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Alaska Oil and Gas Conservation Commission
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5-1/2"x4-1/2"
RECEIVED 11/17/2023
Completed
10/24/2023
JSB
RBDMS JSB 112923
GDSR-12/8/23
Drilling Manager
11/16/23
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.11.16 15:58:30 -
09'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Edited By: JNL 10/31/2023
SCHEMATIC
Milne Point Unit
Well: MPU I-31
Last Completed: 10/25/2023
PTD: 223-066
TD =19,386’(MD) / TD =4,215’(TVD)
4
20”
Orig. KB Elev.: 67.4’ / GL Elev.: 33.3’
7”
5
6
9
9-5/8”
1
2
3
5-1/2” XO
4-1/2”
@9,589’
See
Screen/
Solid
Liner
Detail
PBTD =19,384’(MD) / PBTD = 4,215’(TVD)
9-5/8” ‘ES’
Cementer
@2,286’
4-1/2”
Shoe @
19,384’
7
8
12
10
4-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 162’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,271’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2271’ 6,874’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 6,687’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.780 6,683’ 9,589’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 9,589’ 19,386’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 6,697’ 0.0152
OPEN HOLE / CEMENT DETAIL
20” Driven
12-1/4"Stg 1 Lead – 624 sx / Tail – 400 sx
Stg 2 Lead – 744 sx / Tail 270 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 244’
90° Hole Angle = @ 7,595’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23763-00-00
Completion Date: 10/25/2023
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 5,345’ Haliburton X-Profile Sliding Sleeve (opens down) 3.813”
3 5,407’ Baker Zenith Gauge Carrier 3.865”
4 5,469’ Baker Retrievable Premier Packer 3.870”
5 5,538’ XN Nipple, 3.813” Packing Bore, 3.725” No-Go 3.725”
66,661’Mule Shoe Joint 3.958”
7 6,683’ SLZXP Liner Top Packer (11.27’ Tieback Sleeve) 6.180”
8 6,705’ 7” H563 x 5.5” EZGO HT XO 4.860”
9 9,589’ 5-1/2” x 4-1/2” XO 3.910”
10 19,384’ Shoe
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 6,878’ 3,948’ 9,589’ 3,959’
4-1/2” 9,591’ 3,959’ 19,345’ 4,212’
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU I-31 Date:10/13/2023
Csg Size/Wt/Grade:9.625", 40# x 47#, L-80 Supervisor:Yessak / Gruenberg
Csg Setting Depth:6874 TMD 3948 TVD
Mud Weight:9.3 ppg LOT / FIT Press =555 psi
LOT / FIT =12.00 Hole Depth =6899 md
Fluid Pumped=1.00 Bbls Volume Back =1.00 bbls
Estimated Pump Output:0.101 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->165 ->5 249
->2 133 ->10 531
->3 191 ->15 800
->4 256 ->20 1015
->5 315 ->25 1278
->6 361 ->30 1509
->7 406 ->35 1776
->8 488 ->40 2061
->9 525 ->45 2348
->10 570 ->50 2620
->11 ->55
->12 ->60
->14 ->65
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 570 ->0 2620
->1 547 ->5 2615
->2 539 ->10 2613
->3 531 ->15 2610
->4 528 ->20 2608
->5 518 ->25 2606
->6 515 ->26 2605
->7 514 ->27 2604
->8 514 ->28 2603
->9 503 ->29 2603
->10 498 ->30 2603
->11 497 ->
->12 486 ->
->13 485 ->
->14 484
->15 484
->16 470
0
1
2
3
4
5
6
7
8 9
10
0
5
10
15
20
25
30
35
40
45
50
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 10203040506070
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
570547539531528518515514514503498497486485484484470
2620 2615 2613 2610 2608 260626052604260326032603
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 35
Pr
e
s
s
u
r
e
(p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Wellname: MP I-31
Rig: Doyon, 14
API Number: 50-029-23763-00-00
Well Permit Number: 223-066
Spud Date: 10/05/23
Date Summary
10/03/23
Build platform & set tree and wellhead equip behind well. Prep and assist WH Rep with installing
speedhead on conductor. C/O sprocket on conveyor #1. Install surface bag on Well w/ crane.
Disconnect 5 star trailer and prep to move Rig. Provided 24 hour notice to the AOGCC at 17:22 of
upcoming diverter test. Move rig onto matts and jockey into position to spot over I-31. Not enough
clearance with I-38 Wellhouse to center Rig over Well. Notify Wells support & Pad operator. Discuss
options and start putting plan in place to move Well house. Offset front of Rig to give an angled
approach in attempt to maximize clearance from I-38 Wellhouse. Still unable to back in far enough to
spot Rig properly. Pull Rig forward to give Wells Group working room. Mobilize crane to move Well
house. Wells Group disconnect electrical in Well house and Wells Support move I-38 Well house back
3'. Spot Rig and center over I-31. Shim the Rig level. Skid the rig floor into drilling position. Secure
landings and exhaust stacks on the roof. R/U service lines to the rig floor. Work on rig acceptance
checklist.
