife
valve open in 9 seconds. Accumutator drawdown test: Int Acc-3000 PSI, Final-1900 PSI, 200 Pre-charge- 16 sec, Full Recovery-48 sec. 2250 PSI N2 bottle average
(6 bottles) Test PVT/Flow alarms. Mobilize AK E-line and gyro data. Load Baker whipstock components in shed. Bring tools to rig floor. P/U and M/U 12-1/4" window
mill, watermelon mill and upper mill. Make up Gen2 whipstock W/45K shear bolt. Orient UBHO as per Sperry DD/GYRO reps. M/U 2 string magnets and RIH with 2
5" flex Jts and 20 Jts of 5" HWDP T/738'. Sim-ops spot in AKE-line. RIH with whipstock assembly F/738' T/1147'. PU 75K, SO 72K. Fill pipe pumping 2x drill pipe
volume. L/D top single of std #7, B/D topdrive. R/U AKE-line hanging sheave on derrick board fingers, P/U Gyro tools and RIH taking 3 shots at 280 deg. M/U top
drive-rotate and move pipe. RIH with gyro taking 3 shots @ 244 Deg. POOH L/D AKE-line. PU= 78K, SO= 76K. P/U top single of std #7. RIH and set down 6K to
set anchor. P/U with 13K overpull verifying anchor set. S/O to 26K Shearing from whipstock. Pick up 10' noticing a 7K drop in up/dwn. TOW- 1140' BOW-1165'.
Start pumps @ 420 gpm, 325 psi, 65 rpm, 2K tq, Rot 73K and begin milling window F/1140' T/1144' as per baker rep 3-5 ft/min, 1-2K wob. Daily disposal to PB
G&I: 168 bbls, total 1105 bbls. Daily disposal to MP G&I: 0 bbls, total 0 bbls. Daily water from Lake 2: 140 bbls, total 1,540 bbls. Daily Metal 0# total 0#. Daily
downhole losses: 0 bbls, total 0 bbls.
12/16/2022 Cont. milling 12.25" window F/1144' T/1149', 420 GPM, 350 PSI, 65 RPM, 10-12K TQ, 4-5K WOB, 41% R/F, ROT=73K, PU=72K, S/O= 72K, Total Metal in 6 hrs=
473#'s. Cont. milling 12.25" window F/1149' T/1155', 420 GPM, 350 PSI, 65 RPM, 3-8K TQ, 4-5K WOB, 40% R/F, ROT=73K, PU=72K, S/O= 72K, Total Metal in
6 hrs= 150#'s. Cont. milling 12.25" window F/1155' T/1165' plus 6' of new formation, 420 GPM, 430 PSI, 65 RPM, 7-9K TQ, 18-20K WOB, 53% R/F, ROT=73K,
PU=72K, S/O= 72K, Total Metal in 6 hrsl= 150#'s. Cont. milling 12.25" of new formations F/1171' T/1189', 420 GPM, 505 PSI, 65 RPM, 5-7K TQ, 20-25K WOB,
42% R/F, ROT=73K, PU=72K, S/O= 72K, Total Metal in 6 hrs= 33#'s. Daily disposal to PB G&I: 168 bbls, total 1105 bbls. Daily disposal to MP G&I: 0 bbls, total 0
bbls. Daily water from Lake 2: 0 bbls, total 1,540 bbls. Daily Metal 773# total 773#. Daily downhole losses: 0 bbls, total 0 bbls.
12/17/2022 Cont. milling window F/1189' T/1191', 420 GPM, 515 PSI, 65 RPM, 5-6KK TQ, 20-25K WOB, R/F 41%, ROT-73K, PU-72K, SO-72K. Observed mud running down
DP, Picked up off btm racking back stand to service rig and investigate leak. Pull second std rack back in derrick T/1090', B/D top drive and open grabber box.
Observed wash out on saver sub. Line up and monitor well on TT. Change out saver sub with new one. TQ fedderring to 185 FT/LBS, Close and button up grabber
box. Pick up 2 stds and RIH T/1191', Cont. milling window F/1191' T/1192', 420 GPM, 505 PSI, 65 RPM, 5-6K TQ, 20-25K WOB, R/F 42%, ROT-73K, PU-72K, SO-
72K. Metal recovered 6hrs- 45#. Cont. milling window F/1192' T/1193', 260-460 GPM, 170-500 PSI, 65 RPM, 8-9K TQ, R/F-46%, WOB 20-30K, PU-78K, SO-74K,
ROT-75K. Metal recovered 6 hrs= 55#. Work through window multiple times with pumps and rotations. And multiple times with pumps off no rotation with no issues.
Pump 30 BBL 200 Vis sweep while rotating and reciprocating F/1192' T/1140'. Sweep back on time with no increase in metal returns. Monitor well for 10 min- static,
B/D topdrive. POOH racking back stds of 5" DP F/1140' T/738' L/D 20 jts of 5" HWDP. Clean and send out 2 string magnets recovering 60#'s of metal. L/D XO,
UBHO, 2 Flex jts and mill assembly. Gauged mills- Upper mill= 1/8" under, Lower mill= 1/16" under and Window mill= 7/16" under. Install rotary table mouse hole,
P/U and make stands of 5" DP, built 94 stds using 3.125" drift. Monitoring well on TT-Static. Grease crown, Blocks, RLA, link tilt and ironroughneck, Check oil in TD
and rotary table. Organize BHA in pipe shed. Bring TM, DM and BHA XO's to rig floor. Rig up rig tong double line for 50K connections. Organize BHA in pipe shed
and P/U tools to rig floor. P/U Mud motor and make up 12-1/4" Bit 52K on connections. M/U DM,TM, and 2 flex collars to 56K on connections. M/U crossover and
single in the hole on 5" HWDP and 1 jar T/685'. RIH on 5" stds of DP F/685' T/1120'. M/U top drive and fill pipe. PU-76K, SO-76K, Observing calculated
displacement. Orient motor to 29 LOHS. Shut down pumps and attempted to RIH through window tagging 3x W/ 10-15K Down at 1141'. P/U and Orient TF to 5
ROHS observing motor stab at TOW setting 10K down on stab. P/U 5' run back in with no other issues occurred F/1141' T/1171'. Once bit exited the window 10K
drag was observed. PU-80K, SO-66K. AT 1171' motor stab hung up at the bottom of window with 10K down. P/U 3' turned pumps on and washed at 300 GPM, 570
PSI slacked off and motor stalled @ 1171'. Increased flow rate to 400 GPM, 920 PSI and wash down F/1171' T/1192' with no other issues. Daily disposal to PB G&I:
376 bbls, total 1481 bbls. Daily disposal to MP G&I: 0 bbls, total 0 bbls. Daily water from Lake 2: 280 bbls, total 1,820 bbls. Daily Metal 160# total 933#. Daily
downhole losses: 0 bbls, total 0 bbls.
12/18/2022 Slide drill TF at HS F/1192' T/1307', 350 GPM, 955 PSI, 10-15K WOB, 36% R/F, P/U-77K SO-77K. MWD survey showed 2 separation from original well @ 1307'
(INC-12.23). POOH F/1307' T/675'. With TF at 5 ROHS pulled through window with no issues. PU-78K, SO-73K. Observed calculated displacement for trip. Rack
back 9 stds of 5" HWDP W/Jars. Rack back 1 stand of NM-Flex collars. L/D TM and DM pull bit to surface and inspect. RIH with bit and motor. M/U EWR, DM and
TM. Scribe DM to motor (Off-set=284). Perform down load as per Sperry MWD. Complete Down load, P/U std of Flex collars,XO and RIH with 9 stds of 5" HWDP
T/705'. RIH on 5" DP F/705' T/1087', Fill pipe and orient TF HS. Shutdown and pass through window with 5K drag on slide. Wash down to 1307' no fill. PU-78K,
SO-75K. Drill Surface hole F/1307' T/1656' (Total=349', AROP=100 FPH) at 420 GPM, 1000 PSI, 10.34 ECD, 58% R/F, MW-9.6 PPG, Max gas=21, 40 RPM, TQ
on-4K, TQ OFF-2K, WOB 4-7K, PU=83K, SO=81K, ROT= 82K. Jetting flow line between connections as needed. Cont. Drilling ahead F/1656' T/2166' (Total=510',
AROP=85 FPH) at 420-450 GPM, 1100-1250 PSI, 10.4 ECD, 69% R/F, MW-9.5 PPG, Max gas=25, 60 RPM, TQ on 5-6K, TQ OFF 4-5K, WOB 4-8K, PU=86K,
SO=76K, ROT= 85K. Jetting flow line between connections as needed. Base of Permafrost logged at 2063' MD- 1942' TVD. Cont. Drilling ahead F/2166' T/2696'
(Total=530', AROP=118 FPH) at 500 GPM, 1720 PSI, 10.48 ECD, 60% R/F, MW-9.5 PPG, Max gas=95, 80 RPM, TQ on 5-6K, TQ OFF 4-5K, W OB 4-10K,
PU=97K, SO=76K, ROT= 84K. Distance to plan 20.88', High 6.57', Left 19.82'. Sperry's Compus WP-05 Differs from the PDF WP-05, called well planner to
investigate. P/U racking back 1 std T/2674', Circulate and reciprocate F/2674' T/2610', 550 GPM, 1730 PSI, 80 RPM, 5K TQ, Max gas 58 units. Daily disposal to
PB G&I: 518 bbls, total 1,999 bbls. Daily disposal to MP G&I: 394 bbls, total 394 bbls. Daily water from Lake 2: 420 bbls, total 2,240 bbls. Daily Metal 10# total
943#. Daily downhole losses: 0 bbls, total 0 bbls.
12/19/2022 Cont. drilling 12-1/4" hole from 2697' to 3434' (Total 737', AROP 123 fph) at 500 gpm, 1725 psi, 80 rpms, 7Kft-lbs, WOB 8-10K. ECD 10.6 ppg, 9.5 ppg MW, Max
gas 304u. P/U 101K, S/O 80K, ROT 87K. Maintenance slide as needed for tangent. Backream full stands. Cont. drilling 12-1/4" hole from 3434' to 4122' (Total
688', AROP 115 fph) at 525 gpm, 1900 psi, 80 rpms, 8-9Kft-lbs, WOB 6-8K. ECD 10.69 ppg, 9.6 ppg MW, Max gas 578u. P/U 112K, S/O 85K, ROT 97K.
Maintenance slide as needed for tangent. Backream full stands. Cont. drilling 12-1/4" hole from 4122' to 4772' (Total 650', AROP 108 fph) at 525 gpm, 2020 psi, 80
rpms, 9.5Kft-lbs, WOB 9-11K. ECD 10.65 ppg, 9.65 ppg MW, Max gas 3463u. P/U 122K, S/O 84K, ROT 101K. Maintenance slide as needed for tangent.
Backream full stands. Cont. drilling 12-1/4" hole from 4772' to 5440' (Total 668', AROP 111 fph) at 500 gpm, 1770 psi, 80 rpms, 11-13Kft-lbs, WOB 4-9K. ECD
10.3 ppg, 9.65 ppg MW, Max gas 335u. P/U 145K, S/O 85K, ROT 109K. Maintenance slide as needed for tangent. Backream full stands. Observe oil on shakers at
4962'. Distance to WP 6.64', 2.22' high, 6.26' left. Daily disposal to PB G&I: 1083 bbls, total 3,082 bbls. Daily disposal to MP G&I: 0 bbls, total 394 bbls. Daily water
from Lake 2: 1260 bbls, total 3,500 bbls. Daily Metal 0# total 943#. Daily downhole losses: 0 bbls, total 0 bbls.
12/20/2022 Slide/ Rot 12.25" Hole F/ 5,440' to 6,041' MD (4,034' TVD) Total 601' (AROP 100.2') 500 GPM, 1,930 psi on/ 1,805 off, 80 RPM, TRQ on 14-16k, TRQ off 12-13k,
F/O 47%, WOB 10-13k. ECD 10.2. Max Gas 144u. P/U 159K, SLK 88K, ROT 115K. Ream 60'. Slide as needed to maintain tangent. Jet as needed. Slide/ Rot
12.25" Hole F/ 6,041' to 6,620' MD (4,327' TVD) Total 579' (AROP 96.5') 525 GPM, 2,050 psi on/ 1,920 off, 80 RPM, TRQ on 16-18k, TRQ off 15-17k, F/O 55%,
WOB 5-8k. ECD 10.22. Max Gas 92u. P/U 175K, SLK 88K, ROT 121K. Ream 60'. Slide as needed to maintain tangent. Jet as needed. Slide/ Rot 12.25" Hole F/
6,620' to 7,155' MD (4,585' TVD) Total 535' (AROP 89.2') 525 GPM, 2,150 psi on/ 1,850 off, 80 RPM, TRQ on 19-21k, TRQ off 18-20k, F/O 54%, WOB 8-10k.
ECD 10.37. Max Gas 457u. P/U 193K, SLK 87K, ROT 126K. Ream 60'. Start 4/100 build at 7,121' MD. Slide/ Rot 12.25" Hole F/ 7,155' to 7,565' MD (4,741' TVD)
Total 410' (AROP 68.3') 550 GPM, 2,505 psi on/ 2,395 off, 80 RPM, TRQ on 20-21k, TRQ off 20k, F/O 51%, WOB 8-12k. ECD 10.3. Max Gas 207u. P/U 198K,
SLK 87K, ROT 127K. Ream 60'. Cont 4/100 build. Distance to WP 11.66', 11.6' high, 1.20' left. ROT Hrs: 9.68
SLD Hrs: 4.74. Daily disposal to PB G&I: 1373 bbls, total 4455 bbls. Daily disposal to MP G&I: 57 bbls, total 451 bbls. Daily water from Lake 2: 860 bbls, total 4360
bbls. Daily Metal 0# total 943#. Daily downhole losses: 0 bbls, total 0 bbls.
12/21/2022 Slide/ Rot 12.25" Hole F/ 7,565' to 8,000' MD (4,865' TVD) Total 435' (AROP 72.5') 550 GPM, 2,675 psi on/ 2,495 off, 80 RPM, TRQ on 22-24k, TRQ off 21k, F/O
69%, WOB 8-12k. ECD 10.5. Max Gas 271u. P/U 190K, SLK 84K, ROT 125K. Ream 60'. Jet as needed. Slide/ Rot 12.25" Hole F/ 8,000' to 8,415' MD (4,967'
TVD) Total 415' (AROP 69.2') 550 GPM, 2,520 psi on/ 2,280 off, 80 RPM, TRQ on 19-22k, TRQ off 18-20k, F/O 45%, WOB 9-13k. ECD 10.32. Max Gas 580u. P/U
198K, SLK 86K, ROT 127K. Ream 60'. Directional work as per Geo. Slide/ Rot 12.25" Hole F/ 8,415' to 8,711' MD (4,994' TVD) Total 296' (AROP 49.3') 500 GPM,
2,050 psi on/ 1,860 off, 80 RPM, TRQ on 20-22k, TRQ off 19-22k, F/O 42%, WOB 6-11k. ECD 10.11. Max Gas 378u. P/U 194K, SLK 86K, ROT 127K. Ream
60'.Directional work as per Geo. Slide/ Rot 12.25" Hole F/ 8,711' to TD 8,736' MD (4,991' TVD) Total 25' 500 GPM, 2,050 psi on/ 1,860 off, 80 RPM, TRQ on 20-
22k, TRQ off 19-22k, F/O 42%, WOB 6-11k. ECD 10.11. Max Gas 120u. P/U 194K, SLK 86K, ROT 127K. TD called by Geo. Final survey 8,640.56' MD 4,994.60'
TVD 89.91 inc 322.83 Az. Geologist adjusted the plan to drill down to the base of the pay zone to have a look at the reservoir quality, prior to building back to 93.50
inc at TD 8736 MD. Monitor well 10 min, static. Perform clean up cycle. BROOH F/ 8,736' to 8,585' MD. Circ 0.5 BU per stand for 3 stands. 550 GPM, 2,200 psi, 80
RPM, TRQ 17-19k, F/O 44%, ECD 10.1. Max Gas 361u. Rot/ Rec F/ 8,585' to 8,522' MD. Pump 40 bbl high vis nut plug sweep back on time W/ 10% increase.
Circulated a total of 3X BU. 550 GPM, 2,200 psi, 80 RPM, TRQ 17k, F/O 43%, ECD 10.1. Max Gas 49u. Wash down F/ 8,522' to 8,736' MD. 425 gpm 1430 psi 60
rpm TRQ 9-12k F/O 44%.Max Gas 37u. No fill. BROOH F/ 8,736' to 8,458' MD. 550 GPM, 2,190 psi, 80 RPM, TRQ 16-17k, F/O 44%, ECD 10.02. Max Gas 25u.
P/U 182k SLK 89k ROT 119k. Distance to WP05a: 41.90', 41.90' Low, 4.99' Left in OBd sand. ROT Hrs: 5.49. SLD Hrs: 7.49. Daily disposal to PB G&I: 974 bbls,
total 5429 bbls. Daily disposal to MP G&I: 57 bbls, total 508 bbls. Daily water from Lake 2: 720 bbls, total 5080 bbls. Daily Metal 0# total 943#. Daily downhole
losses: 0 bbls, total 0 bbls.
12/22/2022 BROOH F/ 8,458' to 6,045' MD 550 gpm 2,050 psi 80 rpm Trq 15-16k ECD 10.2, F/O 45%. Max Gas 51u. P/U 168k SLK 88k ROT 118k. At 7,200' MD CBU over 3
stands at end of tangent. Pull speed 20-30 ft/min as hole dictates. Lost 32 bbls. Cont BROOH F/ 6,045' to 2,773' MD 550 gpm 1,540 psi 80 rpm Trq 7-9k ECD
10.2, F/O 50%. Max Gas 120u. P/U 107k SLK 79k ROT 85k. Pull speed 20-40 ft/min as hole dictates. Lost xx bbls. Cont BROOH F/ 2,773' to 1,520' MD 550 gpm
1,230 psi 80 rpm Trq 6-8k. ECD 10.13 F/O 47% Max Gas 120u. Reduced rpm F/ 80 to 60 at 1,590 and 40 rpm at 1,520' MD. Pull speed 10-30 ft/min as hole
dictates. At 1,715' to 1,593' MD encountered hole unloading heavy sand at shakers. CBU 2X over 2 stands till shakers cleaned up. At 1,520' orientated 14 LHS and
attempted to pull through window with 10k over pull. Worked string up to 10k over without success. Adjusted rotation F/ 5-10 rpm (stall set 7k) 300-350 gpm 480-
650 psi pulling F/ 1,520' to 1,473' MD W/ 2-7k over pull. to get jar stand past window (TOW 1,140' BOW 1,165' MD). Pull speed 1-2 ft/min. P/U 84k SLK 81k. Minor
packing off. At 1,473' MD after pulling jars past window increased rotary to 30 rpm Trq 4-7k 400 gpm 830 psi pull speed 2-3 ft/min. Appears BHA balled up, not a
window issue.. Cont BROOH F/ 1,473' to 1,332' MD 400 gpm 830 psi Trq 5-7k heavy clay seen at shakers. At 1,332' MD orientate motor to 12 LHS. Attempted to
pull on elevators working up to 25k only gaining 2-3 able to slack down without issue. Cont BROOH F/ 1,332' to 1,267' MD. 350 gpm 700 psi 10 rpm Trq. 2.5-3.5k
pulling NM FC through window W/ 2-4k drag at 1-4 ft/min. At 1,267 orientated motor to 9 LHS and pumped out 350 gpm 650 psi pulling speed 2-4 ft/min, ILS pulled
clean. F/ 1,172' to 1,163' MD worked motor though window W/ 4-10k drag at 1-4 ft/min. Lost a total BROOH 50.5 bbls. CBU F/ 1,130 to 1,082 MD 350 gpm 637 psi
20 rpm Trq 1.5-2k. No real increase at shakers. Blow down top drive. POOH 3 stands F/ 1,082 to 998 MD hole appears to be swabbing. Pump out of hole F/ 998 to
695 MD 350 gpm 615 psi F/O 45% P/U 71k SLK 68k. Daily disposal to PB G&I: 589 bbls, total 6018 bbls. Daily disposal to MP G&I: 114 bbls, total 622 bbls. Daily
water from Lake 2:3020 bbls, total 8100 bbls. Daily Metal 0# total 943#. Daily downhole losses: 32 bbls, total 32 bbls.