10/04/23
Continue acceptance checklist.. Spot cuttings box, Rockwasher and fuel trailer.. Load 225 jts DP into
Shed. Inspect Mud Pits. Make up knife valve and start work on diverter line.. Rig on Hi Line @
10:00,Continue rigging up and acceptance checklist. Welder re-position #2 pump suction valve pedestal
in Pit #3. Rig up Rockwasher and Rig floor lines. Finish make up diverter vent line. Prep mud pits for
fluid. Continue rigging up and acceptance checklist. Install 4" conductor valves. Install riser on surface
bag. Install manual pit straps in pits #3 & 4. Test mud pits with H2O and test PVT alarms.C/O tugger
line. Perform derrick inspection. R/U H2O upright & pump house. MWD and GWD test tools. Finish
nipple up the diverter vent pipe. SimOps: Offload H2O from pits,Test H2S & LEL gas alarms. Inspect
saver sub and grabber dies, C/O dies on door side. Nipple down diverter line, open I-39 Wellhouse door
allowing access to Wellhead. Start nipple diverter line back up. Install 90' mousehole & stock hopper
room with mud products.. Rig Accepted at 01:00,Pick up and rack back 6 stands HWDP & Jars.. SimOps:
Load on 580 bbls Spud mud to pits. Perform the diverter function test with 5" HWDP. The states right
to witness was waived by AOGCC inspector Kam StJohn on 10/04/23 at 09:16 hours. . Knife valve
opened in 18 seconds and the annular closed in 32 seconds. P/U and M/U 12-1/4" VMD-3 tri-cone bit,
8" mud motor with 1.5 bend and crossover to 36'.. M/U stand HWDP and top drive, RIH and tag up at
57'. Accumulator Test:. System psi = 3000 psi. PSI after closure = 1925 psi. 200 psi attained in 37
seconds. Full pressure attained in 144 seconds. N2 Bottles - 6 at 1900 psi (average). Diverter length =
291'. . Nearest ignition source is 112', light plant at North West corner of pad. Fill stack with water,
check for leaks - Good.. Pressure test mud lines to 3500 psi - good. Cleanout 20" conductor from 57' to
162' with 400 GPM, 400 PSI, 30 RPM, 1K Tq.. Swapped to Spud mud on the fly
Hilcorp Alaska, LLC
HEC Composite
Well Operations Summary
10/05/23
Drill 12-1/4" surface hole from 162' to 218'. pumping 400 GPM, 410 PSI, 30 RPM, 1K ft/lbs Tq, 1K
WOB,,Circulate hole clean, BROOH from 218' to 130', POOH on elevators. Inspect bit - No damage,
cones rotate freely. LD the tri-cone bit, 1-1, in gauge, MU12-1/4" Kymera and RIH with motor.. M/U
Gyro While Drilling, MWD directional, gamma and resistivity tools to 97'. Test and initialize MWD tools.
Drill 12-1/4" surface hole from 218' to 262' (262' TVD). Drilled 44' = 44'/hr AROP. 400 GPM = 850 psi, 30
RPM = 1K ft-lbs TQ, WOB = 5K. PU = 65K, SO = 65K & ROT = 65K. MW = 8.9 ppg, Vis = 300, ECD = 10.22
ppg. Start 3 deg/100' build at 250',Drill 12-1/4" surface hole from 262' to 842' (837' TVD), 580' drilled,
96.7'/hr AROP. 400-450 GPM = 830-1210 psi, 40 RPM = 1-5K ft-lbs Tq, WOB = 5-10K. PU = 85K, SO = 85K,
ROT = 83K. MW = 9.1 ppg, Vis = 195, ECD = 10.11 ppg. Start 4 deg/100' build at 500',Drill 12-1/4" hole
from 842' to 1317' (1264' TVD), 475' drilled, 79.2'/hr AROP.. 450 GPM = 1230 PSI, 40-50 RPM = 3-7K Tq,
WOB = 5-8K.. MW = 9.1, Vis = 230, ECD = 10.62 Max Gas = 5u. PU = 89K, SO = 85K, ROT = 86K. Last Gyro
survey at 1182.95' MD / 1150.57' TVD then swap to MWD. Drill 12-1/4" hole from 1317' to 1984' (1741'
TVD), 667' drilled, 111.2'/hr AROP.. 450 GPM = 1460PSI, 50 RPM = 6K Tq, WOB = 10K.. MW = 9.3, Vis =
171, ECD = 10.5 Max Gas = 7u. PU = 102K, SO = 90K, ROT = 96K
10/06/23
Start 54 deg tangent at 1931.. Last survey at 1931.76 MD / 1711.66 TVD, 54.96 inc, 260.12 azm, 9.89
from plan, 0.5 Low and 9.88 Right,Drill 12-1/4" hole from 1984' to 2651' (2128' TVD), 667' drilled,
111'/hr AROP.. 500 GPM = 1560 PSI, 60 RPM = 7K Tq, WOB = 6K.. MW = 9.3, Vis = 145, ECD = 10.2 Max
Gas = 407u. PU = 110K, SO = 90K, ROT = 101K,Drill 12-1/4" hole from 2651' to 3147' (2429' TVD), 496'