12/23/2022 L/D BHA from 695' to Surface, pumping 8 stds HWDP/Jars out of hole. L/D XO and 2x FFlex Collars. Down Load MWD. L/D TM,EWR, DM and UBHO Sub. Milk
and Break Bit. Bit Grade 1-1-CT-G-F-I-NO-TD, PDC Grade 1-2-WT-A-F-I-NO-TD. Clean and pressure wash floor from Balled up BHA clays. Stage cent on rig floor.
R/D 5" Hyd Elevators, clean and put away collar slips/Dog Collar, Rig Tongs and swing Iron roughneck aside. Finish pressure washing, start riggin up to run casing.
PJSM with RIG/Casing Crew. Install 9.625" 250T side door elevators. Drain stack, P/U landing jt with Fluted Csg Hgr, Drigt run Csg Hgr and verify landed out. P/U
320T Volant/Cmt Swivel and M/U to Top Drive, chain off swivel. P/U and R/U Power Tongs. Verify pipe and centralizer count. PJSM w/Rig/Csg/Cmt Crews. M/U
Shoe Track to FC, pump through, drop Bfl Bypass, check Floats, good. M/U Bfl Adapter baker locing connections on Shoe Track.Continue to run in hole with
9.625", 47#, L-80, VamTop Casing from 127' to 1120' filling every 5 jts, top off every 10 jts. CBU at 1120' prior to. entering the TOW @ 1140'. Cont. Run casing
from 1120' to 1398'. Pass through window with 3-4k drag across window. Cont RIH 9.625" 47# L-80 Vam Csg F/ 1,398' to 4,027' MD installing SB Centralizers as
per tally. Circ string volume at 2,195' (BPF) & 3,612' MD staging up to 6 bpm 214 psi Max Gas 105u no dynamic loss. Run Speed 40-60 ft/min. Trq Vam 15.9k. Fill
every 5 jnts and top off every 10. Calc Disp 61.2 bbl Act -26.4, lost 87.6 bbls. Cont RIH 9.625" 47# L-80 Vam Csg F/ 4,027' to 6,863' MD installing SB Centralizers
as per tally. Max Gas 174u. P/U 262k SLK 101k. Run Speed 40 ft/min. Trq Vam 15.9k. Fill every 5 jnts and top off every 10. Calc Disp 47.8 bbl Act 24.4, lost 23.4
bbls. Daily disposal to PB G&I: 114 bbls, total 6132 bbls. Daily disposal to MP G&I: 57 bbls, total 679 bbls. Daily water from Lake 2: 140 bbls, total 8240 bbls. Daily
Metal 0# total 943#. Daily downhole losses: 136 bbls, total 168 bbls.
12/24/2022 Continue to RIH w 9.625" , 47#, L-80 Vam-Top casing from 6,863' to 7,220' MD, Fill pipe every 5 jts, topping off every 10 jts. Install centralizers as per Tally. Tq =
15,900 ft/lbs. P/U 280K, SO 110K, Calc + 115.6 bbls, Act = 19.8 bbls, Lost 135 bbls. Max Gas 144u,. Attempt to Break Circulation and CBU from 7220'. Attempt
Several methods to reestablish circulation, working pipe 50', 1-14 RPM, 15,000 Tq on down stroke with 0 to .5 bpm, 450-500 psi. Appear to be packed off and
injecting fluid away at .5 to 4 bpm 400 to 500 psi. on upstroke & Down Stroke. Decision made to pump out of hole to last point of circulation. Pump out to 6990'.
Attempt to regain circulation using multiple methods and multiple Parameters as before with no success. Constant 450 - 500 psi injection when working pipe with
pumps on. Decision made to run to bottom. RIH with casing on elevators from 6,990' to 8,357, filling pipe and attempting to regain circulation every 5 jts with
multiple attempts each 5 jts. Cont RIH W/ 9.625" Csg F/ 8,357' to 8,728' MD W/ extra jnt 217 to ensure we can get hanger down and establish Circ. Working string
up hole, pump pressure holding at 450 psi without injection, pulling up to 400k, Trq stall set at 12k able to get 1-2 rpm on the down stroke. Started injecting at 1
bpm 685 psi. Able to get JNT 217 out and L/D. Lost 81 bbls running casing. P/U 355k SLK 95k. Cont to try & establish Circ Rot/ Rec F/ 8,646' to 8,686' MD. Trq
stall set at 12k 1-3 rpm on down stroke and adjusting pump rate 1-2 bpm and 400 psi on down stroke and 600 psi on the up stroke. We are injecting at 550 to 600
psi at 2 bpm. Adjusting parameters and pull speeds to gain Circ. At surface we are seeing heavy clabber and sand working its way up while on the up stroke. P/U
weight is about 15-20 k less when we hold 600 psi on formation. Slacking down has not been an issue. Made several attempts to pull past 8,646 MD pulling up to
400k with out success. Injected 79 bbls. P/U 350-375k SLK 90-95k breaking over at 72k down. Called out 2 vac trucks with 290 bbls each of Spud Mud and round
tripping one for another 290 bbls for cement without returns. Cont to establish Circ Rot/ Rec F/ 8,646 to 8,686 MD. Trq stall set at 9.8k 1-3 rpm on down stroke and
adjusting pump rates 1-4 bpm shutting down pumps on the down stroke. Attempted with and without rotation. Our run speed up and down 10-40 ft/min. P/U weight
is about 15-20 k less when pumping. with pump pressure around 480 psi. Appears we are injecting at 450 psi. Slacking down has not been an issue. Made a
couple attempts to pull past 8,646 MD pulling up to 400k without success. Injected 234 bbls. P/U 350-375k SLK 90-95k breaking over at 72k down. Total injected
559 bbls. Injection rate 1 bpm 450 psi, 2 bpm 480 psi, 3 bpm 500 psi. We are seeing more frequent heavy clabber and sand working its way up while on the up
stroke. Still unable to establish Circ. Decision was made to move forward with 1st stage cement job. PJSM Flush out stack with hole fill pump. Break out of Volant.
P/U M/U 9.625" Hanger as rep Vault onsite. Trq Vam Top 15,9k. Pull bushing and land hanger as per Vault Rep onsite. Install bushings. Blow Down top drive and
volant. PJSM R/U Cement lines and LoTrq's to Volant. R/D power tongs, elevators & bails. Daily disposal to PB G&I: 57 bbls, total 6189 bbls. Daily disposal to MP
G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 420 bbls, total 8660 bbls. Daily Metal 0# total 943#. Daily downhole losses: 568 bbls, total 736 bbls.
12/25/2022 Break out of Volant and inspect cup element, M/U to Stump. Pump through bleeder and clear flow line. Continue to pumping through cement line @ 1 bpm 350 ICP,
FCP 226, No returns. Establish injection rate prior to pumping 1 stage cement..5 BPM, 250 PSI to 8 BPM, 1030 psi. HES pump 5 bbls H2O. PT 4000 psi, good.
Pump 60 bbls 10 ppg 4# red dye & Poly E Flak 4 bpm 800 PSI. Pump 281 (675 sx) 12 ppg EconoCem Type I II Lead cmt, 2.347 yld, 4.5 bpm, 380 psi. 82 bbls
(400 sx) 15.8 ppg HalCem Type I II Tail cmt, 1.156 yld, 3.5 bpm, 790 PSI. Release F/ Volant, drop shutoff plug.
Displace w/ 20 bbls H2O f/CMT Unit 5 bpm, psi. Turn over to rig. Rig disp w/ 436 bbls 9.4 ppg spud mud, 8 bpm, ICP 780 psi, FCP 778 psi @ 6.5 BPM. HES
pump 72 bbls 9.4 ppg spacer, 4.5 bpm, 883 ICP, FCP 600 @ 2 BPM. Rig displace w/ 103 bbls 4.5 bpm, 810 ICP, Maintain 3 BPM to Bump with FCP 800. Bumped
@ 631 bbls, 1.10 bbls over Calc 629.9 bbls. Hold 1350 psi (3 min). Bleed off psi, Check floats (good). Psi up, open stage tool 6 bpm, shift @ 2550 psi. CIP @
14:40 hrs. Landed on Casing Hgr No Returns during job. CBU @ 3 BPM 400 psi. Dumped 140 bbls contaminated mud. ( No Green Cement) Total Fluids pumped
without returns 1053 bbls. Continue to circulate and condition mud via stage tool (2235' MD) 5 bpm, 250 psi,. Cont Circ through ES 5 bpm 220 psi. Increase rate to
8 bpm 530 psi for 5 min every hour. No dynamic losses. Prep for second stage cement job. WOC. PJSM Pump 2nd stage cement job as follows: 54 bbls 10 ppg
Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls) 3.5 bpm 220 psi. Lead ArcticCem 200 bbls 10.7 ppg Lead cmt, 2.883 yld, (435 sx) 4.5 bpm, ICP 330/
FCP 505 psi. 214 bbls into cement saw poly flak at shaker (Calc 293 bbl). At 264 bbls into cement saw 10.45 ppg spacer/cement at shakers. Pump Tail Premium G
cement 58 bbls 15.8 ppg Tail cmt, 1.156 yld, (270 sx) 3.0 bpm, ICP 503/ FCP 381 psi. Release from CRT & drop closing plug. Displace w/ 20 bbls H2O (HES) 4.5
bpm 282 psi then turn over to rig. Rig disp actual 142.1 bbls Calc 144 bbls W/ 9.5 ppg spud mud, 7 bpm ICP 296 psi FCP 356 psi, reduce rate 6 bpm 20 bbls away
ICP 362 FCP 750 psi. Reduced rate last 15 bbls to 3 bpm, ICP 610 psi FCP 630 PSI. ES Cementer shifted shut at 1,747 PSI. Held 2,131 psi for 5 minutes, check
plug - good. . CIP 03:08 hrs. No losses. Dumped 383 bbls total: 183 bbls black water & spacer, 200 bbls of green cement. Appears hole is 60% under gauge. PJSM
L/D Volant CRT. R/D blow down cement lines and valves. Unhook knife valve and flush stack W/ black water cycling annular. Off loading fluid from pits. L/D landing
jnt. Daily disposal to PB G&I: 114 bbls, total 6303 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 840 bbls, total 9500 bbls. Daily
Metal 0# total 943#. Daily downhole losses: 701 bbls, total 1437 bbls.
12/26/2022 PJSM Flush through cement line and remove. Hook up bridge cranes to stack and remove chain binders. Johnny whack stack W/ black water. Vac out stack. Pull
mouse hole. R/D 16" diverter sections. Pull riser. Lift stack and set on pedestal. Break out Diverter Tee.. SIMOPS Grease cement and CM valves. Offload mud from
pits. Remove inspection cover for flow line and clean. Clean pits. Pressure wash cellar mezz landing for welder. PJSM Prep wellhead as per Vault rep onsite. Set
tubing spool on wellhead. Vault rep clean casing hanger. Install bolts and trq wellhead. Phase 2 weather conditions started at 12:45 working at a reduce speed to
minimize risk. PJSM Remove bell nipple F/ annular. P/U RCD head W/ tugger and center to rotary table. Move stack over well and install RCD head as per Beyond
rep onsite. Move stack back to pedestal and set down. Trq RCD head. PJSM Set 2' DSA on tubing spool. P/U and set stack on DSA. Install choke and kill lines. Trq
flanges. SIMOPS Assist NES welder patching hole in flowline and drip pan. Cont cleaning pits. Send RCD riser to shop for repair. P/U 5" DP and pack off running
tool. PJSM PJSM made several attempts to set pack off. Stacked 35k and use link tilt W/ TD to try and center pakoff. Vault rep onsite. Use stainless rod to clear
flutes in hanger to ensure clear path to OA and confirmed not hydraulic locking. It does not appear packoff is going over hanger evenly. Checked upset on the upper
part of packoff where O rings seat and it was 13 3/8" and looked to be where we are hanging up on the tubing spool. Decision was made to N/D and inspect casing
hanger. Still in Phase 2 weather conditions. Cont to work at a reduced rate to minimize risk. PJSM Cont W/ Phase 2 weather condition working at a reduced rate.
R/U bridge cranes to stack. R/D chain binders. R/D drip pan, koomey, choke and kill lines. Unbolt BOP F/ tubing spool and rack back to pedestal. PJSM N/D tubing
spool and set aside in cellar. Hanger was centered in wellhead. Wellhead was a quarter bubble out of level towards skate. P/U M/U 5 D.P and pack running tool. Set
pack off on hanger stump and put about 12k down to get set. RILDS. Looked to be due to wellhead not level and such a. tight tolerance with tubing spool was
causing the problem. Install and m/u tubing spool without issue. Attempting to test seals. Retorque flange and retest. Daily disposal to PB G&I: 781 bbls, total 7084
bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 560 bbls, total 10060 bbls. Daily Metal 0# total 943#. Daily downhole losses: 0 bbls,
total 1437 bbls.
12/27/2022 PJSM Cont testing pack off seals to 500/ 5000 low/high for 5 min ea,, good. Vault rep R/D test Equip. P/U 5" D.P. and set test plug. PJSM P/U and set BOP on
tubing spool. Secure W/ chain binders. Install choke, kill lines, drip pan and MPD test cap. R/U 4" MPD hard lines. C/O UPR's to 4.5" X 7" VBR. s. Verify LPR's 5"
solid body. Hook up drip pan lines. Install split bushings. Install companion flange on wellhead and R/U 1502. SIMOPS: Made up test Equip for BOPE testing. TIW/
Dart/ Side entry. PJSM Flood lines and pump through super choke, cycle valves and purge air. Test MPD lines to 1,200 psi, good. Remove MPD test plug. Install
trip nipple. Went to normal weather conditions at 11:57 am. PJSM Install grey clamp and inflate 20" boot. R/U Test lines. P/U 4.5" test jnt and M/U to test plug.
Flood lines and purge air. Shell test to 3,000 psi, good. PJSM Perform BOPE test W/ 4.5" & 5" to 250 PSI low and 3,000 PSI high for 5 Min. Tested Choke Manifold
1-15, 5" Dart, 2 ea 5" TIW, Upper and lower IBOP, Mez Kill, HCR Choke, HCR Kill, manual Choke and Kill, Super Choke and manual (F/P) to 2,000 PSI, Use 5 for
LPRs (5 solid body), Use 4.5 & 5. for Upper VBR (4.5 X 7) & 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 2,950 PSI, Manifold 1,650 PSI, Annular 1,200 PSI, after System 1,500 PSI, Man 1,450 PSI, Annular 1,060 PSI. 200 PSI
increase 33 Sec,. full charge 101 sec. Nitrogen 6 bottle average 2,358 PSI. Closing times Ann 13 sec, UPR & Blinds 9/8 sec, LPR 6 sec, HCR Choke & Kill 1/1 sec.
F/P Manual Super Choke greased/function. Used H2O for test. Witnessed waived by AOGCC Rep Sully Sullivan. PJSM R/D test Equip. Pull test plug. Blow down
Choke Manifold, kill and choke lines. M/U and set wear ring 13.44" OD 9" ID Lng 12.25". RILDS (4) Clean and clear rig floor. PJSM BHA #4 P/U M/U RR 8.5"
XR+CPS Tricone (0.9419 TFA) 6.75" 1.5 StrataForce Motor and 9 stands 5" HWDP/Jar to 581' MD. Taking returns down drag chain. Dull Grade in 1-1-WT-A-E-I-
NO. PJSM Cut & slip 16 wraps (100') drilling line. TM 1,376, ACCUMTM 31,381. 1,502' left on spool. Check Drawworks brakes and calibrate blocks. Deadman Trq
80 ft/lb. PJSM Service rig. Grease crown, TD & PH8. Perform monthly EAM wobble on crown sheave and blocks. PJSM Cont single in hole 8.5" Clean Out BHA W/
5" 19.5# S-135 D/P F/ 581' to 1,447' MD. Drift 3.125" OD. P/U 72k SLK 64k. Total 27 jnts. PJSM Cont single in hole 8.5" Clean Out BHA W/ 5" 19.5# S-135 D/P F/
1,447' to 2,083' MD. Drift 3.125" OD. P/U 72k SLK 64k. Total 48 jnts. Wash down F/ 2,115' to 2,232' MD 350 gpm 480 psi 30 rpm Trq 3.5k P/U 84k SLK 77k ROT
80k. Drill cement and ES. Tagged cement at 2,232' MD Drilled F/ 2,232' to 2,237' MD ES on depth 2,234' MD. Rotate across ES W/ and W/O rotary 3 X ea no
issue. 400 gpm 604 psi 30 rpm Trq 4-5k WOB 4-7k. Cont wash/ ream down chasing debris F/ 2,237' to 2,703' MD. 400 gpm 680 psi 30 rpm Trq 3.4-7k P/U 95k
SLK 80k ROT 84k. Blow down top drive. Cont single in hole 8.5" Clean Out BHA W/ 5" 19.5# S-135 NC50 D/P F/ 2,703'' to 3,227' MD. Drift 3.125" OD. P/U 103k
SLK 68k. Total 83 jnts227. Daily disposal to PB G&I: 57 bbls, total 7141 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 0 bbls, total
10060 bbls. Daily Metal 0# total 943#. Daily downhole losses: 0 bbls, total 1437 bbls.
12/28/2022 Cont RIH BHA 4 W/ 5" 19.5# S-135 NC50 D.P, F/ 3,227' to 5,038' MD P/U 127k SLK 74k. Single in hole to 3,768' MD (total 100 jnts) Started RIH W/ stands F/
derrick at 3,768' MD. Service TD. Work on communication issues W/ PH-8 and remote control. Grease IBOP. R/D rig tongs. Mechanic inspect overhead spinners
limit switch. Blow down TD. Cont RIH BHA 4 W/ 5" 19.5# S-135 NC50 D.P, F/ 5,038' to 8,343' MD P/U 182k SLK 74k. Wash down F/ 8,343' to 8,563' MD. P/U
working single and wash to 8,566' MD. 400 gpm 1,650 psi 30 rpm Trq 18-22k. P/U 192k SLK 114k ROT 126k. Adjusted flow rate while Circ due to clabbered up
mud coming back tacking returns down drag chain. ROT/ Rec F/ 8,566' to 8,493' MD. Cont adjusting flow rates 42 to 252 gpm 465 psi 30 rpm Trq 20-22k CBU
1.5X cleaning up clabbered mud from down hole. Blow down TD. PJSM M/U TIW and 1502 head pin and test Equip. Pump through kill line and choke manifold
purging air. Test 9.625" Csg to 2,500 psi for 30 min on chart, good. Pumped 6.6 bbls, bled back 6.6 bbls. R/D test Equip and blow down surface Equip. PJSM
Monitor well 5 min, static. Pump 30 bbl 10.7 ppg dry job. POOH L/D working single and Cont POOH F/ 8,566' to 589' MD. P/U 205k SLK 95k. PJSM POOH L/D 8
jnts 5" HWDP. Rack back 4 stands W/ jars. L/D last stand of 5" HWDP. Drain motor and break off 8.5" TriCone bite. Bit Grade 1-1-WT-A-E-NO-LOG. PJSM Spot
Eline unit. P/U Tee bar and sheave. Secure to elevators W/ secondary safety line. Unhook hydraulic lines to elevator. Raise block in place. AK ELine M/U BHA. Csg
Centralizer 2.79', 2" Lead Filled 65# WT Bar (2" OD) 5', Csg Centralizer 2.79', CRCCL (3.13" OD) 5.03', Csg Centralizer 2.73',. TEKSCBL (2.75" OD) 9.13', Csg
Centralizer 2.71, & 1 7/16" Cable Head. Total Lng 31.21' WT 397.03#. Lag off area around logging unit and rig floor. PJSM Check communication W/ CBL, good.
Hoist BHA to rig floor and zero at table. RIH at 120 ft/min to 1,500' WLM perform free pipe calculation. Cont increasing run speed to 300 ft/min to 7,200' WLM. Start
logging CBL F/ 7,190' to 1,140' WLM 50 ft/min. RIH to 2,500' WLM to recalibrate free point and tools failed. Attempted multiple times to restart. POOH and check
tools. L/D tools and found a kink in ELine. Re head and was unable to get tools working. Found CBL is not working. AK ELine is going to the shop and picking up
spare CBL. Failed CBL is 2 3/4" OD and spare is 1 11/16". Daily disposal to PB G&I: 367 bbls, total 7508 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls.
Daily water from Lake 2: 560 bbls, total 10620 bbls. Daily Metal 0# total 943#. Daily downhole losses: 0 bbls, total 1437 bbls.
12/29/2022 Waiting on tools (Replacement CBL). Sim Ops - Rebuild gunline valves in mud pits. Replace steam line and valve in gas buster room. Service traveling equipment
(crown, TDS, Drawworks). Clean and organize cellar. Service choke manifold. AK-E line on location with replacement CBL 11:30 hrs. PJSM, R/U and RIH w/
YellowJacket CBL assy conveyed on AK E-Line equipment (24.52' OAL). CCL/GR/CBL. RIH to 2750' ELM for baseline with YellowJacket CBL tool. Yellow Jacket
CBL showed skewed parameter settings with AK E-Line power unit. POOH and L/D YJ CBL tool. M/U Ak E-Line CBL tool and RIH to ~2750' ELM. Calibrate and
baseline free pipe parameters. Continue RIH to 7110' ELM before running out of wt. Log up from 7110' to 150' ELM with no hard cmt indicated on logs. RIH with 9-
5/8" test jt. QC the CBL parameters in known free pipe and baseline same. RIH with CBL after obtaining new baseline to 550' ELM. Log up with similar results as
previous run showing no hard cmt indicated on logs. R/D and release AK E-line @ 19:30 hrs. Clean and inspect elevators, Swapped elevators to manual so
hydraulic safety latch and hose can be fixed. Conduct PJSM with Yellow Jacket E-line, backed into position and rigged up sheaves and cables. M/U CCL, 2 Roller
centralizer, CBL and Gama Ray ( Length= 21.62' ) RIH with 9 5/8" test jt and attempted a free pass inside test jt. with no success. L/D 9 5/8" test jt. RIH w/3.25"
CBL tool, top roller centralizer had issues going through wear ring worked through and cont. in the hole. Stopped at 200' due to CBL not reading correctly. POOH to
surface and inspected tool- Good. Run back in with no issues down to 7382' CBL depth of 7374', Log from 7374' to 4800'. observing CMT F/7374' T/6750'. Cont.
logging F/4800' T/Surface observing good CMT F/2500' T/1650'. Once top roller centralizer was at the wear ring tool pulled tight, lowered out of wear ring. E-line
reps were attempting to get tool to pop through by jerking on line with there hands on ground level with no success. While draining. stack e-line reps attempted to
pop through using there hands again when the line pulled free from head loosing tool down hole. Mobilize slick line for fishing CBL tool. R/D Yellow Jacket sheaves,
Pull wear ring and inspect. Clean and work on EAM's while waiting on Slick line. Daily disposal to PB G&I: 0 bbls, total 7728 bbls. Daily disposal to MP G&I: 0 bbls,
total 679 bbls. Daily water from Lake 2: 140 bbls, total 10760 bbls. Daily Metal 9# total 952#. Daily downhole losses: 0 bbls, total 1437 bbls.
12/30/2022 Demob slickline unit from L-Pad and mobilize to W-Pad. Wait on arrival. Continue replace steam fittings for cutting box steam loop. Clean and organize pipeshed
and shop. Clean and prep diverter bolts and equipment. Work maintenance EAM's. Repair heater cores. PJSM, R/U Pollard slickline unit. M/U 5.5" OD bell guide
(Dressed for 1" FN). 26.87' OAL - Rope socket, R-stem, oil jars, spang jars 2x, 5.5" bellguide, 2.6", JU tool). RIH F/ surface to 7818' SLM before losing all dn wt.
Obtain wts every 1000' ft. No indication of tag on TOF. POOH - No Fish. R/D and release Pollard slickline. Mobilize Baker Fishing. Clean and clear rig floor. Gather
and mobilize BOT fishing tools from Deadhorse. On location @ 17:00 hrs. Bring tools to rig floor. PJSM, with crews. P/U 1 single of 5" 19.5# DP and M/U XO,
Bumper jar, Rupture disk sub, overshot and Oversize guide ( 8" O.D ) to BTM. RIH on 5" stds of DP F/47' T/5512'. Move 4 stds of 5" HWDP from ODS to DS. Cont.
RIH on 5" stds of DP F/5512' T/7801'. PU- 184K, SO- 94K. Slowly RIH F/7801' T/8436'. M/U top drive establish pump parameters 4 bpm= 105 psi, 6 bpm= 240 psi,
7 bpm= 310 psi, 8 bpm= 400 psi, PU- 193K, SO -96K, wash F/8436' down to 8554' at 4 BPM, 135 PSI with no indications of latching on fish. Back side was heavy
and U-tubing. CBU @ 500 gpm, ICP= 810 psi, FCP= 705. No pipe movement while circulating. PU-200K, SO-94K. Washed down F/8554' T/8567', 4 bpm, 45 psi
observing pressure increase to 165 psi setting 3K down. P/U to 200K where pressure fell off to 0 psi indicating possibly pulling off fish. Washed back down to 8569'
( 2 ft deeper ) 4 bpm, 45 psi this time seeing pressure increase to 600 psi with no return. flow. Bled off pressure and PU to 200K then 205K. Kicked pumps back on
at .5 bpm, 275 psi with slight returns. SO to 8571' setting 5K down observing pressure increase to 715 psi with no flow indicating full swallow over 3-1/8" fish.
Picked back up 5 ft and kicked on pumps 4 bpm, 200 psi showing good indication of fish on. Rack back std and blow down top drive. POOH on elevators with 5"
19.5# S-135 DP F/8554' T/5512' moving 4 stds of 5" HWDP back to ODS. Cont POOH F/5512' T/1818', pulling 40-120 FPM as per Baker fishing rep with no
downward movement. Daily disposal to PB G&I: 114 bbls, total 7842 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 140 bbls, total
10900 bbls. Daily Metal 9# total 952#. Daily downhole losses: 0 bbls, total 1437 bbls.
12/31/2022 Continue POOH w/ 6-3/8" overshot dressed - 3-1/8" grapple F/ 1776' - T/ surface. Drain stack when pulling fishing BHA thru. L/D CBL fish. Found 2x centralizer
threaded pins missing and 2x blades on upper CBL centralizer had separated. Lost btm half of 1x blade and 2x 3/4" dia rollers downhole. B/O and L/D fish. Found
other threaded pins on centralizers hand tight and 2x were partially backed out. Missing 1/2 of blade measured 10"Lx1"Wx3/8"thick (steel). Hole took proper
displacement for trip. See photos in "O" drive well folder under "photos". R/U HES E-line equipment. Hang sheaves and secure same. Dress E-line with CAST "M"
CBL tool. Zero @ floor. Sim Ops - Bleed down koomey, open ram doors and check for missing centralizer blade (nothing found). RIH with CAST "M" CBL to 3300'
before running out of wt. POOH and redress CBL tool w/ 2x wt bars and rollers. 37.32' OAL / 450#. RIH with CBL to final depth 7274' ELM. Initialize and calibrate
tool. Log up F/ 7274' - T/ 6390' ELM. Field est TOC @ 6730' ELM. Log @ 30 fpm. Log F/ 2600' - T/ surface @ 30 fpm with good indication of cmt from stg @ 2234'
to surface. Ran QC repass both logging intervals (good). Send logs for processing. R/D and release HES E-Line. Mobilize BHA components to rig floor. Set 9" ID
wear bushing (RILDS). Prep pipeshed and stage BHA tools to pick up. Obtain measurements of string magnets, boot baskets and tally 8.5" Cleanout assy. Close
blinds P/U mud motor and M/U 8.5" Tri-cone Bit. Open blinds RIH. M/U 2 string magnets, XO, 2 junk boot baskets and XO torqueing Baker connections to 25K. RIH
with 4 stds of HWDP and jars T/314'. RIH out of Derrick with 5" 19.5# S-135 DP F/314' T/3115' Filling pipe @ 3115'. PU-67K, SO-64K. Cont. RIH out of Derrick
with 5" 19.5# S-135 DP F/3115' T/8510'. Fill piipe. PU-205K, SO-94K. Observing calculated displacement during trip. Wash and ream down F/8510' T/8600'
tagging the top of BFL on depth w/ 5K down 450 GPM, 1160 PSI, 30 RPM, 16-18K TQ. Drill out Shoe track F/8600' T/8627' and new formation T/8756', 450 GPM,
1160 PSI, 30 RPM, 17-18K TQ on BTM, 16-18K TQ off BTM, 3-7K WOB. PU-220K , SO-94K, ROT-126K. Tagged all float equipment on depth. Daily disposal to
PB G&I: 265 bbls, total 8107 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 140 bbls, total 10900 bbls. Daily Metal 9# total 961#.
Daily downhole losses: 0 bbls, total 1437 bbls.
1/1/2023 Displace well over from 9.0 PPG spud mud to 9.2 PPG Baradrill-N at 450 GPM, 892 PSI, 30 RPM, 17-18K TQ while recip. F/8756' T/8694'. PU=185K, SO=84K,
ROT=116K. Rig up to perform FIT and flood all surface equipment. Pressure up to 730 PSI ( EMW of 12.01 PPG ) Shut down and monitor pressure for 10 min.
Pumped 2.7 BBLS- Bled back 2 BBLS. Blow down and R/D test equipment. Monitor well for 10 min= static. Line up and pump 30 BBL dry job. Blow down TD.
POOH on elevators F/8700' T/5589'. PU-146K, SO-88K. Observed calculated displace. Pulled through float equipment with no issues. Cont. POOH F/5589' T/314',
PU-51K, SO-50K. Still observing calculated displacement during the trip. Racked back 4 Stds of HWDP and jars, L/D XO's, 2 Junk boot baskets and 2 string
magnets retrieving Centralizer spring and 42# of metal from magnets and boot baskets. Break bit and L/D motor. Bit Grade= 1-1-WT-A-E-I-JD-BHA. P/U and stage
BHA pieces on rig floor. P/U Geo-piolot and M/U NRP and BIT RIH. M/U ADR, DM and TM and perform download as per Sperry MWD. Cont. M/U 2 Float subs, 2
NM Flex collars, 4 stds of HWDP and jars RIH T/400'. Pick up First single and perform shallow pulse test. 500 GPM, 850 PSI- good test, Break in Geo-pilot at 5-10-
20 and 30 RPM's, Cont. P/U 5" 19.5# S-135 NC50 DP and singling in the hole Drifting off skate W/3.125" drift F/400' T/2940' filling pipe +/- 2500'. PU- 100K, SO-
77K. Cont. singling in the hole with 5" 19.5# S-135 NC50 DP F/2940' T/5864', Drifting Pipe off skate W/3.125" Drift, PU-135K, SO-75K, Observed calculated
displacement while picking up singles. RIH on stds of 5" 19.5# S-135 NC50 DP from derrick F/5864' T/8646'. PU-180K, SO-75K. Observing calculated
displacement during trip. Shut off hole fill, monitor well for 10 min and drain stack. Pull trip nipple and install MPD Bearing on bottom of std. M/U std and lower
Bearing to MPD head, Close and tighten clamp. Line up to pump through Beyond lines and PT beyond lines to 250/1250 psi for 5 min each. Fill pipe and establish
circulation @ 395 GPM, 1180 PSI, Hang off blocks, Remove guards from draw works. Mark drill line for cut and unspool to mark. Cut drill line and remove
remaining drilling line from drum. Remove dog nut and send old line down beaver slide. Daily disposal to PB G&I: 1050 bbls, total 9157 bbls. Daily disposal to MP
G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 200 bbls, total 11100 bbls. Daily Metal 53# total 1014#. Daily downhole losses: 0 bbls, total 1437 bbls.
1/2/2023 Continue Cut and Slip drilling line. Check brakes (good). Calibrate blocks, crown saver and floor saver. Sim Ops - Shear mud during cut/slip operations. 400 gpm,
1070 psi, 78u gas. PJSM, Grease crown sheaves, TDS and prep rig floor for drilling operations. Wash down F/ 8661' - T/ 8756' and drill 8.5" production lateral F/
8756' - T/ 9168' MD (4975' TVD). 412' total / AROP 103'. 500 gpm, 1701 psi on, 1590 psi off, 60-120 rpm (depending on stick slip), 17k tq on, 15k tq off, 10.44
ECD w/ 9.2 MW. Max gas 869u. P/U 202k, S/O 70k, ROT 119k. Cont. Drilling 8.5" production lateral F/ 9168' - T/ 9995' MD (4949' TVD). 827' total / AROP 139'.
515 gpm, 1753 psi on, 1727 psi off, 60-120 rpm (depending on stick slip), 17-20k tq on, 16-19k tq off, 10.51 ECD w/ 9.25 MW. Beyond F/O-507 gpm. Max gas
1016u. P/U 187k, S/O 78k, ROT 113k. Back reaming full stds prior to connections. At 9620' started adding lubes to 2-2.5% due to high tq. Drilled out of zone 2'
TVD into OBc @ 9930'. SPR @ 9995' MP-1 32/48= 195/260, MP-2 32/48= 190/255. Cont. Drilling 8.5" production lateral F/ 9995' - T/ 10945' MD (4964' TVD).
950' total / AROP 158'. 515 gpm, 1915 psi on, 1865 psi off, 120 rpm, 20-22k tq on, 19-21k tq off, 10.84 ECD w/ 9.3 MW. Beyond F/O-505 gpm. WOB=8-12k Max
gas 1037u. P/U 193k, S/O 65k, ROT 110k. Back reaming full stds prior to connections. Back in OBd sand @ 10170'- out of zone for 240'. SPR @ 10495' (4956'
TVD ) MP-1 32/48= 255/320, MP-2 32/48= 255/320. Cont. Drilling 8.5" production lateral F/ 10945' - T/ 11726' MD (4976' TVD). 781' total / AROP 130'. 515 gpm,
2040 psi on, 1985 psi off, 120 rpm, 18-21k tq on, 17-19k tq off, 10.94 ECD w/ 9.3 MW. Beyond F/O-503 gpm. WOB= 7-13k Max gas 1065u. P/U 186k, S/O 71k,
ROT 111k. Back reaming full stds prior to connections. SPR @ 11520' (4970' TVD ) MP-1 32/48= 342/415, MP-2 32/48= 340/410. Distance to Plan 19.16', Low
12.55', Left 14.48'. Daily disposal to PB G&I: 684 bbls, total 9841 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 700 bbls, total
11800 bbls. Daily Metal 7# total 1021#. Daily downhole losses: 0 bbls, total 0 bbls.
1/3/2023 Cont. Drilling 8.5" production lateral F/ 11726' - T/ 12662' MD (4970' TVD). 936' total / AROP 156'. 515 gpm, 2211 psi on, 2138 psi off, 120 rpm, 18-22k tq on, 19-
21k tq off, 11.3 ECD w/ 9.3 MW. Beyond F/O-509 gpm. WOB= 8-16k Max gas 1008u. P/U 179k, S/O 73k, ROT 109k. Back reaming full stds prior to connections.
Cont. Drilling 8.5" production lateral F/ 12662' - T/ 13618' MD (4982' TVD). 956' total / AROP 159'. 550 gpm, 2410 psi on, 2350 psi off, 120 rpm, 18-20k tq on, 17-
19k tq off, 11.15 ECD w/ 9.3 MW. Beyond F/O-535 gpm. WOB= 7-12k Max gas 978u. P/U 171k, S/O 74k, ROT 108k. Back reaming 30' prior to connections.
Added 2 drums of NSX-Lube @ 13000' observing tq decrease F/21Kk- T/17k, P/U decrease 7k and SO increase 5k. At 13115' T/13300' performed dump and dilute
of 200 bbls dropping ECD's F/11.4 T/11.2. Cont. Drilling 8.5" production lateral F/ 13618' - T/ 14632' MD (4974' TVD). 1014' total / AROP 169'. 550 gpm, 2460 psi
on, 2420 psi off, 120 rpm, 15-18k tq on, 15-17k tq off, 11.26 ECD w/ 9.25 MW. Beyond F/O-528 gpm. WOB= 6-16k Max gas 1111u. P/U 170k, S/O 71k, ROT
107k. Back reaming 30' prior to connections. SPR's 13612' (4982' TVD) MP-1 32/48= 370/445, MP-2 32/48= 365/440. Cont. Drilling 8.5" production lateral F/
14632' - T/ 15333' MD (4974' TVD). 701' total / AROP 117'. 550 gpm, 22591 psi on, 2520 psi off, 120 rpm, 15-18k tq on, 13-15k tq off, 11.4 ECD w/ 9.3 MW.
Beyond F/O-523 gpm. WOB= 7-13k Max gas 978u. P/U 159k, S/O 76k, ROT 106k. Back reaming full stds prior to connections. SPR's 14700' (4975' TVD) MP-1
32/48= 445/525, MP-2 32/48= 444/520. Distance to Plan 24.29', Low 21.34', Left 11.61'. Daily disposal to PB G&I: 1373 bbls, total 11214 bbls. Daily disposal to
MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 1540 bbls, total 13340 bbls. Daily Metal 12# total 1033#. Daily downhole losses: 0 bbls, total 0 bbls.
1/4/2023 Cont. Drilling 8.5" production lateral F/ 15333' - T/ 15771' MD (4979' TVD). 438' total / AROP 73'. 550 gpm, 2578 psi on, 2498 psi off, 120 rpm, 15-18k tq on, 13-
15k tq off, 11.4 ECD w/ 9.15 MW. Beyond F/O-515 gpm. WOB= 10-14k Max gas 909u. P/U 154k, S/O 85k, ROT 109k. Back ream full stds prior to connections.
SPR @ 15705' ( 4977' TVD) MW 9.15 PPG, MP-1 32/48= 450/533, MP-2 32/48= 444/525. Replace Liner, Wear plate and swap on MP #1 Pod #1 while Circulating
with MP #2, 205 gpm, 805 psi, 80 rpm, 12-13k tq, Max gas 145u. SPR @ 15771' ( 4979' TVD) MW 9.15 PPG, MP-1 32/48= 441/525, MP-2 32/48= 444/525. Cont.
Drilling 8.5" production lateral F/ 15771' - T/ 15904' MD (4979' TVD). 133' total / AROP 89'. 550 gpm, 2563 psi on, 2451 psi off, 120 rpm, 15-18k tq on, 13-15k tq
off, 11.42 ECD w/ 9.15 MW. Beyond F/O-510 gpm. WOB= 9-12k Max gas 803u. P/U 154k, S/O 85k, ROT 110k. Back ream full stds prior to connections. Cont.