drilled, 82.7'/hr AROP.. 500-550 GPM = 1560-1800 PSI, 60 RPM = 5-7K Tq, WOB = 0-5K.. MW = 9.3, Vis =
180, ECD = 10.43 Max Gas = 556u. PU = 120K, SO = 87K, ROT = 100K. 30 bbl hi vis sweep @ 3032', back
on time with 75% increase,BOPF logged at 2092' MD, 1805' TVD. Pump 30 bbl hi vis sweep @ 2270',
back on time with 30% increase. Maintain 54 deg tangent. Drill 12-1/4" hole from 3147' to 3637' (2754'
TVD), 490' drilled, 81.7'/hr AROP.. 500-550 GPM = 1690-1850 PSI, 80 RPM = 6-10K Tq, WOB = 5K.. MW =
9.2, Vis = 132, ECD = 10.2 Max Gas = 107u. PU = 135K, SO = 92K, ROT = 108K. Start 4.25 deg build and
right turn @ 3412',Drill 12-1/4" hole from 3637' to 4270' (3061' TVD), 633' drilled, 105.5'/hr AROP.. 530
GPM = 1930 PSI, 80 RPM = 12K Tq, WOB = 8K.. MW = 9.1, Vis = 188, ECD = 10.3 Max Gas = 36u. PU =
146K, SO = 96K, ROT = 117K. 30 bbl hi vis sweep @ 4078', back on time with 30% increase
10/07/23
Top of Ugnu logged at 2907' MD / 2277'. Last survey at 4216.22' MD / 3038.13' TVD, 56.60 inc, 297.20
azm, 13.62' from plan, 10.8' High and 8.3' Right,Drill 12-1/4" hole from 4270' to 4937' (3061' TVD), 667'
drilled, 111'/hr AROP.. 550 GPM = 1930 PSI, 80 RPM = 12K Tq, WOB = 8K. MW = 9.1, Vis = 188, ECD =
10.3 Max Gas = 36u. PU = 146K, SO = 96K, ROT = 117K,Drill 12-1/4" hole from 4937' to 5396' (3551'
TVD), 459' drilled, 76.5'/hr AROP.. 550 GPM = 2290 PSI, 60-80 RPM = 10-17K Tq, WOB = 13-15K.. MW =
9.4, Vis = 135, ECD = 10.34 Max Gas = 183u. PU = 160K, SO = 90K, ROT = 117K. Sweep at 5031' on time
50% increase in cuttings,Drill 12-1/4" hole from 5396' to 5695' (3677' TVD), 299' drilled, 49.8'/hr AROP..
550 GPM = 1800 PSI, 60 RPM = 14-17K Tq, WOB = 2-5K.. MW = 9.25, Vis = 95, ECD = 10.05 Max Gas =
1189u. PU = 177K, SO = 90K, ROT = 123K,Drill 12-1/4" hole from 5695' to 6170' (3820' TVD), 475' drilled,
79.2'/hr AROP.. 530 GPM = 2210 PSI, 80 RPM = 18K Tq, WOB = 14K.. MW = 9.3, Vis = 126, ECD = 10.4
Max Gas = 208u. PU = 178K, SO = 90K, ROT = 125K. Sweep at 6076', results carried on next report.
Severe screen blinding after connection at 5504' MD. Slow pumps to 4 BPM and screen down to 80
mesh to minimize mud overboarding. Heavy oil returns slowed and screen blinding becoming
manageable by 5600', start screening back up to 140 mesh.
10/08/23
Last survey at 6119.17' MD / 3808.26' TVD, 73.65 inc, 339.32 azm, 11.22' from plan, 8.94' High and 6.78'
Right,Drill 12-1/4" hole from 6170' to 6648' (3926' TVD), 478' drilled, 80'/hr AROP.. 550 GPM = 2420 PSI,
80 RPM = 17K Tq, WOB = 14K.. MW = 9.4, Vis = 115, ECD = 10.5 Max Gas = 207u. PU = 175K, SO = 90K,
ROT = 125K,Hi vis sweep @ 6076', back 100 stks late with 30% increase,Drill 12-1/4" hole from 6648' to
TD at 6879' (3948' TVD), 231' drilled, 92'/hr AROP.. 550 GPM = 2320 PSI, 80 RPM = 15-18K Tq, WOB =
5K.. MW = 9.5, Vis = 81, ECD = 10.46 Max Gas = 158u. PU = 185K, SO = 86K, ROT = 121K. TD called by
geologist, 7' TVD below top of Schrader Bluff OA-sands. Pump 30 bbl hi-vis sweep and circulate the hole
clean at 550 GPM = 2,029 psi, 60 RPM = 15K ft-lbs TQ while reciprocating 90' alternating stopping
points.. Sweep back 500 strokes late with no increase. Cont to circulate 2 BU racking back a stand each
BU. MW in/out = 9.35/9.4 ppg & Vis in/out = 55/95. Obtain final MWD survey at TD. Last Survey =
6825.55' MD / 3944.82' TVD, 86.14 deg Inc, 1.16 deg Azi. Distance to Plan = 14.66', 14.20' low and 3.63'
Right,Wash to bottom @ 200 GPM with no issues and monitor well for 10 min - static. BROOH from
6879' to 5697' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM =
1850 psi, 60 RPM = 14-17K ft-bs Tq, Max gas = 30u. PU = 187K, SO = 90K, ROT = 127K,BROOH from 5697'
to 2209' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1300
psi, 60 RPM = 5-10K ft-bs Tq, Max gas = 50u. PU = 125K, SO = 92K, ROT = 100K
10/09/23
BROOH from 2209' to 749' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots.
550 GPM = 1300 psi, 60 RPM = 3K ft-bs Tq, Max gas = 50u. PU = 85K, SO = 85K, ROT = 85K,Circulate 2x
BU on last stn of 5" DP @ 844'. Observed 15k tq spike and 15k overpull at 805'. Slacked off and eased up
into it in small increments. At bottoms up observed wood on the shakers. At 801' tq smoothed out and
was able to get up to 779' before it started overpulling and torqueing up again. Eased up to top of stand
at 749'. Oriented HS and with no pumps slacked off down to 811' with no issue. Cont. to back ream
from 749' to 656', at 450 GPM = 890 PSI 40, RPM = 3-4k TQ.. Still seeing 4-14k Tq spikes still seeing
wood at the shakers and hole started to unload sand. At top of stand at 656' oriented HS and with no
pumps slacked off down to 749' with no issue. POOH on elevators from 558' to 463'.Blow down top
drive.. Cont to POOH on elevators from 463' to 159',Cont to back ream from 656' to 558'. At top of
stand at 558' oriented HS and with no pumps slacked off down to 656' with no issue.. 32 bbls lost on
BROOH,PJSM, L/D BHA F/ 159' T/ 97' MD Download MWD.. Cont. L/D BHA to surface.. 12-1/4" Kymera
Dull Bit Grade: PDC = 1-1-CT-N-X-1-NO-TD & Cones = 2-2-WT-A-E-1-NO-TD,Clear and clean the rig floor,
adjust TopDrive service loop, flush and clean the flowline. R/U the volante tool, bail extensions, 9-5/8''
handling equipment and DDI casing tongs. Ready FOSV and crossover. Loss rate 3-4 bph,PJSM. MU 9-
5/8", 40#, L-80, TXP-BTC shoe track. Bakerlok 1-4 connections with 21K ft-lbs TQ. HES rep installed "Top
Hat" above float collar. Pump through shoe track and check floats (good). RIH with 9-5/8", 40# casing
from 125' to 987', Tq = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing
centralizer per tally.. PU = 80K, SO = 75K. Loss rate = 4 BPH,RIH with 9-5/8", 40# casing from 987' to
2627', Tq = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer
per tally.. PU = 145K, SO = 100K. Loss rate = 5 BPH,Circulate a string volume. Stage pumps up to 6 BPM,
200 psi. Some wood and good amount of sand through bottoms up. RIH with 9-5/8", 40# casing from
2627' to 3642', Tq = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing
centralizer per tally.. PU = 225K, SO = 102K. Loss rate = 4 BPH
10/10/23
RIH with 9-5/8", 40# casing from 3642' to 4572', Tq = 21K ft-lbs with Volant tool. Fill on the fly and top
off every 10 joints. Installing centralizer per tally.. PU = 256K, SO = 100K. Loss rate = 4 BPH,PU, thread
loc and MU ES Cementer and pup jts to 4602'. Halliburton cementers double checked shear screws (6
screws 3,300 psi). RIH with 9-5/8", 47# TXP-BTC casing from 4602' to 6243', Tq = 23820K ft-lbs with
Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally.. PU = 355K, SO =
104K. Loss rate = 4 BPH,RIH with 9-5/8", 47# TXP-BTC casing from 6243' to 6817', Tq = 23820K ft-lbs
with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally.. PU = 370K, SO
= 115K. Loss rate = 4 BPH,Wash down f/ 6817' t/ 6874' MD @ 1 BPM = 300 PSI ICP. Stage pumps up,
working string 20' strokes. 4 BPM = 340 PSI, 5 BPM = 400 PSI, 6 BPM = 190 PSI. Rotate at 5 RPM = 15k
Tq. SimOps: Prep pits for cmt job, R/D spiders, tongs and bail extensions. Cementers spotted in and
R/U. Total 52 bbls loss on TIH,Shut down pump, BD TD and breakout volant. RU plug valves and cement
hose. Re-dope and MU volant. Close upper and lower IBOP. Continue to circulate 6 BPM = 320 psi, .