Drilling 8.5" production lateral F/ 15904' - T/ 16825' MD (4957' TVD). 921' total / AROP 154'. 525 gpm, 2590 psi on, 2533 psi off, 120 rpm, 17-19k tq on, 15-17k tq
off, 11.49 ECD w/ 9.15 MW. Beyond F/O-499 gpm. WOB= 19-12k Max gas 662u. P/U 164k, S/O 0k, ROT 108k. Back ream full stds prior to connections. Lost down
weight @ 16351'. Cont. Drilling 8.5" production lateral F/ 16825' - T/ 17459' MD (4963' TVD). 634' total / AROP 106'. 540 gpm, 2650 psi on, 2550 psi off, 120 rpm,
18-21k tq on, 18-19k tq off, 11.35 ECD w/ 9.1 MW. Beyond F/O-509 gpm. WOB= 8-12k Max gas 258u. P/U 171k, S/O 0k, ROT 107k. 16-18 BPH dynamic loss
rate. Back ream full stds prior to connections. SPR @ 17111' ( 4960' TVD) MW 9.15 PPG, MP-1 32/48= 455/555, MP-2 32/48= 460/555. At 17111' made a hook
and pressure increased to 3150 psi @ 480 gpm, from 2670 psi off btm at 540 gpm. MWD also wouldn't pulse and we were unable to get detection. Cycled pumps a
few times with no success. Racked back stand, screwed into stump to inspect IBOP, IBOP was functioning properly. Attempted to pump at 500 gpm, 3360 psi with
no MWD pulse or detection. Shut down lined up on kill line pumping to eliminate surface equipment reading same gpm's in/out. with Beyond coriolis. Lined back up
pumping down DP and at 340 gpm MWD was seeing pulses and detection. Came up full rate and pressures normalized. Issue unknown thoughts are possible ice
plug in DP. Flash lighting remainder of stds to TD. Hit a concretion @ 17,220' that deflected us down 1.3 deg to 88.3 INC as bedding rolled up from 90.5 to 91.5
deg, causing us to hit the BTM of the OBd dropping res down to 7.7 ohms over 50'. TD called 191' early @ 17459'. Distance to Plan 31.67', Low 31.42', Left 3.96'.
Rotate and reciprocate F/17459' T/17398' while circ. 4x BU, 550 gpm, 2680 psi, Beyond F/O-527 gpm, 120 rpm, 15-17k tq, ECD-11.28 w/9.1 ppg mw. Max gas
121u. Pumped 35 bbl 8.6 ppg 35 vis/35 bbl 9.5 ppg 165 vis tandem sweep back on time with no increase in cuttings. Build sap pill in pill pits empty trip tanks and
pit #5, clean in prep for displacement. Grease and inspect Iron roughneck. Observing 16-18 BPH dynamic loss rate. SPR's 17459' (4963' TVD) 9.1 ppg, MP-1
32/48= 459/558, MP-2 32/48= 463/561. Pump 40 bbls of sap pill chased with 20 bbls 9.1 ppg Quikdrill-N, pump another 40 bbls of sap pill chased with 20 bbls of
Quikdrill-N, pump remaining 40 bbls of sap pill and displace well with 9.1 ppg Quikdril-N, 334 gpm, 1100 psi, 120 rpm, 16-17k tq, ECD-10.65, Max gas 65u. while
rotating and reciprocating F/17459' T/17398', parked on BTM while sap train exit the bit. Daily disposal to PB G&I: 969 bbls, total 12183 bbls. Daily disposal to MP
G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 1120 bbls, total 14460 bbls. Daily Metal 2# total 1035#. Daily downhole losses: 10 bbls, total 10 bbls.
1/5/2023 Cont. Displacing well over to 9.1 ppg Quikdrill-N 415 gpm, 1320 psi, Beyond F/O 404 gpm, 120 rpm, 13-16k tq, Max gas 94u, Monitor well through Beyond- good.
Clean under shaker beds and surface equipment. SPR's 17459' (4963' TVD) MP-1 32/48= 285/356, MP-2 32/48= 281/355, 10 bph loss rate. L/D single working
single and dropped drift 2.4" OD 20" long. BROOH F/17459' T/15588', 525 gpm, 1565 psi, Beyond F/O- 510 gpm, 120 rpm, 13-15k tq, Max gas 38u, P/U 167k,
S/O N/A, ROT 117k, Pulling 25-40 fpm as hole dictates. L/D single working single and dropped drift 2.4" OD 20" long. Cont. BROOH F/15588' T/12664' (4970'
TVD) 525 gpm, 1650 psi, Beyond F/O 460 gpm, ECD 10.08 ppg, 120 rpm, 14-15k tq, P/U 163k, S/O 73k, ROT 111k, Max gas 39u, Adding water @ 15 bph,
pulling 25-40 fpm as hole allows. Still seeing 8-10 bph dynamic loss rate. Cont. BROOH F/12664' T/9300' (4970' TVD) 525 gpm, 1650 psi, Beyond F/O 460 gpm,
ECD 11.38 ppg, 120 rpm, 14-15k tq, P/U 163k, S/O 73k, ROT 111k, Max gas 39u, Adding water @ 15 bph, pulling 25-40 fpm as hole allows. Still observing 8-10
bph dynamic loss rate. F/10090' T/9725' observed multiple slight pack offs with 150 psi spike 5-8k increase in WT and 2-4k increase in tq with Beyond F/O
dropping 100 gpm. Ran back down each time and back reamed back through with no issues. Cont. BROOH F/9300' T/8727' (4991' TVD) 525 gpm, 1510 psi,
Beyond F/O 470 gpm, ECD 10.0 ppg, 120 rpm, 14-15k tq, P/U 178k, S/O 74k, ROT 112k, Max gas 172u, Adding water @ 15 bph, pulling 25-40 fpm as hole
allows. 8-10 bph dynamic loss rate. Attempted to pull with no rotation pumps on 525 gpm, 1510 psi with 8-10k over pull at 8808' ( first stab at shoe ) ran back down
and back reamed F/8808' T/8730' at 20 rpm, 14-15k tq with no issues. CBU 3x, 525 gpm, 1485 psi, 40 rpm, 15k tq, Beyond F/O 497 gpm, Max gas 179u, ECD 9.9,
Pumped 30 bbl 9.15 ppg/300 vis sweep around with no increase in cuttings. Monitor well for 5 min and close in Beyond chokes for 5 min watch for pressure build=
none. Blow down top drive and Geo-span, Drain stack and pull MPD bearing, install trip nipple close clamp. Turn on hole fill and watch for leaks. Grease blocks,
topdrive, and Iron roughneck. Check oil levels in top drive. POOH F/8725' T/8613' laying down drill pipe. Stop and pump 30 bbl 9.9 dry job 4 bpm, 196 psi. Daily
disposal to PB G&I: 2187 bbls, total 14370 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 420 bbls, total 14880 bbls. Daily Metal 2#
total 1037#. Daily downhole losses: 247 bbls, total 347 bbls.
1/6/2023 Continue POOH F/ 8613' - T/400' laying down 5" NC50, S-135. Continue POOH F/ 400' to surface laying down 5" drill pipe and RSS BHA assy. L/D HWDP, FS,
NM Flex, (Retrieve drift from top of float) Read MWD, L/D MWD tools, Geo-Pilot and Bit. Bit grade 1,2,CT,A,X,I,NO,TD. 14.5 bbl loss for trip. RIH w/10 stds of 5" DP
T/636', L/D remaining 10 stds of 5" DP F/636' to surface. M/U 5" 19.5# S-135 NC-50 safety jt with 563 wedge XO, 5" FOSV, and 10" OD lift sub. P/U 6 5/8" YC 250
ton elevators, slips, dog collar and air slips. R/U power tongs. P/U 6 centrilizers to rig floor. RIH with 6 5/8" 20#, L-80, 563 Wedge slotted liner F/ Surface T/5627'
torqueing connections to 7100 ft/lbs at 50 fpm. P/U 87k, S/O 84k. Cal Disp= 40 bbls, Act Disp= 29 bbls, Loss of 11 bbls, Conducted well control drill with rig crew.
Cont. RIH with 6 5/8" 20#, L-80, 563 Wedge slotted liner F/5672' T/8619' torqueing connections to 7100 ft/lbs at 50 fpm. P/U 152k, S/O 84k. Cal Disp= 20.3 bbls,
Act Disp= 12.5 bbls, Loss of 6.8 bbls, Conducted well control drill with rig crew and held AAR. Pick up safety jt and RIH and hang off blocks. Cut and slip drilling
line ( 8 wraps cut 50' ) , TM= 708, ACC TM= 33,497, LOD = 1394'. Perform crown wobble EAM and check breaks. Static loss rate of 2.3 BPH. Daily disposal to PB
G&I: 57 bbls, total 14427 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 0 bbls, total 14880 bbls. Daily Metal 0# total 1037#. Daily
downhole losses: 52 bbls, total 399 bbls.
1/7/2023 Grease crown, blocks and top drive. Extend out and grease spinners. Check gear oil on TD and rotary table. Waiting on OH/Triple connect assembly. Inspect TD
and cradle for leaks and cracks. Remove Glycol pump #2 from roof. Sting in and position tree and adapter into cellar. Work on rig maintenance and EAM's. Monitor
well on trip tank- 2 BPH loss rate. Cont. RIH with 6 5/8" 20#, L-80, Wedge 563 slotted liner F/8619' T/8905' torqueing connections to 7100 ft/lbs. Running speed 50
ft/min. M/U Triple connect and bakerlock, M/U Weltec inflatable PKR and XO w/bakerlock. Install 6 solid centrilizers on blanks as per tally. Change out handling
equipment. Cont. RIH with 6 5/8" slotted liner on 5" 19.5# S-135 NC-50 DP F/8905' T/17459' stopping at 8975' circulating at 4 bpm, 275 psi to verify clear fluid
path. Tagged btm on depth w/20k down 2x. Racked back std and P/U 10 ft pup for space out. Spaced out with shoe @ 17459' and TOL @ 8527.59'. P/U 205k, S/O
62k, Cal Disp= 73 bbl, Act Disp= 67 bbls, Loss of 6 bbls for the trip. Pump 10 bbls down string 2 bpm, 275 psi. Shut down and drop 1.125" Phenolic ball. Park with
string in tension 175k, Pump ball down at 4 bpm, 475 psi for 1620 stks, 2 bpm, 155 psi to 2165 stks where ball landed on seat. Slowly increased pressure to 2545
psi and held for 5 min. Slacked off quickly to 35k showing hanger had set. Slowly increased pressure to 3679 psi where pressure fell off indicating hyd. release. Felt
pusher tools full shift at surface 2885 psi. P/U 2 ft and set slips, B/D top drive line up and close upper rams. P/T 7" x 9 5/8" SLZXP LTP to 1500 psi- good test, 2.2
bbls pumped, 2.2 bbls bled back. POOH L/D 2 jts. Pumped 25 bbl 9.9 ppg corrosion inhibited dry job, B/D TD, kill and choke lines. Change out 5" manual elevators
with Hydraulic ones. Cont to POOH laying down DP F/8527' T/4550' culling pipe as per tally, P/U 113, S/O 89k. Cal Disp= 31 bbls, Act disp= 38 bbls. Lost 7 bbls
for the trip. Cont. POOH laying down DP F/4550' T/32', B/D and L/D running tool as per baker rep. Cal Disp= 44.8 bbls, Act disp= 54.4 bbls. Lost 9.6 bbls for the
trip, Static loss rate of 2.3 bph. Break down 5" safety jt, Pull wear ring. P/U Parker CSG. 4 1/2" pipe handling equipment and power tongs. Swap out elevators to 75
ton YT's. R/U power tongs and torque turn equipment. Load and prep pipe shed for 4 1/2" upper completion run. Still observing 2.3 bph static loss rate. RIH with
4.5" 12.6# 13Cr Vamtop tbg. F/Surface T/233' as per tally, torqueing connections to 4440 ft/lbs. Performed dump test with 1st full jt of tbg. Bakerloc mule shoe jt to
first jt of 13cr. PU 38K, SO 38K. Daily disposal to PB G&I: 0 bbls, total 14427 bbls. Daily disposal to MP G&I: 0 bbls, total 679 bbls. Daily water from Lake 2: 0 bbls,
total 14880 bbls. Daily Metal 0# total 1037#. Daily downhole losses: 44 bbls, total 433 bbls.
Activity Date Ops Summary
1/8/2023 Cont. RIH with 4.5" 12.6# 13Cr Vamtop tbg F/233' T/1342', M/U RHC-M x-nipple, 1 jt and 9.625" TNT PKR bakerlocing throughs 3 connections T/1507'. Cont RIH
with 4.5" 12.6# L-80 Vamtop tbg F/1342' T/6382' as per tally, P/U 87K, S/O 66K, Cal Disp=26.6 bbls, Act Disp= 17.5 bbls, lost 9.1 bbls for trip,Jewelry ran was 4
GLM- 1 w/SOV, 3 x-nipples and 1 PKR with 6 shear pins.,Cont RIH with 4.5" 12.6# L-80 Vamtop tbg F/6382' T/8675' as per tally, P/U FMC 13 5/8" x 4.5" hanger
and landing jt. 5 ft in to mule shoe depth of 8701.48', P/U 3 ft off seat for displacement. P/U 103K, S/O 70K, Cal Disp= 7 bbls, Act Disp= 7 bbls, lost 0 bbls,M/U XO
to landing jt and kelly up. Displace well over to 9.1 ppg corrosion inhibited brine 4 bpm- 154 psi, 6 bpm- 240 psi for a total of 580 bbls pumped.,Drain stack and
land hanger with 35K hanging off. PT seal to 1000 psi for 5 min. Drop ball and rod ( Length- 9.03', Ball OD- 1 7/8", Fish neck- 1 3/8") B/D top drive, L/D landing jt.
Flood and purge air from surface lines. Pressure up to 3500 psi on tbg. setting PKR and performing MIT-T holding for 30 min- good test., bleed tbg down to 2100
psi and line up on I/A. Pressure up on I/A to 3500 psi holding for 30 min- good t,Pressure up on I/A to 3500 psi holding for 30 min- good test. Dumped tbg and
sheared out valve observing both I/A and tbg fall to 0 psi. A total of 6.6 bbls pumped and 6.5 bbls back for both tests. Pump 2 bbls down I/A at 1 bpm-10 psi, 2 bpm-
43 psi.,Suck out stack and install BPV. Flush all surface lines, equipment and Johnny whack stack with con-det soap pill and water. Blow down choke, kill, top drive
and mud lines.,B/D hole fill lines and remove trip nipple and drip pans. Install RCD test cap and remove chain binders. Hook up bridge cranes. Bleed off and
disconnect koomey lines, unbolt stack and spacer spool. Remove choke and kill lines. P/U stack and set on pedestal. Pull clean and grease ring grooves on spacer
spool,Sim-ops flush through surface lines and pumps in pits.,Inspect hanger and LDS as per Vault well head rep. Install CTS on top of BPV, N/U tree and adaptor
and torque. Sim- ops cleaning pits,PT hanger void to 500/5000 psi for 5/10 min each- good test. Fill tree and PT to 5000 psi, O-ring on ottis cap leaked, changed
out and brought pressure back up to 5000 psi- no leaks. Pull CTS and BPV,R/U to pump down I/A taking returns through the tbg back to cuttings box. Stage and
R/U LRS,Hold PJSM with LRS and crew, PT all surface lines to 2000 psi. Line up and pump 60 deg freeze protect diesel down the I/A @ 1.5 bpm- ICP= 50 psi.
Increased rate to 2 bpm 50 bbls away 184 psi. 90 bbls away 271 psi,Daily disposal to PB G&I: 1229 bbls, total 15656 bbls. Daily disposal to MP G&I: 0 bbls, total
679 bbls. Daily water from Lake 2: 140 bbls, total 15020 bbls. Daily Metal 0# total 1037#. Daily downhole losses: 24 bbls, total 467 bbls.
1/9/2023 Cont. w/ Diesel freeze protect operations, Total bbls pumped 155 bbls, FCP= 313 at 2 bpm, B/D lines and R/D LRS. Allow well to u-tube for 1 hr. Cont. cleaning
pits, perform MP #2 inspection, strap and tally 110 jts of 5" DP. U-tube pressure 175 psi.,Bridle up and scope down derrick, Finish MP #2 inspections. C/O 5
valves and seats between both MP's. Remove cuttings box and R/D U-tube lines shutting in 175 psi on both I/A and TBG. Swap to cold starts. Blow down steam
and water and R/D inter-connects.,Finish cleaning pill pits and trip tanks. Secure roof tops and prep for rig move. Rig was released at 12:00 hrs, Place jeep under
gen mod.,Trucks on location @ 12:00. Seperate modules and stage on pad. Pull sub off W-26. Install starting head and Diverter-T. Spot sub over W-241.,Set mats,
Spot catwalk, pipe shed, mud mod and gen mod. Trucks released at 22:00 hrs.,R/U inter-connects and plug in as per electrician. Swap from cold starts to gen
power @ 23:30. Turn on steam, water and air. Released rig from W-26B @ 23:59.
50-029-21964-02-00API #:
Well Name:
Field:
County/State:
PBW W-26B
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
p No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
156
54
X Yes No X Yes No 4
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns? Yes X 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? Yes X No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
9.625" Csg X/O
Pup Jnt
LLDS
Casing (Or Liner) Detail
Shoe
ES Cementer
Pup Jnt
10
SE
C
O
N
D
S
T
A
G
E
MP 1
3:08
Returned to surface
Rotate Csg Recip Csg Ft. Min. PPG9.55
Shoe @ 9727.46 FC @ Top of Liner8,641.86
Floats Held
Spud Mud
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Innovex 1.73 8,727.46 8,725.73
2,216.84 2,175.71
2.82 2,237.23 2,234.41
2,234.419 5/8 40.0 L-80 TXP BTC 17.57
BTC/ Vam Top
10 TXP BTC Halliburton
2,216.84
8" LH Acme 1.34
9 5/8 47.0
9 5/8 47.0 L-80
Fluted Hanger 10 3/4 27.22
41.13
L-80 Vam Top
9.625" Csg 9 5/8 47.0 L-80 Vam Top
25.88 25.88
2,175.71 35.70
8.48 35.70 27.22
2,140.01
Csg Wt. On Hook:360,000 Type Float Collar:Conventional No. Hrs to Run:36
9.4 6.5
1747
10
10.7 220 4.5
800
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
630
3
9.5 6 162.1/164
631/629.9
1350
0
MP #1
15.8 82
Bump press
Cement Evaluation Log
Bump Plug?
Y
14:40 12/25/2022 6,550
2234.41
,,
CEMENTING REPORT
Csg Wt. On Slips:
Spud Mud
Tuned Spacer
435 2.88
Stage Collar @
54
Bump press
100
200
ES Closure OK
58
12 281
26.95 RKB to CHF
Type of Shoe:Ported Casing Crew:Parker Wellbore
No. Jts. Delivered 285 No. Jts. Run 216 19
Length Measurements W/O Threads
Ftg. Delivered 9,400.00 Ftg. Run 8,691.00 Ftg. Returned 709.00
Ftg. Cut Jt. Ftg. Balance
3.5
ArcticCem
Type
2 ea SB & 4 ea SR on shoe jnt, 1 ea SB Blank Jnt and FC jnt. 1 ea SB to jnt 26. Every other Jnt to Jnt 62. 5 ea SB before ES,
1 ea SB & 1 ea SR on ES Pups, 5 ea SB after ES. Every third jnt F/ jnt 169 to jnt 214. Total 8 stop rings and 72 Solid Body
Centralizers.
9.625" Csg 9 5/8 47.0 L-80 BTC 82.49 8,725.73 8,643.24
FC 10 BTC Innpvex 1.38 8,643.24 8,641.86
9.625" Csg 9 5/8 47.0 L-80 BTC 40.50 8,641.86 8,601.36
Baffle Adapter 10 BTC Halliburton 1.40 8,601.36 8,599.96
9.625" Csg 9 5/8 47.0 L-80 BTC 40.51 8,599.96 8,559.45
9.625" Csg X/O 9 5/8 47.0 L-80 BTC/ VAM Top 38.50 8,559.45 8,520.95
9.625" Csg 9 5/8 47.0 L-80 Vam Top 6,226.73 8,520.95 2,294.22
9.625" Csg X/O 9 5/8 47.0 L-80 VAM Top/ BTC 38.95 2,294.22 2,255.27
Pup Jnt 9 5/8 40.0 L-80 TXP BTC 18.04 2,255.27 2,237.23
EconoCem Type I II 675 2.35
HalCem Type I II 400 1.15
4.5
Premium G 270 1.16
12/26/2022 Surface
Spud Mud
X
200
Surface
6,550
X
Evaluation Log
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Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.01.09 09:21:09 -09'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.01.09 09:39:35 -09'00'
Kyle Wiseman Hilcorp Alaska, LLC
Geo Tech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: Kyle.Wiseman@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 01/24/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230124
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BCU 14B 50133205390200 222057 11/21/2022 YELLOW JACKET GPT-PERF
CLU 10RD 50133205530100 222113 11/17/2022 YELLOW JACKET GPT
CLU 10RD 50133205530100 222113 10/26/2022 YELLOW JACKET GPT-PERF
CLU 10RD 50133205530100 222113 11/28/2022 YELLOW JACKET GPT-PERF
CLU 10RD 50133205530100 222113 12/2/2022 YELLOW JACKET PERF
CLU 10RD 50133205530100 222113 11/25/2022 YELLOW JACKET PLUG
CLU 13 50133206460000 214171 11/29/2023 YELLOW JACKET PERF
PBU W-26B 50029219640200 222151 12/30/2022 YELLOW JACKET SCBL
SRU 224-10 50133101380100 222124 12/19/2022 YELLOW JACKET GPT
SRU 224-10 50133101380100 222124 12/16/2022 YELLOW JACKET GPT-PERF
SRU 224-10 50133101380100 222124 12/21/2022 YELLOW JACKET GPT-PERF
SRU 224-10 50133101380100 222124 12/29/2022 YELLOW JACKET GPT-PERF
Please include current contact information if different from above.