Blow air to cement unit. Finish getting the pits ready. Hold PJSM with all parties involved. Pump 50 bbls
mud treated with desco, HES filled lines with 5 bbls fresh water. PT surface lines to 1,000/4,000 psi,
good. Displace with 9.4 ppg mud from the rig at 5 BPM = 540 psi ICP, slow to 3 bpm for last 10 bbls, FCP
650 psi.. Bumped plugs at 3991 strokes (3 bbls early). Pressure up to 1,250 psi, hold for 3 min, bleed off.
pressure, check floats good. Pressure up and shift ES cementer open at 3300 psi. CIP @ 22:56. Recorded
25 bbls loss during 1st stage cement job. HES pump 20 bbls water at 7 BPM = 500 psi. Displace with 309
bbls (3060 strokes) 9.4 ppg spud mud from rig at 6-7 BPM = 200 psi. Displace with 80 bbls 9.4 ppg
Tuned Spacer from HES at 4.9 BPM = 580 psi. Pump through ES cementer at 2289' stage up to 5 BPM =
200 psi. Dumped 130 bbls of tuned spacers, 34 bbls of good cement and 89 bbls of clabbered
mud/interface to the Rockwasher before taking returns to the pits.. Circulated total of 5 bottoms up.
No losses while circulating. Pump 1st stage cement job: . Mix & pump 60 bbls of 10 ppg tuned spacer
with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 5 BPM = 300 psi. . Drop bypass plug. . Mix and pump
261 bbls of 12.0 ppg lead cement (EconoCem I/II cement, 2.347ft^3/sk yield, 624 sks total) at 5 BPM =
350 psi. Mix & pump 82 bbls 15.8 ppg tail cement (HalCem I/II, 1.155 ft^3/sk yield, 400 sks total) at 3.2
BPM = 350 psi. Drop shutoff plug.. P/U wt exceeding 400K, park on depth at 6874,Disconnect knife
valve from accumulator. Drain stack and flush with black water two times. . Re-connect knife valve to
the accumulator. Clean rig floor cement valves and PT valves after to 3750 psi. Continue circulating
through the ES cementer at 2289', staging the pumps up to 6 BPM = 200 psi
10/11/23
Continue circulating through the ES cementer at 2289', pumping 4 BPM = 90 psi while prepping for 2nd
stage.. No losses,Hold PJSM with all parties.. Pump 2nd stage cement job: . Mix & pump 60 bbls of 10.0
ppg Tuned Spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 6.5 BPM = 290 psi.. Mix & pump
total 388 bbls 10.7 ppg ArcticCem lead cmt (744 sx at 2.888 ft^3/sk yield) at 6.5 BPM = 367 psi (ICP) &
388 psi (FCP),Blow down the lines. Disconnect the knife valve from the accumulator. Drain the stack and
flush with blackwater 3 times. R/D the Volant CRT. Vacuum out the mud from the casing. R/U the 9-
5/8" elevators.. SimOps: Weld on structural beams in Mud Pits. Mix & pump 56 bbls of 15.8 ppg HalCem
tail cement (270 sx at 1.156 ft^3/sk yield) at 3 BPM= 315 psi.. Drop the closing plug.. Pump 20 bbls of
8.34 ppg fresh at 4 BPM = 160 psi. Displace cement with 9.4 ppg spud mud. 5.5 BPM = 225 psi (ICP) &
700 psi (FCP). Slowed to 3 BPM = 550 psi for last 10 bbls. Bumped plugs at 1471 strokes (10strks/1 bbls
late). Pressured up and shifted the ES cementer closed at 1580 psi. Continue to pressure up to 1700 psi
and hold for 2 minutes,Bleed pressure to 0 psi and check for flow - none. CIP at 13:33 hours. No losses
during the job. Returns to surface: 60 bbls of spacer, 95 bbls interface and 233 bbls of cement. Mobilize
casing handling equipment off the rig floor. SimOps: Welder fix chain guard on skate. N/D diverter line.
N/D the knife valve.. SimOps: Welder & mechanic install new drawworks cooling fan,BOLDS on the
speed head. Let the air out of the air boots on the riser. Lift the surface annular. Center up the 9-5/8''
casing, WHR install casing slips with 100K set on the slips. Welder made casing cut. L/D cut joint. Length
on cut joint= 17.08'. Welder dressed the casing stump. N/D the diverter stack/tee and remove from
cellar. Mobilize Well head spools into the cellar. Lay down the mousehole.. SimOps: Cleaning the mud
pits.. Hi-Line power down at 22:17, On Rig Gen power at 22:36,Orient and make up the Wellhead and
casing spools. PT the void to 500 psi for 5 minutes and 3,800 psi for 10 minutes (good test). SimOps:
Continue cleaning the mud pits. N/U the BOP stack.
Recorded
25 bbls loss during 1st stage cement job.
Mix & pump
total 388 bbls 10.7 ppg ArcticCem lead cmt (
Pump 1st stage cement job:
Mix & pump 82 bbls 15.8 ppg tail cement
Pump through ES cementer at 2289' stage up to 5 BPM =
200 psi. Dumped 130 bbls of tuned spacers, 34 bbls of good cement and 89 bbls of clabbered
mud/interface to the Rockwasher before taking returns to the pits..
Mix & pump 56 bbls of 15.8 ppg HalCem
tail cement
Mix and pump
261 bbls of 12.0 ppg lead cement
Bumped plugs
Bumped plugs at 3991 strokes (3 bbls early).
Pump 2nd stage cement job:
10/12/23
Cont. N/U the BOP stack. Remove 24" 13-5/8" spacer. Install kill and choke line. Obtain RKB's,Change
out upper pipe rams from 2-7/8" x 5" VBR's to 4-1/2" x 7" VBR's. Grease choke manifold / Mud
cross,Install mouse hole. Install MPD trip nipple. Prep for testing BOPE,Install test plug, fluid pack BOP's
/ Choke manifold with water and check for leaks. Fix leak on choke line Oteco clamp.. Mobilize 3-1/2"
floor valves to rig floor and M/U to test stump. Perform BOP shell test to 250/3000 psi (passed).
Conduct initial BOPE test to 250/3,000 psi: UPR (4-1/2" x 7" VBR) with 4-1/2", 5'' & 7" test jts. LPR (2-
7/8" x 5" VBRs) with 4-1/2" & 5" test jts, annular with 4-1/2" test jt, . Accumulator drawdown test &
test gas alarms. Blow down and R/D testing equipment. Pull the test plug and install the wear ring (ID =
9"). Accumulator Test: System pressure = 3050 psi. Pressure after closure = 1650 psi. 200 psi attained in
46 seconds. Full pressure attained in 188 seconds. Nitrogen Bottles - 6 at 1963 psi. Rig electrician
calibrate and test rig gas alarms. All tests performed with fresh water against test plug.. Test witnessed
by AOGCC inspector J. Hunt.. Tests: . 1. Annular with 4-1/2" test joint, 3" Demco kill, 5" Dart, choke
valves 1, 12, 13 & 14 (passed). 2. UPR with 4-1/2" test joint, 5" FOSV, choke valves 9 & 11 (passed),3.
LPR with 4-1/2" test joint (passed). 4. UPR with 7" test joint, upper IBOP, HCR kill, choke valves 5, 8 &
10 (fail/pass). 5. Lower IBOP, manual kill, choke valves 4, 6 & 7 (passed).. 6. Choke valve 2 (passed). 7.
HCR choke, 3-1/2" dart valve (passed). 8. Manual choke, 3-1/2 FOSV (passed),9. LPR with 5" test joint
(passed). 10. Blind rams, choke valve 3 (passed). 11. Hydraulic super choke (passed). 12. Manual
adjustable choke (passed),Rig up and jet the flowline clean. M/U 8-1/2" Cleanout BHA: 8-1/2" Tri-cone
bit, 6-3/4" mud motor with non-ported float installed in top and ABH set at 1.5 deg to 32'. TIH with 6
stands 5" HWDP including jar stand to 587'. TIH with cleanout BHA from 587' to 2205', M/U TD, fill
pipe.. PU = 100K, SO = 80K, ROT = 90K,Wash and ream from 2205'. Tag soft cement at 2278'. 400 gpm,
700 psi, 30 rpm, 2k torque. Drill plug and ES cementer from 2286' to 2289' at 400 GPM = 700 psi, 30
RPM = 2K Tq, WOB = 5-8K. . Wash and ream through the ES cementer 3 times and drift through clean
without pump/rotary to 2298'. Start RIH on elevators and take wt at 2339'. Work string and still taking
wt down to 2345'. Kelly up and Wash/Ream in the hole t/ 2679'. 400 GPM = 650 psi, 30 RPM = 2K Tq,.
RIH on elevators with 3 stands to 2965' with no issues. Blow down the top drive. TIH with cleanout BHA
from 2965' to 5914' filling DP every 2,000'. PU = 195K & SO = 85K.
10/13/23
TIH with cleanout BHA from 5914' to 6676'.. PU = 195K & SO = 85K. Wash down from 6676' to 6735' at
400 GPM = 1070 psi, 30 RPM = 18K ft-lbs Tq. CBU to condition mud for casing PT. P/U = 225k S/O = 75k
ROT = 90k,RU testing equipment and purge air from the system. Close the UPR and PT the 9-5/8" casing
to 2,500 psi for 30 minutes charted - good test. Pumped 5 bbls to pressure up and bled back 5 bbls..
Blow down and rig down test equipment. Wash down from 6735' tag hard cement at 6737'. Drill
cement and float equipment from 6737' to 6879'. (FE on depth). Drill rathole and 20' of new formation
to 6899' at 400 GPM = 1,050 psi, 30 RPM = 20K ft-lbs TQ, WOB = 5-8K. PU = 254K, SO = 72K. Rack back 1
stand to 6864'. Circulate and condition mud prior to performing FIT at 400 GPM = 1020 psi, 30 RPM =
17K ft-lbs TQ, reciprocating string 90'. RU testing equipment and purge air from the system Close the
UPR. Perform FIT to 12.0 ppg with 9.3 ppg MW at 3,948' TVD and applying 555 psi at surface. Good test.
Pumped 1 bbls and bled back 1 bbl.. B/D, R/D test equipment and hoses. Pump 11.3 ppg dry job. B/D
top drive. TOOH from 6864' to HWDP at 587'. Observe the well for flow (static). Lay down 15 jts, 5"
HWDP and rack back jar stand from. Lay down motor and tri-cone bit. Bit grade: 1-1-WT-A-E-I-NO-BHA.
10 bbl losses TOOH,Clear and clean the rig floor. Mobilize split bushings and BHA components to the rig
floor. Remove the master bushing and install the split bushings.. Monitor well with trip tank, static.