By Meredith Guhl at 9:59 am, Jan 24, 2023
T37463
T37464
T37464
T37464
T37464
T37464
T37465
T37466
T37467
T37467
T37467
T37467
PBU W-26B 50029219640200 222151 12/30/2022 YELLOW JACKET SCBL
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2023.01.24 10:05:13 -09'00'
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 01/18/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
PBU W-26B
PTD: 222-151
API: 50-029-21964-02-00
FINAL LWD FORMATION EVALUATION LOGS (12/16/2022 to 01/04/2023)
x EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Geosteering and EOW Report
SFTP Transfer – Main Folders:
PBU W-26B LWD Subfolders:
PBU W-26B Geosteering Subfolders:
Please include current contact information if different from above.
By Meredith Guhl at 10:21 am, Jan 19, 2023
222-151
T37447
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2023.01.19 10:21:46 -09'00'
Kyle Wiseman Hilcorp Alaska, LLC
Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: Kyle.Wiseman@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 01/13/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230113
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
MPU C-39 50029228490000 197248 1/1/2023 HALLIBURTON MFC24
PBU L-114B 50029230320200 222135 12/23/2022 HALLIBURTON RBT
PBU W-26B 50029219640200 222151 12/31/2022 HALLIBURTON CAST
Please include current contact information if different from above.
By Meredith Guhl at 8:44 am, Jan 19, 2023
T37441
T37442
T37443PBU W-26B 50029219640200 222151 12/31/2022 HALLIBURTON CAST
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2023.01.19 09:00:18 -09'00'
PBU W-26B
PTD 2221510
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner:Rig No.:Innovation DATE:12/27/22
Rig Rep.:Rig Email:
Operator:
Operator Rep.:Op. Rep Email:
Well Name:PTD #2221510 Sundry #
Operation:Drilling:x Workover:Explor.:
Test:Initial:X Weekly:Bi-Weekly:Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1677
MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1 P
Permit On Location P Hazard Sec.P Lower Kelly 1 P
Standing Order Posted P Misc.NA Ball Type 2 P
Test Fluid Water Inside BOP 1 P
FSV Misc 0 NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0 NA Trip Tank P P
Annular Preventer 1 13-5/8", 5K P Pit Level Indicators P P
#1 Rams 1 4-1/2"x7"P Flow Indicator P P
#2 Rams 1 Blinds P Meth Gas Detector P P
#3 Rams 1 2-7/8"x5-1/2"P H2S Gas Detector P P
#4 Rams 0 NA MS Misc 0 NA
#5 Rams 0 NA
#6 Rams 0 NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8", 5K P Time/Pressure Test Result
HCR Valves 1 3-1/8", 5K P System Pressure (psi)2950 P
Kill Line Valves 1 3-1/8", 5K P Pressure After Closure (psi)1500 P
Check Valve 0 NA 200 psi Attained (sec)33 P
BOP Misc 0 NA Full Pressure Attained (sec)101 P
Blind Switch Covers:All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 @ 2358psi P
No. Valves 15 P ACC Misc 0 NA
Manual Chokes 1 P
Hydraulic Chokes 1 FP Control System Response Time:Time (sec)Test Result
CH Misc 0 NA Annular Preventer 13 P
#1 Rams 9 P
Coiled Tubing Only:#2 Rams 8 P
Inside Reel valves 0 NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:5.0 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 12/24/22, 21:36
Waived By
Test Start Date/Time:12/27/2022 13:30
(date)(time)Witness
Test Finish Date/Time:12/27/2022 18:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Sully Sullivan
Hilcorp
Super Choke failed initial test. Serviced valve and retested without issue. Tested with 4.5" and 5" test joints.
Matt Vanhoose
Hilcorp
Shane Barber
PBU W-26B
Test Pressure (psi):
nnovationtoolpusher@hilcorp.com
sbarber@hilcorp.com
Form 10-424 (Revised 08/2022)2022-1227_BOP_Hilcorp_Innovation_PBU_W-26B
Hilcorp North Slope LLC========jbr
J. Regg; 5/24/2023
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN ORIN W-26B
JBR 01/26/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:Good Test and ready when I arrived.
TEST DATA
Rig Rep:Joel StureOperator:Hilcorp North Slope, LLC Operator Rep:James Lott
Contractor/Rig No.:Hilcorp Innovation PTD#:2221510 DATE:12/15/2022
Well Class:DEV Inspection No:divRCN221216124308
Inspector Bob Noble
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:NA NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:13.625 P
Hole Size:12.25 P
Vent Line(s) Size:16 P
Vent Line(s) Length:215 P
Closest Ignition Source:80 P
Outlet from Rig Substructure:199 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:NA
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:12 P
Knife Valve Open Time:9 P
Diverter Misc:0 NA
Systems Pressure:P3000
Pressure After Closure:P1900
200 psi Recharge Time:P16
Full Recharge Time:P48
Nitrogen Bottles (Number of):P6
Avg. Pressure:P2250
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
NA NAMud System Misc:
SCHRADER BLUFF OIL POOL, ORION DEVELOPMENT AREA
12.14.2022
322-702
By Anne Prysunka at 1:48 pm, Dec 14, 2022
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: 2022.12.14 13:19:58 -09'00'
Monty M
Myers
10-407
MGR14DEC22 SFD 12/14/2022 DSR-12/14/22
* BOPE test to 3000 psi. Annular to 2500 psi.
JLC 12/15/2022GCW 12/15/22
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2022.12.15 15:02:52
-09'00'
RBDMS JSB 121622
Prudhoe Bay West
(PBU) W-26B
Drilling Permit
Version 3
12/13/2022
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 Pre-Window Plugged & Planned Wellbore Schematic ............................................................. 6
7.0 Drilling / Completion Summary ................................................................................................ 8
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 9
9.0 MIRU & Test BOPE ................................................................................................................ 11
10.0 Pull Tubing String, Cut & Pull 9-5/8” ..................................................................................... 13
11.0 Set Mechanical Plug, Set Whipstock, Mill 12-1/4” Window ................................................... 14
12.0 Drill 12-1/4” Hole Section ........................................................................................................ 17
13.0 Run 9-5/8” Casing .................................................................................................................... 20
14.0 Cement 9-5/8” Liner ................................................................................................................ 25
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 30
16.0 Run 6-5/8” Liner ...................................................................................................................... 35
17.0 Run Upper Completion / Post Rig Work ................................................................................ 39
18.0 Innovation Rig Diverter Schematic ......................................................................................... 42
19.0 Innovation Rig BOP Schematic – Big Bore Sidetrack ............................................................ 43
20.0 Wellhead Schematic ................................................................................................................. 44
21.0 Days Vs Depth .......................................................................................................................... 45
22.0 Formation Tops & Information............................................................................................... 46
23.0 Anticipated Drilling Hazards .................................................................................................. 47
24.0 Innovation Rig Layout ............................................................................................................. 51
25.0 FIT Procedure .......................................................................................................................... 52
26.0 Innovation Rig Choke Manifold Schematic ............................................................................ 53
27.0 Casing Design ........................................................................................................................... 54
28.0 8-1/2” Hole Section MASP ....................................................................................................... 55
29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
30.0 Surface Plat (As Built) ............................................................................................................. 57
Page 2
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU W-26B
Pad Prudhoe Bay W Pad
Planned Completion Type 4-1/2” Gas Lift
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 17,514’ MD / 4930’ TVD
PBTD, MD / TVD 17,514’ MD / 4930’ TVD
Surface Location (Governmental) 945' FNL, 1446' FEL, Sec 21, T11N, R12E, UM, AK
Surface Location (NAD 27) X= 611789.07, Y=5959308.01
Top of Productive Horizon
(Governmental)2546' FSL, 1342' FEL, Sec 17, T11N, R12E, UM, AK
TPH Location (NAD 27) X= 606553.3, Y= 5962723.15
BHL (Governmental) 727' FNL, 629' FEL, Sec 7, T11N, R12E, UM, AK
BHL (NAD 27) X= 601862, Y=5969945
AFE Number 221-00131
Maximum Anticipated Pressure
(Surface) 1677 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 2176 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 53.3 ft = 79.8 ft
Cellar Box Elevation above MSL: 53.3 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
W-26B 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
Surface 13-3/8” 12.415 12.259 14.375 68 L-80 BTC 5020 2260 1556
Intermediate
Casing 9-5/8” 8.681 8.525 10.396 47 L-80 VAMTOP 6870 4760 1086
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 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
W-26B SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Wyatt Rivard 907.777.8547 wrivard@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 mmayfield@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
6.0 Pre-Window Plugged & Planned Wellbore Schematic
Pre Window Reservior Plug and Pre Window W-26A Schematic
Page 7
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Proposed W-26B Schematic
Page 8
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
PBU W-26B is a sidetrack producer planned to be drilled in the Schrader Bluff OBd sands. W-26B is part of
a multi-well program targeting the Schrader Bluff sand on PBU W-pad
The parent bore, W-26A, is a LTSI well. W-26A reservoirs will be abandoned prior to the rigs arrival on the
well.
The directional plan is 12-1/4” intermediate hole and 9-5/8” casing string 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 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 December 10, 2022, pending rig schedule.
Intermediate casing will be run to 8,450’ MD / 4,935’ TVD, and cemented to surface.
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” BOPE
3. Pull 4-1/2” Tubing, cut & pull 9-5/8” casing
4. Set 13-3/8” mechanical plug
5. ND tubing spool. NU diverter spool.
6. Set 13-3/8” whipstock, mill 12-1/4” window
7. Drill 12-1/4” hole to TD
8. Run and cement 9-5/8” casing.
9. ND diverter spool. NU tubing spool.
10. Drill 8-1/2” lateral to well TD
11. Run 6-5/8” production liner
12. Run Upper Completion
13. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) GR + ADR
e Schrader Bluff OBd sands.
GR + Res
Intermediate casing will be run to 8,450’ MD /
Page 9
Prudhoe Bay West
W-26B 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 W-26B.
Ensure to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
No variances requested at this time.
Page 10
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”
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
250/3,000
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
Subsequent Tests:
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 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 11
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
9.0 MIRU & Test BOPE
9.1 W-26A will be the parent well for this side track. Ensure to review attached surface plat and
make sure rig is over appropriate well.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Level pad and ensure enough room for layout of rig footprint and R/U.
9.4 Rig mat footprint of rig.
9.5 MIRU Innovation. Ensure rig is centered over wellhead to prevent any wear to BOPE or
wellhead.
9.6 Mud loggers WILL NOT be used on either hole section.
9.7 Give AOGCC 24hr notice of BOPE test, for test witness.
9.8 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.
9.9 RU MPD RCD and related equipment
9.10 Run 5” BOP test plug
9.11 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 4-1/2” 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
9.12 RD BOP test equipment
9.13 Dump and clean mud pits, send spud mud to G&I pad for injection.
Page 12
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
9.14 Mix 9.5 spud mud for well work operations
9.15 Set wearbushing in wellhead.
9.16 If needed, rack back as much 5” DP in derrick as possible to be used while drilling future hole
section.
9.17 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 13
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
10.0 Pull Tubing String, Cut & Pull 9-5/8”
10.1 RU tubing handling equipment
x Tubing is 4-1/2”
x Tubing cut depth: ~4,500’, confirm with pre rig well work report
10.2 PU landing joint or spear and engage tubing hanger
10.3 Backout lock down screws
10.4 Pull tubing hanger with landing jointoxo to the rig floor, have appropriate protectors ready.
10.5 If necessary, circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a
soap sweep surface-to-surface to clean the tubing.
10.6 POOH laying down 4-1/2” tubing. RD tubing handling equipment
10.7 RU e-line. Run CBL to determine TOC in 9-5/8” annulus (12/14/2022 note: TOC logged at
1,475’ MD).
x Note: TOC estimated at 1,450’ MD after OA downsqueeze in 2004. The operator pumped
95 bbls of 15.7ppg Arctic Set cement followed by 85 bbls of crude.
10.8 MU Baker mechanical cutter, RIH to TOC and cut 9-5/8” casing at 1,410’ MD.
10.9 POOH and inspect mechanical cutter for wear. LD mechanical cutter
x If inspection indicates, RIH with backup cutter and repeat.
10.10 RU casing handing equipment
x Casing is 9-5/8” 47# L-80 NSCC
10.11 PU landing joint or spear and engage casing hanger
10.12 Back out lock down screws
10.13 Pull casing free
x If necessary, circulate at least 1.5x BU after pulling hanger to the floor. If desired, circulate a
sweep surface to surface to clean the tubing.
10.14 POOH laying down the 9-5/8” casing
10.15 RD casing handling equipment
Page 14
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
11.0 Set Mechanical Plug, Set Whipstock, Mill 12-1/4” Window
11.1 MU 13-3/8” casing scraper assembly and RIH to top of 9-5/8” cut
11.2 P/U 13-3/8” mechanical plug, RIH to set depth (TBD based on CBL results and CCL) & set
same
11.3 RU casing testing equipment and PT 13-3/8” casing to 2500 psi for 30 min, chart test. Ensure
rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001.
11.4 After obtaining a passing pressure test, ND tubing spool. NU diverter and test same.
DIVERTER DIAGRAM
(TBD based on CBL results
Page 15
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
11.5 Whipstock Set Depth Information
x Planned TOW: TBD based on CBL results, estimating TOW at 1,300’ +/-
x WS should be set to avoid a collar while milling the window
x Drilling Foreman, Whipstock hand and drilling engineer to agree on the set depth
11.6 MU 12-1/4” mill/whipstock assembly as per Baker Hughes tally
x MU HWDP, string magnets and float sub
x Ensure magnets are in trough, under shakers and flow area to capture metal shavings
circulated
11.7 Install MWD and orient. Rack back mill assembly
x Ensure a dedicated MWD is available for the orientation of the whipstock
11.8 Verify offset between WD, and the whipstock tray, witnessed by the Drilling Foreman,
MWD/DD and Baker Hughes rep. Document and record offset in well file.
11.13 Slowly run in the hole as per fishing Rep.
11.14 Run in hole at 1 ½ to 2 minutes per stand, or per contractor rep. Ensure work string is stationary
prior to setting the slips to avoid weakening the shear bolt and prematurely setting the anchor.
11.15 Shallow test MWD at first drill pipe fill up depth.
11.16 Stop at least 30-45’ above planned set depth, obtain survey with MWD.
11.17 Milling fluid will be 9.5 ppg spud mud
11.18 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string,
measure and record P/U and S/O weights. Obtain good survey to orient whipstock face.
11.19 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP
to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is
30q LOHS – Consult with milling hand
11.20 Whipstock Orientation Diagram:
45L
15L
TBD based on CBL results,
Page 16
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Desired orientation of the whipstock face is 15L to 45L, target is 30 LOHS
Hole Angle at window interval (@1,300’, 11.9° inc, 292° azi).
Sidetrack tangent section is 62q inclination and 296q azimuth
11.21 Once whipstock is in desired orientation, set WS per Baker Hughes rep.
11.22 CBU and confirm 9.5 ppg MW in/out
x Ensure Mud properties are sufficient for transporting metal cuttings
x Visc: 40-60, YP: 18-20
11.23 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight
and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps
as necessary.
11.24 If possible, install catch trays in shaker underflow chute to help catch metal cuttings.
11.25 Clean catch trays and ditch magnets frequently while milling window.
11.26 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window
as needed.
11.27 With upper mill at the end of the tray, this will drill ~ 20’ of new hole.
11.28 After window is milled but before POOH, shut down pumps and work milling assembly through
window watching for drag. Dress and polish window as needed. After reaming, shut off pumps
and rotary and dry drift window.
11.29 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud
properties for drilling.Note: FIT is NOT required.
11.30 POOH & LD milling BHA. Gauge mills for wear.
11.31 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris.
Page 17
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
12.0 Drill 12-1/4” Hole Section
12.1 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 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.
12.2 RIH with 12-1/4” BHA, to top of whipstock. Shallow test MWD at the first fill up point
12.3 Orient directional motor 30q left of highside and slide through window with no pumps or
rotary
x Confirm set orientation of whipstock, and have BHA match
12.4 Displace wellbore to 9.5 ppg spud mud
x 9.5 ppg due to hydrates, free gas and potential for Cretaceous over pressure (although none has
been see at W pad, be aware from 4500’ TVD and deeper)
12.5 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 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 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 over melting hydrates
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x 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.Wood has been observed across shakers during the
surface interval TVD.
x Gas hydrates are have been seen on W pad. 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.
y
around 1660’ TVD (Base of Perm) to 2740’ TVD (Top Ugnu) and below.
IGas hydrates are have been seen on W pad. yp
Page 18
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
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 Surface Hole AC, CF <1.0 :
x There are no wells with a CF less than 1.0
12.6 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. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Window - TD 9.5+ (For Hydrates/Free Gas based on offset
wells and cretaceous injection mitigation)
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. Maintain a
minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole
cleaning becomes an issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
MW for free gas and hydrates based upon offset wells
(
9.5+ (
y gg
barite or spike fluid will be on location to weight up the active system (1) ppg aboveg p y ( ) ppgp
highest anticipated MW.
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
System Type:8.8 – 9.8 ppg spud mud
Properties:
Section Density LSYP PV YP MPT API FL pH Temp
Surface 8.8 –9.8 4-6 15 - 30 25-45 <8 <10 8.5 –9.0 70 F
12.7 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
12.8 RIH to bottom, proceed to BROOH to window
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.
12.9 CBU x2 at the 13-3/8” shoe and clean casing with high visc sweeps
12.10 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 window for any higher than expected pressure seen
12.11 Orient BHA and pull through window with no pumps or rotary
12.12 TOOH and LD BHA
pp
Wellbore breathing has been seen on past MPU SB wells. P
h MPD.
y
8.8 –9.8
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
13.0 Run 9-5/8” Casing
13.15 Install 9-5/8” solid body casing rams in the upper ram cavity. RU testing equipment. PT to
250/3,000 psi with 7” test joint. RD testing equipment.
13.15 R/U 9-5/8” liner running equipment (CRT & Tongs)
x Ensure 9-5/8” VAMTOP x NC50 XO on rig floor and M/U to FOSV.
x Use compatible 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 8.5” on the location prior to running.
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.
13.15 P/U shoe joint, visually verify no debris inside joint.
13.15 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint –9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” TXP, 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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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
13.15 Float equipment and Stage tool equipment drawings:
13.15 Continue running 9-5/8” liner
x Fill casing while running using fill up line on rig floor.
x Use compatible thread compound. Dope pin end only w/ paint brush.
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Drilling Procedure
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.
9-5/8” 47# L-80 VAMTOP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”14,440 ft-lbs 15,900 ft-lbs 17,400 ft-lbs
13.15 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the 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.
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Drilling Procedure
13.6 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.
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Drilling Procedure
13.13 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
13.14 Slow in and out of slips.
13.15 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.