PJSM, MU 8-1/2" NOV PDC bit, NRP-A2 bit sleeve, 7600 Geo-Pilot, ADR, DGR, ILS, PWD, directional
collars and stabilizer to 89'. Initialize and confidence test MWD. Finish making up BHA with 2 NM float
subs, 2 NM flex collars, 5" HWDP and jar to 247'.. SimOps: PT MPD lines to 300/1,000 psi - good test,RIH
1 stand drillpipe to 339'. Shallow pulse test MWD at 400 GPM = 675 psi. Break in the Geo Pilot seals.
Blow down the top drive. TIH with 8-1/2" RSS from 339' to 6621'. Continue in the hole picking up 5" DP
singles from pipe shed to 6747'. . PU = 235k, SO = 75k. No losses while TIH.
10/14/23
Continue to P/U DP single from pipe shed from 6747' to 6809'. PU = 230K & SO = 75K,PJSM. Pull the
MPD riser and install the MPD RCD bearing. Install the RCD head skirt for the drip pan. Fill the DP and
break circulation. Check for leaks - none. PJSM. Pump 35 bbl spacer pill. Displace the well from 9.3ppg
spud mud to 8.8 ppg FloPro NT at 6 BPM = 650 psi ICP, 30 RPM = 13K ft-lbs Tq. Wash to TD with mud at
the bit then pull into the casing. Reciprocate 30'.. P/U = 230k S/O = 74K ROT = 120K. FCP 6 BPM = 520
psi, P/U = 208K, S/O = 80k, ROT = 120K,PJSM. Slip and cut 80' of drilling line. Service the top drive..
SimOps: Clean pit 4 and surface equipment. C/O saver sub and check break out dies. Obtain SPR's and
wash down to 6899'. Drill 8-1/2" lateral from 6899' to 7189' (3960' TVD). Drilled 290' = 116'/hr AROP.
460 GPM = 1240 psi, 120 RPM = 10K ft-lbs Tq, WOB = 15K. PU = 147K, SO = 90K & ROT = 115K. MW =
8.85 ppg, Vis = 40, ECD = 10.01 ppg, max gas = 884 units. Drilled through fault #1 at 7160', 6' DTS throw
from OA-2 into OA-3,Drill 8-1/2" lateral from 7189' to 7760' (3956' TVD). Drilled 571' = 95'/hr AROP. 450
GPM = 1370 psi, 120 RPM = 9K ft-lbs Tq, WOB = 15K. PU = 143K, SO = 89K & ROT = 113K. MW = 8.95
ppg, Vis = 40, ECD = 10.23 ppg, max gas = 642 units. Exit OA base at 7341',Drill 8-1/2" lateral from 7760'
to 8330' (3949' TVD). Drilled 570' = 95'/hr AROP. 500 GPM = 1800 psi, 120 RPM = 11K ft-lbs Tq, WOB =
15K. PU = 148K, SO = 84K & ROT = 108K. MW = 9.0 ppg, Vis = 44, ECD = 10.60 ppg, max gas = 358 units
10/15/23
Re-enter the OA sands at 7830'. Drop trajectory & exit the base at 8160' in anticipation of Fault #2. . We
have drilled 17 concretions for a total thickness of 131' (10.0% of the lateral). Last survey at 8261.00'
MD / 3945.03' TVD, 86.67 inc, 5.82 azm, 25.73' from plan, 25.72' high and 0.29' left,Drill 8-1/2" lateral
from 8330' to 8985' (3982' TVD). Drilled 655' = 109'/hr AROP. 500 GPM = 1840 psi, 120 RPM = 10K ft-lbs
Tq, WOB = 15K. PU = 143K, SO = 87K ROT = 110K. MW = 9.0 ppg, Vis = 45, ECD = 10.8 ppg, max gas = 588
units. MPD choke open while drilling & trapping 9.6 EMW on connection,Re-acquired the OA-1 sand at
8620'.. Encountered fault # 3 at 8785', 14' DTS. Faulting from OA-1 to OA-3. Drill 8-1/2" lateral from
8985' to 9567' (3959' TVD). Drilled 582' = 97'/hr AROP. 500 GPM = 1890 psi, 120 RPM = 11K ft-lbs Tq,
WOB = 15K. PU = 146K, SO = 81K & ROT = 110K. MW = 9.1 ppg, Vis = 42, ECD = 11.01 ppg, max gas = 570
units. Pump sweep at 9091' back on time 75% increase,MPD choke open while drilling & trapping 9.6
EMW on connection.. Encountered fault #4 at 9022', 24' DTS throw. Faulted out of zone below the OA
package. Targeting 94 deg to re-acquire OA sand. Drill 8-1/2" lateral from 9567' to 10329' (3985' TVD).