13.16 Lower casing to setting depth. Confirm measurements.
13.17 Have slips staged in cellar, along with necessary equipment for the operation.
13.18 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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Prudhoe Bay West
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Drilling Procedure
14.0 Cement 9-5/8” Liner
14.1 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.
14.2 Document efficiency of all possible displacement pumps prior to cement job.
14.3 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.
14.4 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.
14.5 Fill surface cement lines with water and pressure test.
14.6 Cement job will be a two stage job with TOC to surface.
14.7 Pump remaining 60 bbls 10.5 ppg tuned spacer.
14.8 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.
14.9 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated Total Cement Volume:
Cement job will be a two stage job with TOC to surface.
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Prudhoe Bay West
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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
14.10 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.
14.11 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.
14.12 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
14.13 Displacement calculation is in step 14.9 above.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES
cementer is tuned spacer to minimize the risk of flash setting cement
14.14 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.
14.15 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. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool.
14.16 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.
14.17 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
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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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
14.18 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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Prudhoe Bay West
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Drilling Procedure
Second Stage Surface Cement Job:
14.19 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.
14.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
14.21 Fill surface lines with water and pressure test.
14.22 Pump remaining 60 bbls 10.5 ppg tuned spacer.
14.23 Mix and pump cmt per below recipe for the 2
nd stage.
14.24 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
14.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
14.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
mgr
p
Job will consist of lead & tail, TOC brought to surface.
367108.3
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
14.27 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.
14.28 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.
14.29 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.
14.30 ND diverter. If necessary, set casing slips. NU tubing spool. NU BOPE and test same.
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.
Assure casing starting head is clear of cement for 9-5/8"slips and packoff assy.mgr
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum
required to drill ahead
x 9.8 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP)
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a ported float in the production hole section.
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Prudhoe Bay West
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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 <1008.9-9.5
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Prudhoe Bay West
W-26B SB Producer
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
15.15 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 ftomin, 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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Prudhoe Bay West
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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 a CF < 1.0
15.16 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.
15.17 At TD, CBU at least 4 times at 200 ftomin 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
15.18 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.
15.19 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (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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W-26B SB Producer
Drilling Procedure
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.20 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
15.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.23 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
15.24 POOH and LD BHA.
15.25 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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Prudhoe Bay West
W-26B SB Producer
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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W-26B SB Producer
Drilling Procedure
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Prudhoe Bay West
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Drilling Procedure
16.5 Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for gas lift
completion. Tentative liner set depth ~ 8,380’ 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.
16.6 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.
16.7 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.
16.8 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
16.9 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.
16.10 RIH with liner no faster than 30 ftomin – 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
16.11 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.
16.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15 Rig up to pump down the work string with the rig pumps.
8300'MD
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Prudhoe Bay West
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Drilling Procedure
16.16 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
16.17 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.
16.18 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.
16.19 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.
16.20 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.
16.21 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22 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.
16.23 PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24 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 39
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
17.0 Run Upper Completion / Post Rig Work
17.1 RU to run 4-1/2”, 12.6#, L-80 VAMTOP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6# VAMTOP 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.
17.2 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 4x GLM
x 1x X Nipple
x 1x Production Packer
i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval.
x 1x X Nipple
x XXX joints, 4-1/2”, 12.6#, L-80, VAMTOP
Page 40
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Draft Upper Completion Tally
Page 41
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
17.3 PU and MU the 4-1/2” tubing hanger with XO.
17.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
17.5 Land the tubing hanger and RILDS. Lay down the landing joint.
17.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
17.7 NU the tubing head adapter and NU the tree.
17.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
17.9 Pull the plug off tool and BPV.
17.10 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.
17.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
17.12 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.
17.13 Bleed both the IA and tubing to 0 psi.
17.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
17.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
17.16 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
Page 42
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
18.0 Innovation Rig Diverter Schematic
Page 43
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
19.0 Innovation Rig BOP Schematic – Big Bore Sidetrack
Page 44
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
20.0 Wellhead Schematic
Page 45
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
21.0 Days Vs Depth
Page 46
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
22.0 Formation Tops & Information
TOP
NAME
MD
(FT)
TVD
(FT)
TVDSS
(FT)
Formation
Pressure
(psi)
EMW
(ppg)
SV1 3,947 2,987 2,907 1,314 8.46
UG4 4,695 3,371 3,291 1,483 8.46
UG_MB 6,860 4,483 4,403 1,972 8.46
SB NB 7,276 4,682 4,602 2,060 8.46
SB OA 7,686 4,812 4,732 2,117 8.46
SB OBd 8,759 4,953 4,873 2,179 8.46
Page 47
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
23.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have been seen on PBU W Pad. Be prepared for them. They have been reported between
1800’ 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.
Cretaceous Over Pressure:
W-Pad does not have a history of over-pressure in the cretaceous interval (4500-5300’ TVD). However,
as a precaution ensure MW is above 9.0. Be prepared while drilling this interval.
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
yp (
n ensure MW is above 9.0. Be prepared while drilling this interval.
y
Gas hydrates have been seen on PBU W Pad.
Page 48
Prudhoe Bay West
W-26B SB Producer
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. Stuck pipe,
wood chunks over shakers and other hole stability issues are specific to W pad. Be prepared and review
Pad Data Sheet. Bad see pad data sheet
H2S:
Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 49
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 50
Prudhoe Bay West
W-26B 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 51
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
24.0 Innovation Rig Layout
Page 52
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
25.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 53
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
26.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
27.0 Casing Design
Page 55
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
28.0 8-1/2” Hole Section MASP
Page 56
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
29.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
30.0 Surface Plat (As Built)
Page 58
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Pad Map For SHL Visual Reference
6WDQGDUG3URSRVDO5HSRUW
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090018002700360045005400True Vertical Depth (1800 usft/in)0 900 1800 2700 3600 4500 5400 6300 7200 8100 9000 9900 10800 11700 12600 13500 14400 15300 16200 17100 18000Vertical Section at 318.00° (1800 usft/in)W-240 wp03 SB-tgtW-240 wp02 CP2W-240 wp02 CP3W-240 wp02 CP4W-240 wp02 CP5W-240 wp02 CP6W-26B wp02 CP1500100015002000250030003500400045005000550060006500700075008000W-268000W-26A13 3/8" TOW9 5/8" x 12 1/4"6 5/8" x 8 1/2"1500200025003000350040004500500055006000650070007500800085009000950010000105001100011500120001250013000135001400014500150001550016000165001700017514W-26B wp05KOP : Start Dir 9.88º/100' : 1299.6' MD, 1296.97'TVD : 30° LT TFEnd Dir : 1324' MD, 1320.76' TVDStart Dir 4º/100' : 1344' MD, 1340.16'TVDEnd Dir : 2493.91' MD, 2240.74' TVDStart Dir 4º/100' : 7037.49' MD, 4573.64'TVDEnd Dir : 7378.3' MD, 4717.71' TVDStart Dir 2.5º/100' : 7519.66' MD, 4762.77'TVDEnd Dir : 8294.28' MD, 4921.49' TVDStart Dir 2.5º/100' : 8394.28' MD, 4930.21'TVDEnd Dir : 9009.04' MD, 4957.37' TVDStart Dir 2.5º/100' : 13096.17' MD, 4960.12'TVDStart Dir 2º/100' : 13366.37' MD, 4960.21'TVDEnd Dir : 13380.4' MD, 4960.18' TVDStart Dir 2º/100' : 15414.93' MD, 4950.21'TVDEnd Dir : 15988.8' MD, 4946.06' TVDStart Dir 2.5º/100' : 16603.83' MD, 4940.21'TVDEnd Dir : 17160.86' MD, 4934.31' TVDSV1Ugnu 4AUG3Ugnu MBNBOAOBdHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Rig: W-26Ground Level: 53.26+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005959308.010611789.07070° 17' 52.0241 N 149° 5' 40.9357 WSURVEY PROGRAMDate: 2022-11-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool37.30 1299.60 W-26 Srvy 1 GCT MS (W-26) 3_Gyro-CT_pre-1998_Csg1299.60 1700.00 W-26B wp05 (W-26B) 3_MWD_Interp Azi+Sag1700.00 8450.00 W-26B wp05 (W-26B) 3_MWD+IFR2+MS+Sag8450.00 17514.02 W-26B wp05 (W-26B) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation2986.76 2906.55 3946.87 SV13370.76 3290.55 4694.75 Ugnu 4A3693.76 3613.55 5323.83 UG34482.76 4402.55 6860.49 Ugnu MB4681.76 4601.55 7276.22 NB4811.76 4731.55 7685.63 OA4952.76 4872.55 8759.15 OBdREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: W-26, True NorthVertical (TVD) Reference:W-26B Actual RKB @ 80.21usftMeasured Depth Reference:W-26B Actual RKB @ 80.21usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:WWell:Rig: W-26Wellbore:W-26BDesign:W-26B wp05CASING DETAILSTVD TVDSS MD SizeName1296.98 1216.77 1299.61 13-3/8 13 3/8" TOW4934.85 4854.64 8450.00 9-5/8 9 5/8" x 12 1/4"4930.21 4850.00 17514.48 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 1299.60 11.85 292.41 1296.97 2.10 -40.82 0.00 0.00 28.87 KOP : Start Dir 9.88º/100' : 1299.6' MD, 1296.97'TVD : 30° LT TF2 1324.00 13.99 287.42 1320.76 3.93 -45.95 9.88 -30.00 33.67 End Dir : 1324' MD, 1320.76' TVD3 1344.00 13.99 287.42 1340.16 5.38 -50.56 0.00 0.00 37.83 Start Dir 4º/100' : 1344' MD, 1340.16'TVD4 1544.00 21.99 287.42 1530.23 23.86 -109.45 4.00 0.00 90.975 2493.91 59.11 301.28 2240.74 298.86 -647.32 4.00 19.51 655.24 End Dir : 2493.91' MD, 2240.74' TVD6 7037.49 59.11 301.28 4573.64 2323.25 -3979.51 0.00 0.00 4389.32 Start Dir 4º/100' : 7037.49' MD, 4573.64'TVD7 7217.94 65.00 306.00 4658.21 2411.63 -4112.01 4.00 36.41 4543.66 W-240 wp03 SB-tgt8 7378.30 71.41 305.86 4717.71 2498.95 -4232.51 4.00 -1.15 4689.19 End Dir : 7378.3' MD, 4717.71' TVD9 7519.66 71.41 305.86 4762.77 2577.45 -4341.10 0.00 0.00 4820.18 Start Dir 2.5º/100' : 7519.66' MD, 4762.77'TVD10 8294.28 85.00 320.00 4921.49 3093.01 -4891.87 2.50 47.20 5571.86 End Dir : 8294.28' MD, 4921.49' TVD11 8394.28 85.00 320.00 4930.21 3169.33 -4955.90 0.00 0.00 5671.42 W-26B wp02 CP1 Start Dir 2.5º/100' : 8394.28' MD, 4930.21'TVD12 9009.04 89.96 334.56 4957.37 3684.58 -5286.73 2.50 71.59 6275.69 End Dir : 9009.04' MD, 4957.37' TVD13 13096.17 89.96 334.56 4960.12 7375.55 -7042.11 0.00 0.00 10193.19 Start Dir 2.5º/100' : 13096.17' MD, 4960.12'TVD14 13366.37 90.00 327.81 4960.21 7612.17 -7172.26 2.50 -89.67 10456.12 W-240 wp02 CP3 Start Dir 2º/100' : 13366.37' MD, 4960.21'TVD15 13380.40 90.28 327.81 4960.18 7624.04 -7179.73 2.00 -0.78 10469.95 End Dir : 13380.4' MD, 4960.18' TVD16 15414.93 90.28 327.81 4950.21 9345.74 -8263.68 0.00 0.00 12474.72 W-240 wp02 CP4 Start Dir 2º/100' : 15414.93' MD, 4950.21'TVD17 15988.80 90.55 316.33 4946.06 9797.61 -8615.85 2.00 -88.64 13046.17 End Dir : 15988.8' MD, 4946.06' TVD18 16603.83 90.55 316.33 4940.21 10242.47 -9040.50 0.00 0.00 13660.91 W-240 wp02 CP5 Start Dir 2.5º/100' : 16603.83' MD, 4940.21'TVD19 17160.86 90.66 302.41 4934.31 10594.91 -9470.04 2.50 -89.44 14210.25 End Dir : 17160.86' MD, 4934.31' TVD20 17514.48 90.66 302.41 4930.21 10784.41 -9768.58 0.00 0.00 14550.83 W-240 wp02 CP6 Total Depth : 17514.48' MD, 4930.21' TVD
-1500
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
South(-)/North(+) (1500 usft/in)-9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0
West(-)/East(+) (1500 usft/in)
W-26B wp02 CP1
W-240 wp02 CP6
W-240 wp02 CP5
W-240 wp02 CP4
W-240 wp02 CP3
W-240 wp02 CP2
W-240 wp03 SB-tgt
1500225025002750300032503500375040004 5 0 050005500
6 0 0 0
6 5 0 0
6 7 5 0
7 2 5 0
7 7 5 0
8 2 5 0
8 7 5 0 9 0 0 0
9 1 7 6
W -2 6
775082508 7 5 0
W-26A
8934W-26AL113 3/8" TOW
9 5/8" x 12 1/4"
6 5/8" x 8 1/2"275030003250350037504000425045004930W-26B wp05
KOP : Start Dir 9.88º/100' : 1299.6' MD, 1296.97'TVD : 30° LT TF
End Dir : 1324' MD, 1320.76' TVD
Start Dir 4º/100' : 1344' MD, 1340.16'TVD
End Dir : 2493.91' MD, 2240.74' TVD
Start Dir 4º/100' : 7037.49' MD, 4573.64'TVD
End Dir : 7378.3' MD, 4717.71' TVD
Start Dir 2.5º/100' : 7519.66' MD, 4762.77'TVD
End Dir : 8294.28' MD, 4921.49' TVD
Start Dir 2.5º/100' : 8394.28' MD, 4930.21'TVD
End Dir : 9009.04' MD, 4957.37' TVD
Start Dir 2.5º/100' : 13096.17' MD, 4960.12'TVD
Start Dir 2º/100' : 13366.37' MD, 4960.21'TVD
End Dir : 13380.4' MD, 4960.18' TVD
Start Dir 2º/100' : 15414.93' MD, 4950.21'TVD
End Dir : 15988.8' MD, 4946.06' TVD
Start Dir 2.5º/100' : 16603.83' MD, 4940.21'TVD
End Dir : 17160.86' MD, 4934.31' TVD
CASING DETAILS
TVD TVDSS MD Size Name
1296.98 1216.77 1299.61 13-3/8 13 3/8" TOW
4934.85 4854.64 8450.00 9-5/8 9 5/8" x 12 1/4"
4930.21 4850.00 17514.48 6-5/8 6 5/8" x 8 1/2"
Project: Prudhoe Bay
Site: W
Well: Rig: W-26
Wellbore: W-26B
Plan: W-26B wp05
WELL DETAILS: Rig: W-26
Ground Level: 53.26
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
5959308.010 611789.070 70° 17' 52.0241 N 149° 5' 40.9357 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Rig: W-26, True North
Vertical (TVD) Reference:W-26B Actual RKB @ 80.21usft
Measured Depth Reference:W-26B Actual RKB @ 80.21usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000 8400 8800Measured Depth (800 usft/in)W-241 wp05W-26W-26AW-26AL1W-59No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Rig: W-26 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 53.26+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959308.010611789.07070° 17' 52.0241 N149° 5' 40.9357 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: W-26, True NorthVertical (TVD) Reference: W-26B Actual RKB @ 80.21usftMeasured Depth Reference:W-26B Actual RKB @ 80.21usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-11-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool37.30 1299.60 W-26 Srvy 1 GCT MS (W-26) 3_Gyro-CT_pre-1998_Csg1299.60 1700.00 W-26B wp05 (W-26B) 3_MWD_Interp Azi+Sag1700.00 8450.00 W-26B wp05 (W-26B) 3_MWD+IFR2+MS+Sag8450.00 17514.02 W-26B wp05 (W-26B) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000 8400 8800Measured Depth (800 usft/in)W-25W-27W-29W-31W-211W-30W-59GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference1299.60 To 17514.48Project: Prudhoe BaySite: WWell: Rig: W-26Wellbore: W-26BPlan: W-26B wp05Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name1296.98 1216.77 1299.61 13-3/8 13 3/8" TOW4934.85 4854.64 8450.00 9-5/8 9 5/8" x 12 1/4"4930.21 4850.00 17514.48 6-5/8 6 5/8" x 8 1/2"
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0.001.002.003.004.00Separation Factor8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725 15200 15675 16150 16625 17100 17575Measured Depth (950 usft/in)W-241 wp05Z-223Z-229Z-222Z-116Z-228Z-220Z-221No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Rig: W-26 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 53.26+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959308.010611789.07070° 17' 52.0241 N149° 5' 40.9357 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: W-26, True NorthVertical (TVD) Reference: W-26B Actual RKB @ 80.21usftMeasured Depth Reference:W-26B Actual RKB @ 80.21usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-11-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool37.30 1299.60 W-26 Srvy 1 GCT MS (W-26) 3_Gyro-CT_pre-1998_Csg1299.60 1700.00 W-26B wp05 (W-26B) 3_MWD_Interp Azi+Sag1700.00 8450.00 W-26B wp05 (W-26B) 3_MWD+IFR2+MS+Sag8450.00 17514.02 W-26B wp05 (W-26B) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725 15200 15675 16150 16625 17100 17575Measured Depth (950 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference1299.60 To 17514.48Project: Prudhoe BaySite: WWell: Rig: W-26Wellbore: W-26BPlan: W-26B wp05Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name1296.98 1216.77 1299.61 13-3/8 13 3/8" TOW4934.85 4854.64 8450.00 9-5/8 9 5/8" x 12 1/4"4930.21 4850.00 17514.48 6-5/8 6 5/8" x 8 1/2"
From:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Date:Wednesday, December 14, 2022 10:07:55 AM
From: Rixse, Melvin G (OGC)
Sent: Wednesday, December 14, 2022 8:56 AM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Nathan,
Hilcorp has AOGCC approval to proceed as you described below by setting a mechanical plug at
~1300’ MD then drilling 12-1/4” OH, followed by fully cementing the 9-5/8” casing to surface.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake
in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Wednesday, December 14, 2022 8:51 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
SL tagged TOC in the 4-1/2” tubing at 4,700’ MD. The estimated TOC inside and outside the 4-1/2”
was 5,000’ MD.
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
O: 907-777-8450
C: 907-301-8996
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: Rixse, Melvin G (OGC) [mailto:melvin.rixse@alaska.gov]
Sent: Wednesday, December 14, 2022 8:46 AM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Nathan,
What was the last TOC tagged prior to cutting and pulling tubing and what is the estimated TOC
in the old 4-1/2” X 9-5/8” annulus?
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake
in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Wednesday, December 14, 2022 7:15 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Good morning Mel,
We ran the CBL yesterday evening and discovered TOC outside the 9-5/8” at 1,475’ ELMD. We made
a mechanical cut at 1,410’ MD and were able to circulate the annulus clean. We are in the process
of swapping rams to begin pulling the 9-5/8” casing. We also have the cut we made yesterday at
2,871’.
There is a step in the original PTD to set a cement retainer and squeeze 150’ of cement below and
leave ~50’ of cement above it. The retainer was to be set at ~2,850’ MD. The well is jug tight. We
won’t be able to squeeze any cement. We will need to set a mechanical plug as a base for our
whipstock (roughly at 1,300’).
Given that we have already abandoned the reservoir, have a passing MIT, will set a plug, and will be
fully cementing our 9-5/8” casing to surface, can we remove this step to leave ~200’ of cement in
the parent bore at the KOP?
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Regards,
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
O: 907-777-8450
C: 907-301-8996
From: Rixse, Melvin G (OGC) [mailto:melvin.rixse@alaska.gov]
Sent: Tuesday, December 13, 2022 4:11 PM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Nathan,
Thanks.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake
in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Tuesday, December 13, 2022 3:54 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; McLellan, Bryan J (OGC)
<bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Understood. We are running the CBL tonight and that will dictate the final directional. We will get
an updated procedure over to you first thing tomorrow morning.
We will proceed with cased hole work tonight but will not mill a window until we have 10-403
approval.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Regards,
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
O: 907-777-8450
C: 907-301-8996
From: Rixse, Melvin G (OGC) [mailto:melvin.rixse@alaska.gov]
Sent: Tuesday, December 13, 2022 12:01 PM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Joseph Lastufka <joseph.lastufka@hilcorp.com>; McLellan, Bryan J (OGC)
<bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Nathan,
AOGCC has no confidence that permafrost will not melt and the FIT will change while drilling 12-
1/4” OH.
Plan on treating your 13-3/8” as a deep set conductor. Plan to nipple up a diverter.
I believe a break in containment after drilling cementing the 9-5/8” would be manageable with
proper monitoring and controls.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake
in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Joe Lastufka, Bryan McLellan
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Tuesday, December 13, 2022 10:00 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Importance: High
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Mel,
Thank you for the quick response.
Due to the fact that we have a full wellhead (casing head, tubing spool), we don’t currently have the
space available to rig up the diverter spool. We are currently taking measurements to determine if
nippling down the tubing spool would give us enough room to fit the diverter stack. This would
require us to ND the tubing spool and then NU the tubing spool after cementing the 9-5/8” casing.
Alternatively, would it be acceptable to leave the BOPE installed as is (no knife valve / diverter line)
and to attempt an FIT? We would need a 12.3ppg for 15 bbls KT. I am aware of one shallow FIT
from the prior operator on PBW L-pad where they achieved a 12.9ppg FIT at 989’ TVD. A 12.9ppg
would provide 21 bbls KT on W-26B. We also have MPD available to us and would propose a
dynamic kill method only if unable to achieve the required FIT.
Regards,
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
O: 907-777-8450
C: 907-301-8996
From: Rixse, Melvin G (OGC) [mailto:melvin.rixse@alaska.gov]
Sent: Tuesday, December 13, 2022 9:17 AM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Joseph Lastufka <joseph.lastufka@hilcorp.com>
Subject: [EXTERNAL] RE: PTD 222-151 Hilcorp Well W-26B
Nathan,
Preliminary discussion here is that AOGCC would treat 13-3/8” casing as a deep set conductor.
Drill 12-1/4” hole on diverter with no required FIT.
Fully cement 9-5/8” to TOL (or carry 9-5/8” to surface alternately)
More to come.
AOGCC would require a 10-403 with change to approved program.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake
in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Joe Lastufka, Bryan McLellan
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Tuesday, December 13, 2022 9:10 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: PTD 222-151 Hilcorp Well W-26B
Mel,
I’m covering I-rig operations for Joe Engel (PTO).
We found a record of a cement downsqueeze in 2004. They pumped 95 bbls of 15.7ppg ArcticSet
cement and displaced with 85 bbls of crude. “Estimated TOC at 1450’ MD”. They performed a
passing MIT-OA to 2400 psi on 12/4/2004.
I’m proposing a path forward (roughly – still working details) as follows:
Run CBL to determine TOC.
Cut and pull 9-5/8” casing from cut (assuming ~1400’ MD).
Set 13-3/8” WS and perform sidetrack.
The primary change is that we’d be sidetracking in the permafrost. As discussed, we could attempt
an FIT after milling the window and will run a few KT scenarios here momentarily to determine what
FIT values we’d need. That being said, we normally drill this interval on diverter.
If you are generally okay with the plan forward, we will work on a new PTD application and will send
it over ASAP.
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
O: 907-777-8450
C: 907-301-8996
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
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immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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 Myers
Drilling Manager
Hilcorp North Slope Alaska, LLC
3800 CenterPoint Drive, Suite 1400
Anchorage Alaska 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU W-26B
Hilcorp North Slope, LLC
Permit to Drill Number: 222-151
Surface Location: 945' FNL, 1446' FEL, Sec. 21, T11N, R12E, UM, AK
Bottomhole Location: 727' FNL, 629' FEL, Sec. 07, T11N, R12E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Obtain gamma ray and resistivity logs in the 12-1/4" section of this well and submit them for AOGCC
review prior to cementing9-5/8" casing in order to determine the appropriate depth for top of cement.
(See20 AAC 25.030(d)(5).)
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 L. Chmielowski
Commissioner
DATED this ___ day of December, 2022. 9
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2022.12.09
16:03:45 -09'00'
1a.
Contact Name:Joe Engel
Contact Email:jengel@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8395
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
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 5
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 W-26B
TVD:17611'4930'
12. Field/Pool(s):
PRUDHOE BAY, PRUDHOE OILMD:
ADL 028263, 028262 & 047450
85-008 December 10, 2022
4a.
Surface:
Top of Productive Horizon:
Total Depth:
945' FNL, 1446' FEL, Sec. 21, T11N, R12E, UM, AK
2546' FSL, 1342' FEL, Sec. 17, T11N, R12E, UM, AK
Kickoff Depth:2750 feet
Maximum Hole Angle: 91 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:2176 1677
17.Deviated wells:16.
Surface: x-y- Zone -611789 5959308 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
81.85
53.26
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
4920'
19.PRESENT WELL CONDITION SUMMARY
Liner
80
12620 8863 12229 12229 8902 None
31 - 111
Surface 4399 cu ft Coldset II
8825 - 8935
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):
47#
2982
11150 - 11293
50-029-21964-02-00
28 - 7984
280 cu ft Class G
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
2398 cu ft Class G
727' FNL, 629' FEL, Sec. 07, T11N, R12E, UM, AK
Time v. Depth Plot555 5Drilling Program
13766
(To be completed for Redrill and Re-Entry Operations)
20"
13-3/8"
9-5/8"
VamTop
7956
1833 8497 - 8864
8-1/2"
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.
7509
275
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
6-5/8" 20#L-80 VamTop 9230' 8380'17610'4930'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
31 - 111
30 - 3012 30 - 2692
3162 7"662 cu ft Class G 7801 - 10963 6078 - 8661
Liner 4-1/2"10787 - 12620
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
28 - 6213
Cement Volume
Comm.
8530'4933'Stg 1 L - 526 sx / T - 393 sx12-1/4"9-5/8"L-80 8530'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
11.29.2022
By Anne Prysunka at 9:00 am, Nov 29, 2022
Schrader Bluff Oil Pool, Orion
Development Area SFD
DSR-12/8/22MGR08DEC2022
* LWD 12-1/4" gamma ray/resistivity log to AOGCC for
review prior to cementing 9-5/8" casing to determine deepest
minimum depth for TOC.
222-151
SFD 12/8/2022
*BOPE test to 3000 psi. Annular to 2500 psi.
1677
GCW 12/09/22
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2022.12.09 16:04:06 -09'00'
Prudhoe Bay West
(PBU) W-26B
Drilling Permit
Version 1
11/22/2022
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 Pre-Window Plugged & Planned Wellbore Schematic ............................................................. 6
7.0 Drilling / Completion Summary ................................................................................................ 8
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 9
9.0 MIRU & Test BOPE ................................................................................................................ 11
10.0 Pull Tubing String, Cut & Pull 9-5/8” ..................................................................................... 13
11.0 Set Retainer, Cement, Set Whipstock, Mill 12-1/4” Window ................................................. 14
12.0 Drill 12-1/4” Hole Section ........................................................................................................ 17
13.0 Run 9-5/8” Liner ...................................................................................................................... 20
14.0 Cement 9-5/8” Liner ................................................................................................................ 23
15.0 Run 9-5/8” Tieback .................................................................................................................. 26
16.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
17.0 Run 6-5/8” Liner ...................................................................................................................... 33
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 37
19.0 Innovation Rig Diverter Schematic ......................................................................................... 40
20.0 Innovation Rig BOP Schematic ............................................................................................... 41
21.0 Wellhead Schematic ................................................................................................................. 42
22.0 Days Vs Depth .......................................................................................................................... 43
23.0 Formation Tops & Information............................................................................................... 44
24.0 Anticipated Drilling Hazards .................................................................................................. 45
25.0 Innovation Rig Layout ............................................................................................................. 49
26.0 FIT Procedure .......................................................................................................................... 50
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 51
28.0 Casing Design ........................................................................................................................... 52
29.0 8-1/2” Hole Section MASP ....................................................................................................... 53
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 54
31.0 Surface Plat (As Built) ............................................................................................................. 55
Page 2
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU W-26B
Pad Prudhoe Bay W Pad
Planned Completion Type 4-1/2” Gas Lift
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 17,610’ MD / 4929’ TVD
PBTD, MD / TVD 17600’ MD / 4929’ TVD
Surface Location (Governmental) 945' FNL, 1446' FEL, Sec 21, T11N, R12E, UM, AK
Surface Location (NAD 27) X= 611789.07, Y=5959308.01
Top of Productive Horizon
(Governmental)2546' FSL, 1342' FEL, Sec 17, T11N, R12E, UM, AK
TPH Location (NAD 27) X= 606553.3, Y= 5962723.15
BHL (Governmental) 727' FNL, 629' FEL, Sec 7, T11N, R12E, UM, AK
BHL (NAD 27) X= 601862, Y=5969945
AFE Number 221-00131
Maximum Anticipated Pressure
(Surface) 1677 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 2176 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 53.3 ft = 79.8 ft
Cellar Box Elevation above MSL: 53.3 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Schrader Bluff OBd Sand
Page 3
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
W-26B 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
Surface 13-3/8” 12.415 12.259 14.375 68 L-80 BTC 5020 2260 1556
Intermediate
Liner 9-5/8” 8.681 8.525 10.396 47 L-80 VAMTOP 6870 4760 1086
Tieback 9-5/8” 8.681 8.525 10.396 47 L-80 VAMTOP 6870 4760 1086
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
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
W-26B SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Wyatt Rivard 907.777.8547 wrivard@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 mmayfield@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
6.0 Pre-Window Plugged & Planned Wellbore Schematic
Pre Window Reservior Plug and Pre Window W-26A Schematic
Page 7
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Proposed W-26B Schematic
Page 8
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
PBU W-26B is a sidetrack producer planned to be drilled in the Schrader Bluff OBd sands. W-26B is part of
a multi-well program targeting the Schrader Bluff sand on PBU W-pad
The parent bore, W-26A, is a LTSI well. W-26A reservoirs will be abandoned prior to the rigs arrival on the
well.
The directional plan is 12-1/4” intermediate hole and 9-5/8” liner set into the top of the Schrader Bluff OBd
sand. A 9-5/8” tieback will be ran. 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 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 December 10, 2022, pending rig schedule.
Intermediate liner will be run to 8,530’ MD / 4933’ TVD, and cemented to above the Ugnu sand.
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” BOPE
3. Pull 4-1/2” Tubing, cut & pull 9-5/8” casing
4. Set 13-3/8” cement retainer & cement, set 13-3/8” whipstock, mill 12-1/4” window & FIT
5. Drill 12-1/4” hole to TD
6. Run and cement 9-5/8” liner, run tieback
7. Drill 8-1/2” lateral to well TD
8. Run 6-5/8” production liner
9. Run Upper Completion
10. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
e Schrader Bluff OBd sands.
See Conditions of Approval in
cover letter and on 401 form.
SFD 12/8/2022
Page 9
Prudhoe Bay West
W-26B 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 W-26B.
Ensure to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
No variances requested at this time.
Page 10
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”
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
250/3,000
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
Subsequent Tests:
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 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 11
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
9.0 MIRU & Test BOPE
9.1 W-26A will be the parent well for this side track. Ensure to review attached surface plat and
make sure rig is over appropriate well.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Level pad and ensure enough room for layout of rig footprint and R/U.
9.4 Rig mat footprint of rig.
9.5 MIRU Innovation. Ensure rig is centered over wellhead to prevent any wear to BOPE or
wellhead.
9.6 Mud loggers WILL NOT be used on either hole section.
9.7 Give AOGCC 24hr notice of BOPE test, for test witness.
9.8 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
9.9 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.
9.10 RU MPD RCD and related equipment
9.11 Run 5” BOP test plug
9.12 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 4-1/2” 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
9.13 RD BOP test equipment
Install BPV. ND tree and THA.
Page 12
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
9.14 Dump and clean mud pits, send spud mud to G&I pad for injection.
9.15 Mix 9.5 LSND for well work operations
9.16 Set wearbushing in wellhead.
9.17 If needed, rack back as much 5” DP in derrick as possible to be used while drilling future hole
section.
9.18 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 13
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
10.0 Pull Tubing String, Cut & Pull 9-5/8”
10.1 RU tubing handling equipment
x Tubing is 4-1/2”
x Tubing cut depth: ~4,500’, confirm with pre rig well work report
10.2 PU landing joint or spear and engage tubing hanger
10.3 Backout lock down screws
10.4 Pull tubing hanger with landing joint/xo to the rig floor, have appropriate protectors ready.
10.5 If necessary, circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a
soap sweep surface-to-surface to clean the tubing.
10.6 POOH laying down 4-1/2” tubing. RD tubing handling equipment
10.7 MU Baker mechanical cutter, RIH t/ ~ 2,871’ MD and cut 9-5/8” casing
x Planned cut depth is ~ 150’ inside the 13-3/8” surface casing shoe
10.8 POOH and inspect mechanical cutter for wear. LD mechanical cutter
x If inspection indicates, RIH with backup cutter and repeat.
10.9 RU casing handing equipment
x Casing is 9-5/8” 47# L-80 NSCC
10.10 PU landing joint or spear and engage casing hanger
10.11 Back out lock down screws
10.12 Pull casing free
x If necessary, circulate at least 1.5x BU after pulling hanger to the floor. If desired, circulate a
sweep surface to surface to clean the tubing.
10.13 POOH laying down the 9-5/8” casing
10.14 RD casing handling equipment
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
11.0 Set Retainer, Cement, Set Whipstock, Mill 12-1/4” Window
11.1 MU 13-3/8” casing scraper assembly and RIH to top of 9-5/8” cut
11.2 P/U 13-3/8” Cement Retainer, RIH t/ ~2,850’ MD & set same
11.3 Sting into cement retainer and pump ~ XXX bbl cement
x Plan is 150’ of 13-3/8” cement below cement retainer
11.4 Unsting from cement retainer and pump XXX bbl of cement on top of retainer
x Plan is ~ 50’ of 13-3/8” cement above cement retainer
11.5 POOH above TOC, CBU and high rate to clear cement from DP
11.6 POOH racking back DP
11.7 Once cement has reached sufficient compressive strength, MU Cleanout/Mill BHa and RIH to
tag TOC and dress off for future window depth of ~2750’ MD.
x At the time of the PTD submission, 13-3/8” run tally has not been located. To determine
casing collar location, a CCL will be needed
x Ensure future whipstock and window will not be set in a collar of the 13-3/8”
11.8 RU casing testing equipment and PT 13-3/8” casing t/ 2500 psi for 30 min, chart test. Ensure
rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001.
11.9 Whipstock Set Depth Information
x Planned TOW: ~2750’ MD
x WS should be set to avoid a collar while milling the window
x Drilling Foreman, Whipstock hand and drilling engineer to agree on the set depth
11.10 MU 12-1/4” mill/whipstock assembly as per Baker Hughes tally
x MU HWDP, string magnets and float sub
x Ensure magnets are in trough, under shakers and flow area to capture metal shavings
circulated
11.11 Install MWD and orient. Rack back mill assembly
x Ensure a dedicated MWD is available for the orientation of the whipstock
11.12 Verify offset between WD, and the whipstock tray, witnessed by the Drilling Foreman,
MWD/DD and Baker Hughes rep. Document and record offset in well file.
11.13 Slowly run in the hole as per fishing Rep.
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
11.14 Run in hole at 1 ½ to 2 minutes per stand, or per contractor rep. Ensure work string is stationary
prior to setting the slips to avoid weakening the shear bolt and prematurely setting the anchor.
11.15 Shallow test MWD at first drill pipe fill up depth.
11.16 Stop at least 30-45’ above planned set depth (2,750’ MD), obtain survey with MWD.
11.17 Milling fluid will be 9.5 ppg LSND
11.18 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string,
measure and record P/U and S/O weights. Obtain good survey to orient whipstock face.
11.19 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP
to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is
30q LOHS – Consult with milling hand
11.20 Whipstock Orientation Diagram:
Desired orientation of the whipstock face is 15L to 45L, target is 30 LOHS
Hole Angle at window interval (2,750’ MD) is ~46°, Azimuth 313°.
Sidetrack tangent section is 62q inclination and 296q azimuth
11.21 Once whipstock is in desired orientation, set WS per Baker Hughes rep.
11.22 CBU and confirm 9.5 ppg MW in/out
x Ensure Mud properties are sufficient for transporting metal cuttings
x Visc: 40-60, YP: 18-20
11.23 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight
and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps
as necessary.
11.24 If possible, install catch trays in shaker underflow chute to help catch metal cuttings.
45L
15L
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
11.25 Clean catch trays and ditch magnets frequently while milling window.
11.26 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window
as needed.
11.27 With upper mill at the end of the tray, this will drill ~ 20’ of new hole.
11.28 After window is milled but before POOH, shut down pumps and work milling assembly through
window watching for drag. Dress and polish window as needed. After reaming, shut off pumps
and rotary and dry drift window.
11.29 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud
properties for drilling.
11.30 Pull back into 13-3/8” casing and perform FIT to 11.0 ppg EMW. Chart Test.
x 13-3/8” casing is cemented. Open hole weak point is the top of the window at 2,750’ MD
/ 2,513’ TVD
x 11.0ppg desired to cover shoe strength for expected ECDs. 10.7 is the minimum to drill
ahead with a >25bbl KT
x 11.0 ppg FIT provides >> 25bbls based upon a 9.5 ppg MW, 8.46 PP (swabbed kick at
9.5 BHP)
11.31 POOH & LD milling BHA. Gauge mills for wear.
11.32 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris.
13-3/8" casing test and FIT digital data to AOGCC immediately upon completion. email: melvin.rixse@alaska.gov
Page 17
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
12.0 Drill 12-1/4” Hole Section
12.1 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 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.
12.2 RIH with 12-1/4” BHA, to top of whipstock. Shallow test MWD at the first fill up point
12.3 Orient directional motor 30q left of highside and slide through window with no pumps or
rotary
x Confirm set orientation of whipstock, and have BHA match
12.4 Displace wellbore to 9.5 ppg LSND
x 9.5 ppg due to hydrates, free gas and potential for Cretaceous over pressure (although none has
been see at W pad, be aware from 4500’ TVD and deeper)
12.5 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 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 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 over melting hydrates
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x 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.Wood has been observed across shakers during the
surface interval TVD.
x Gas hydrates are have been seen on W pad. 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.
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
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 Surface Hole AC, CF <1.0 :
x There are no wells with a CF less than 1.0
12.6 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. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Window - TD 9.5+ (For Hydrates/Free Gas based on offset
wells and cretaceous injection mitigation)
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. Maintain a
minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole
cleaning becomes an issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
System Type:8.8 – 9.8 ppg LSND
Properties:
Section Density LSYP PV YP MPT API FL pH Temp
Surface 8.8 –9.8 4-6 15 - 30 25-45 <8 <10 8.5 –9.0 70 F
12.7 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
12.8 RIH to bottom, proceed to BROOH to window
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.
12.9 CBU x2 at the 13-3/8” shoe and clean casing with high visc sweeps
12.10 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 window for any higher than expected pressure seen
12.11 Orient BHA and pull through window with no pumps or rotary
12.12 TOOH and LD BHA
Obtain gamma ray and resistivity logs in the 12-1/4" section of this well and submit them for
AOGCC review prior to cementing 9-5/8" casing in order to determine the appropriate depth for
top of cement. (See 20 AAC 25.030(d)(5).) SFD 12/8/2022
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
13.0 Run 9-5/8” Liner
13.1 Install 9-5/8” solid body casing rams in the upper ram cavity. RU testing equipment. PT to
250/3,000 psi with 7” test joint. RD testing equipment.
13.2 R/U 9-5/8” liner running equipment (CRT & Tongs)
x Ensure 9-5/8” VAMTOP x NC50 XO on rig floor and M/U to FOSV.
x Use compatible 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 8.5” on the location prior to running.
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.
13.3 P/U shoe joint, visually verify no debris inside joint.
13.4 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
1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring
9-5/8” 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
13.5 Continue running 9-5/8” liner
x Fill casing while running using fill up line on rig floor.
x Use compatible 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.
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
9-5/8” 47# L-80 VAMTOP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”14,440 ft-lbs 15,900 ft-lbs 17,400 ft-lbs
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
13.6 Ensure to run enough liner to provide for sufficient overlap inside 13-3/8” casing. Tentative liner
set depth ~ 2,600’ MD
x Confirm set depth with engineer.
13.7 Ensure hanger/pkr will not be set in a 13-3/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6).
13.8 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.
13.9 M/U Baker SLZXP liner hanger to 9-5/8” liner.
13.10 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.
13.11 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
13.12 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.
13.13 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
13.14 Slow in and out of slips.
13.15 Position the liner shoe +/- 10’ from TD.
13.16 Lower liner to setting depth. Confirm measurements.
13.17 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.
Page 23
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
14.0 Cement 9-5/8” Liner
14.1 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.
14.2 Document efficiency of all possible displacement pumps prior to cement job.
14.3 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.
14.4 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.
14.5 Fill surface cement lines with water and pressure test.
14.6 Cement job will be a single stage job with planned TOC above Ugnu4
14.7 Pump remaining 60 bbls 10.5 ppg tuned spacer.
14.8 Drop bottom dart – Baker rep to witness. Mix and pump cement per below calculations for the
1st stage, confirm actual cement volumes with cementer after TD is reached.
14.9 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to Ungu4, ~4,490’ MD
Estimated Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Liner (8,530'-1,000'-4490') x 0.0558 bpf x 1.3 220.5 1236.7
Total Lead 220.5 1236.7 526.3
12-1/4" OH x 9-5/8" Liner 1000' x 0.0558 bpf x 1.3 = 72.5 406.7
9-5/8" Shoetrack 120' x 0.0732 bpf = 8.8 49.3
Total Tail 81.3 456.0 393.1LeadTail TOC brought to Ungu4, ~4,490’ MD To be determined after AOGCC review of gamma ray and resistivity logs obtained
in the 12-1/4" section of this well. (See 20 AAC 25.030(d)(5).) SFD 12/8/2022
Page 24
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
14.10 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.
14.11 After pumping cement displace cement with mud out of mud pits
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
14.12 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.
14.13 Displacement calculation:
2600’ x 0.0177 bpf (5” dp ID) + (8520’ – 120’ – 2600’) x .0732 bpf (9-5/8” 47# ID) =
= 470.8 bbls
14.14 Slow pump before the dart lands. Do not allow dart to slam into landing collar
14.15 Continue pressuring up to set the SLZXP liner hanger. Hold for 5 minutes. Slack off 20K lbs on
the SZXP liner hanger to ensure the HRDE setting tool is in compression for release from the
SLZXP liner hanger. Continue pressuring up to release the HRDE running tool.
x Liner top packer is not needed for the open shoe well design of W-26B
14.16 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
14.17 Pickup to verify that the HRD setting tool has released. If running tool cannot be hydraulically
released, apply LH torque to mechanically release the setting tool.
14.18 PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed. Circulate multiple bottoms up to remove any cement from around the
drillpipe. Have black water ready
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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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
14.19 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
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.
Page 26
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
15.0 Run 9-5/8” Tieback
15.1 RU and pull wear bushing. Get an accurate measurement of RKB to hanger load shoulder to be
used for tie-back space out calculation.
15.2 RU 9-5/8” 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.
15.3 PU 9-5/8” tieback seal assembly and set in rotary table. Ensure 9-5/8” seal assembly has (4) 1”
holes above the first seal. These holes will be used to spot diesel freeze protect in the 13-3/8” x
9-5/8” annulus.
15.4 MU first joint of 9-5/8” to seal assy.
15.5 Run 9-5/8”, 47#, L-80 VAMTOP tieback to position seal assembly two joints above tieback
sleeve. Record PU and SO weights.
9-5/8” 47# L-80 VAMTOP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”14,440 ft-lbs 15,900 ft-lbs 17,400 ft-lbs
15.6 MU 9-5/8” to DP crossover.
15.7 MU stand of DP to string, and MU top drive.
15.8 Break circulation at 1 BPM and begin lowering string.
15.9 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
15.10 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
15.11 PU string & remove unnecessary 9-5/8” joints.
15.12 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.
15.13 PU and MU the 9-5/8” casing hanger.
15.14 Ensure circulation is possible through 9-5/8” string.
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
15.15 RU and circulate corrosion inhibited brine in the 13-3/8” x 9-5/8” annulus.
15.16 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure
are limited to prevent collapse of the 9-5/8” casing (verify collapse pressure of 9-5/8” tieback
seal assembly).
15.17 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
15.18 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.
15.19 RD casing running tools.
Page 28
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
16.0 Drill 8-1/2” Hole Section
16.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
16.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
16.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
16.4 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.
16.5 Drill out shoe track and 20’ of new formation.
16.6 CBU and condition mud for FIT.
16.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum
required to drill ahead
x 9.8 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP)
16.8 POOH and LD cleanout BHA
16.9 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.
Page 29
Prudhoe Bay West
W-26B SB Producer
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
16.10 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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Prudhoe Bay West
W-26B SB Producer
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
16.11 TIH with 8-1/2” directional assembly to bottom
16.12 Install MPD RCD
16.13 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
x Density may change based upon TD of surface hole section
16.14 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
16.15 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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Prudhoe Bay West
W-26B SB Producer
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 a CF < 1.0
16.16 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.
16.17 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
16.18 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.
16.19 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (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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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
16.20 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
16.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
16.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
16.23 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
16.24 POOH and LD BHA.
16.25 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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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
17.0 Run 6-5/8” Liner
17.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints
17.2 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.
17.3 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.
17.4 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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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
17.5 Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for gas lift
completion. Tentative liner set depth ~ 6,567’ 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.
17.6 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.
17.7 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.
17.8 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
17.9 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.
17.10 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
17.11 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.
17.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
17.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
17.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
17.15 Rig up to pump down the work string with the rig pumps.
~8380' MD
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
17.16 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
17.17 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.
17.18 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.
17.19 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.
17.20 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.
17.21 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
17.22 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.
17.23 PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
17.24 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 4-1/2”, 12.6#, L-80 VAMTOP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6# VAMTOP 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 4x GLM
x 1x X Nipple
x 1x Production Packer
i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval.
x 1x X Nipple
x XXX joints, 4-1/2”, 12.6#, L-80, VAMTOP
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
Draft Upper Completion Tally
Page 39
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
18.3 PU and MU the 4-1/2” tubing hanger with XO.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel
freeze protect for both tubing and IA to 2,500’ MD.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
2. Well Tie in
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Not Utilized
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
20.0 Innovation Rig BOP Schematic – Big Bore Sidetrack
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Not Utilized
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
21.0 Wellhead Schematic
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
21.0 Wellhead Schematic Not Utilized
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
22.0 Days Vs Depth
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
23.0 Formation Tops & Information
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have been seen on PBU W Pad. Be prepared for them. They have been reported between
1800’ 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.
Cretaceous Over Pressure:
W-Pad does not have a history of over-pressure in the cretaceous interval (4500-5300’ TVD). However,
as a precaution ensure MW is above 9.0. Be prepared while drilling this interval.
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
y
Gas hydrates have been seen on PBU W Pad.
Take directional surveys every stand, t
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Prudhoe Bay West
W-26B SB Producer
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. Stuck pipe,
wood chunks over shakers and other hole stability issues are specific to W pad. Be prepared and review
Pad Data Sheet. Bad see pad data sheet
H2S:
Treat every hole section as though it has the potential for H2S. PBU W-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.
PBU W-Pad has a history of H2S ony
wells in all reservoirs. B
Page 47
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 48
Prudhoe Bay West
W-26B 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
p
expected to be normal. U
directional surveys every stand,
Page 49
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
25.0 Innovation Rig Layout
Page 50
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
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W-26B SB Producer
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
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Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
28.0 Casing Design
Page 53
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 54
Prudhoe Bay West
W-26B SB Producer
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 55
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W-26B SB Producer
Drilling Procedure
31.0 Surface Plat (As Built)
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Drilling Procedure
Pad Map For SHL Visual Reference
!!"
# $
090018002700360045005400True Vertical Depth (1800 usft/in)900 1800 2700 3600 4500 5400 6300 7200 8100 9000 9900 10800 11700 12600 13500 14400 15300 16200 17100 18000Vertical Section at 318.00° (1800 usft/in)W-240 wp03 SB-tgtW-240 wp02 CP2W-240 wp02 CP3W-240 wp02 CP4W-240 wp02 CP5W-240 wp02 CP6W-26B wp02 CP1250030003500400045005000550060006500700075008000W-268000W-26A13 3/8" TOW9 5/8" x 12 1/4"6 5/8" x 8 1/2"300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500
1 4000
14500
15000
15500
16000
16500
17000
1 750017611 W-26B wp03KOP: Start Dir 12.5º/100' : 2750' MD, 2513.05'TVD : 0° RT TFEnd Dir : 2767' MD, 2524.58' TVDStart Dir 4º/100' : 2787' MD, 2537.88'TVDEnd Dir : 3383.88' MD, 2862.24' TVDStart Dir 4º/100' : 7094.43' MD, 4560.91'TVDEnd Dir : 7474.37' MD, 4717.26' TVDStart Dir 2.5º/100' : 7615.73' MD, 4762.32'TVDEnd Dir : 8390.35' MD, 4921.04' TVDStart Dir 2.5º/100' : 8490.35' MD, 4929.76'TVDEnd Dir : 9105.11' MD, 4956.92' TVDStart Dir 2.5º/100' : 13192.24' MD, 4959.67'TVDStart Dir 2º/100' : 13462.45' MD, 4959.76'TVDEnd Dir : 13476.48' MD, 4959.73' TVDStart Dir 2º/100' : 15511.01' MD, 4949.76'TVDEnd Dir : 16084.87' MD, 4945.61' TVDStart Dir 2.5º/100' : 16699.9' MD, 4939.76'TVDEnd Dir : 17256.93' MD, 4933.86' TVDTotal Depth : 17610.56' MD, 4929.76' TVDSV1Ugnu 4AUG3Ugnu MBNBOAOBdHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: W-26Ground Level: 53.26+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005959308.010611789.07070° 17' 52.0241 N 149° 5' 40.9357 WSURVEY PROGRAMDate: 2022-11-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool36.85 2750.00 W-26 Srvy 1 GCT MS (W-26) 3_Gyro-CT_pre-1998_Csg2750.00 3150.00 W-26B wp03 (W-26B) 3_MWD_Interp Azi+Sag3150.00 8530.00 W-26B wp03 (W-26B) 3_MWD+IFR2+MS+Sag8530.00 17610.56 W-26B wp03 (W-26B) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation2986.76 2907.00 3655.89 SV13370.76 3291.00 4494.69 Ugnu 4A3693.76 3614.00 5200.25 UG34482.76 4403.00 6923.72 Ugnu MB4681.76 4602.00 7373.46 NB4811.76 4732.00 7783.37 OA4952.76 4873.00 8867.98 OBdREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: W-26, True NorthVertical (TVD) Reference:W-26B As built RKB @ 79.76usftMeasured Depth Reference:W-26B As built RKB @ 79.76usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:WWell:Plan: W-26Wellbore:W-26BDesign:W-26B wp03CASING DETAILSTVD TVDSS MD SizeName2513.05 2433.29 2750.00 13-3/8 13 3/8" TOW4933.11 4853.35 8530.00 9-5/8 9 5/8" x 12 1/4"4929.76 4850.00 17610.56 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 2750.00 46.19 313.41 2513.05 514.28 -578.17 0.00 0.00 769.05 KOP: Start Dir 12.5º/100' : 2750' MD, 2513.05'TVD : 0° RT2 2767.00 48.32 313.41 2524.58 522.86 -587.24 12.50 0.00 781.50 End Dir : 2767' MD, 2524.58' TVD3 2787.00 48.32 313.41 2537.88 533.12 -598.09 0.00 0.00 796.39 Start Dir 4º/100' : 2787' MD, 2537.88'TVD4 2987.00 56.32 313.41 2660.04 641.80 -712.98 4.00 0.00 954.035 3383.88 62.76 296.54 2862.24 835.35 -992.57 4.00 -70.59 1284.95 End Dir : 3383.88' MD, 2862.24' TVD6 7094.43 62.76 296.54 4560.91 2309.32 -3943.85 0.00 0.00 4355.11 Start Dir 4º/100' : 7094.43' MD, 4560.91'TVD7 7314.01 65.00 306.00 4657.76 2411.63 -4112.01 4.00 77.32 4543.66 W-240 wp03 SB-tgt8 7474.37 71.41 305.86 4717.26 2498.95 -4232.51 4.00 -1.15 4689.19 End Dir : 7474.37' MD, 4717.26' TVD9 7615.73 71.41 305.86 4762.32 2577.45 -4341.10 0.00 0.00 4820.18 Start Dir 2.5º/100' : 7615.73' MD, 4762.32'TVD10 8390.35 85.00 320.00 4921.04 3093.01 -4891.87 2.50 47.20 5571.86 End Dir : 8390.35' MD, 4921.04' TVD11 8490.35 85.00 320.00 4929.76 3169.33 -4955.90 0.00 0.00 5671.42 W-26B wp02 CP1 Start Dir 2.5º/100' : 8490.35' MD, 4929.76'TVD12 9105.11 89.96 334.56 4956.92 3684.58 -5286.73 2.50 71.59 6275.69 End Dir : 9105.11' MD, 4956.92' TVD13 13192.24 89.96 334.56 4959.67 7375.55 -7042.11 0.00 0.0010193.19 Start Dir 2.5º/100' : 13192.24' MD, 4959.67'TVD14 13462.45 90.00 327.81 4959.76 7612.17 -7172.26 2.50 -89.67 10456.12 W-240 wp02 CP3 Start Dir 2º/100' : 13462.45' MD, 4959.76'TVD15 13476.48 90.28 327.81 4959.73 7624.04 -7179.73 2.00 -0.78 10469.95 End Dir : 13476.48' MD, 4959.73' TVD16 15511.01 90.28 327.81 4949.76 9345.74 -8263.68 0.00 0.00 12474.72 W-240 wp02 CP4 Start Dir 2º/100' : 15511.01' MD, 4949.76'TVD17 16084.87 90.55 316.33 4945.61 9797.61 -8615.85 2.00 -88.64 13046.17 End Dir : 16084.87' MD, 4945.61' TVD18 16699.90 90.55 316.33 4939.76 10242.47 -9040.50 0.00 0.00 13660.91 W-240 wp02 CP5 Start Dir 2.5º/100' : 16699.9' MD, 4939.76'TVD19 17256.93 90.66 302.41 4933.86 10594.91 -9470.04 2.50 -89.4414210.25 End Dir : 17256.93' MD, 4933.86' TVD20 17610.56 90.66 302.41 4929.76 10784.41 -9768.58 0.00 0.0014550.83 W-240 wp02 CP6 Total Depth : 17610.56' MD, 4929.76' TVD
-1500
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
South(-)/North(+) (1500 usft/in)-9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0
West(-)/East(+) (1500 usft/in)
W-26B wp02 CP1
W-240 wp02 CP6
W-240 wp02 CP5
W-240 wp02 CP4
W-240 wp02 CP3
W-240 wp02 CP2
W-240 wp03 SB-tgt
1500225025002750300032503500375040004 5 0 0500052505750
6 2 5 0
6 7 5 0
7 2 5 0
7 7 5 0
8 2 5 0
8 7 5 0 9 0 0 0
9 1 7 5
W -2 6
650077508 7 5 0
8861
W-26A
8934W-26AL113 3/8" TOW
9 5/8" x 12 1/4"
6 5/8" x 8 1/2"3500375040004250450047504930W-26B wp03KOP: Start Dir 12.5º/100' : 2750' MD, 2513.05'TVD : 0° RT TF
End Dir : 2767' MD, 2524.58' TVD
Start Dir 4º/100' : 2787' MD, 2537.88'TVD
Start Dir 4º/100' : 7094.43' MD, 4560.91'TVD
End Dir : 7474.37' MD, 4717.26' TVD
Start Dir 2.5º/100' : 13192.24' MD, 4959.67'TVD
Start Dir 2º/100' : 13462.45' MD, 4959.76'TVD
End Dir : 13476.48' MD, 4959.73' TVD
Start Dir 2º/100' : 15511.01' MD, 4949.76'TVD
End Dir : 16084.87' MD, 4945.61' TVD
Start Dir 2.5º/100' : 16699.9' MD, 4939.76'TVD
End Dir : 17256.93' MD, 4933.86' TVD
Total Depth : 17610.56' MD, 4929.76' TVD
CASING DETAILS
TVD TVDSS MD Size Name
2513.05 2433.29 2750.00 13-3/8 13 3/8" TOW
4933.11 4853.35 8530.00 9-5/8 9 5/8" x 12 1/4"
4929.76 4850.00 17610.56 6-5/8 6 5/8" x 8 1/2"
Project: Prudhoe Bay
Site: W
Well: Plan: W-26
Wellbore: W-26B
Plan: W-26B wp03
WELL DETAILS: Plan: W-26
Ground Level: 53.26
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
5959308.010 611789.070 70° 17' 52.0241 N 149° 5' 40.9357 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: W-26, True North
Vertical (TVD) Reference: W-26B As built RKB @ 79.76usft
Measured Depth Reference:W-26B As built RKB @ 79.76usft
Calculation Method:Minimum Curvature
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WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT W-26BInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2221510PRUDHOE BAY, SCHRADER BLUF OIL - 640135NA1 Permit fee attachedYes Surface Location lies within ADL0028263; Top Productive Interval lies in ADL0028262;2 Lease number appropriateYes TD lies in ADL0047450.3 Unique well name and numberYes PRUDHOE BAY, SCHRADER BLUF OIL - 6401354 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) (For servNA15 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 This is a redrill out of 13-3/8" surface casing.18 Conductor string providedYes19 Surface casing protects all known USDWsYes 13-3/8" surface casing is fully cemented.20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes Gamma Resistivity to be run in intermediate hole to verify no cement in Ugnu.22 CMT will cover all known productive horizonsYes Esisting 13-3/8" shows integrity.23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pitYes Sundry 322-655 is approved but not executed.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collsion scan identifies no close approaches26 Adequate wellbore separation proposedNA This is a sidetrack out of existing surface casing.27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram, 1 flow cross stack.29 BOPEs, do they meet regulationYes 5000 psi stack will be testest 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 PBU W pad is an H2S pad. Monitoring will be required.33 Is presence of H2S gas probableNA This will be a SB development well.34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required. W-Pad wells are H2S bearing.35 Permit can be issued w/o hydrogen sulfide measuresYes Gas hydrates possible from permafrost base to Top Ugnu. Mitigation measures discussed.36 Data presented on potential overpressure zonesNA Normal pressure gradient expected (8.5 - 8.6 ppg). MPD and properly weighted mud will mitigate37 Seismic analysis of shallow gas zonesNA any abnormal pressures or free gas encountered and aid in maintaining wellbore stability.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate11/29/2022ApprMGRDate12/7/2022ApprSFDDate11/30/2022AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate
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.
SCHRADER BLUFF OIL POOL,
ORION DEVELOPMENT AREA
222-151
PRUDHOE BAY
Obtain gamma ray and resistivity logs in the 12-1/4" section of
this well and submit them for AOGCC review prior to cementing
9-5/8" casing in order to determine the appropriate depth for top
of cement. (See 20 AAC 25.030(d)(5).)
PBU W-26B