Drilled 762' = 127'/hr AROP. 520 GPM = 2040 psi, 120 RPM = 11K ft-lbs Tq, WOB = 15K. PU = 149K, SO =
77K & ROT = 111K. MW = 9.1 ppg, Vis = 42, ECD = 11.16 ppg, max gas = 449 units,Min separation with J-
26 close approach was 13.78' at 9980' MD. . Survey at 10069.64' had magnetic interference from the
close approach and the azimuth for that survey station is interpolated. MPD choke full open while
drilling & trapping 100 psi for a 9.6 EMW on connection.. Re-enter the OA base at 9198. Total of 176
feet drilled below the OA sands.. Performed 290 bbls whole mud dilution at 9567, dropping MBT from 7
to 5.75 ppb.. Pump sweep at 10044' back on time 50% increase. Drill 8-1/2" lateral from 10329' to
11188' (4022' TVD). Drilled 859' = 143'/hr AROP. 530 GPM = 2240 psi, 130 RPM = 12K ft-lbs Tq, WOB =
18K. PU = 153K, SO = 70K & ROT = 108K. MW = 9.1 ppg, Vis = 45, ECD = 11.51 ppg, max gas = 846 units
10/16/23
MPD choke full open while drilling & trapping 100 psi for a 9.6 EMW on connection.. At 10600', see an
increase in mud vis and MBT check shows 8 ppb. Start empty Rockwasher and prep for whole mud
dump & dilution.. Sweep at 11090', in the hole at report time. We have drilled 30 concretions for a total
thickness of 221' (5.2% of the lateral).. Last survey at 11019.17' MD / 4023.54' TVD, 89.94 inc, 5.21 azm,
31.42' from plan, 29.18' low and 11.65' right. Drill 8-1/2" lateral from 11188' to 11662' (4030' TVD).
Drilled 544' = 91'/hr AROP. 525 GPM = 2240 psi, 130 RPM = 16K ft-lbs Tq, WOB = 7K. PU = 164K, SO =
68K & ROT = 107K. MW = 9.0 ppg, Vis = 45, ECD = 11.0 ppg, max gas = 846 units. MPD choke full open
while drilling & trapping 100 psi for a 9.6 EMW,Sweep pumped at 11,090' back on time with 20%
increase. 11,310' perform 440 bbl dump/dilute with new 8.8 ppg Flow Pro mud lowering the MBT from
8 to 4.5,Drill 8-1/2" lateral from 11662' to 12519' (4033' TVD). Drilled 857' = 143'/hr AROP. 520 GPM =
2240 psi, 120 RPM = 15K ft-lbs Tq, WOB = 14K. PU = 159K, SO = 63K & ROT = 108K. MW = 9.0 ppg, Vis =
43, ECD = 11.42 ppg, max gas = 330u. MPD choke full open while drilling & trapping 100 psi for a 9.6
EMW,Sweep pumped at 12045' back on time with 75% increase. Drill 8-1/2" lateral from 12519' to
13280' (4043' TVD). Drilled 761' = 127'/hr AROP. 515 GPM = 2330 psi, 120 RPM = 14K ft-lbs Tq, WOB =
15K. PU = 160K, SO = 50K & ROT = 106K. MW = 9.15 ppg, Vis = 46, ECD = 11.62 ppg, max gas = 337u.
MPD choke full open while drilling & trapping 100 psi on conn,Drill 8-1/2" lateral from 13280' to 14045'
(4065' TVD). Drilled 765' = 127'/hr AROP. 525 GPM = 2320 psi, 120 RPM = 15K ft-lbs Tq, WOB = 18K. PU
= 167K, SO = 0K & ROT = 107K. MW = 9.0 ppg, Vis = 44, ECD = 11.4 ppg, max gas = 837u,Sweep at
13090'. 200 stks late, 50% increase.. ECDs at 11.86, slow flow rate to 475 GPM until dump and dilute
started.
10/17/23
We have drilled 38 concretions for a total thickness of 277' (3.9% of the lateral).. Last survey at
13973.69' MD / 4066.48' TVD, 85.86 inc, 12.18 azm, 6.84' from plan, 4.46' high and 5.19' right. Drill 8-
1/2" lateral from 14045' to 14828' (4065' TVD). Drilled 783' = 130'/hr AROP. 525 GPM = 2440 psi, 120
RPM = 16 ft-lbs Tq, WOB = 11K. PU = 177K, SO = 0K & ROT = 108K. MW = 9.0 ppg, Vis = 42, ECD = 11.6
ppg, max gas = 586u,Drilled high in the OA-1 then exit the top from 13269' to 13439', this is was a
planned trajectory and departure from the OA to maximize AC separation with J-09 & I-19. Minimum
separation with J-09 = 8.05' at 13055' MD & I-19 = 4.5' at 13395' MD,Sweep at 14045', in the hole at
report time. MPD choke full open while drilling & trapping 100 psi on conn. ECDs climbing to 11.6-11.8,
adjust flow rates and ROP to help control.. Performed 580 bbls whole mud dilution at 13281', dropping
MBT from 8 to 4 ppb,Sweep at 14045', back on time 75% increase. MPD choke full open while drilling &
trapping 100 psi on conn,Drill 8-1/2" lateral from 14828' to 15695' (4084' TVD). Drilled 867' = 144.5'/hr
AROP. 525 GPM = 2440 psi, 120 RPM = 17 ft-lbs Tq, WOB = 10K. PU = 176K, SO = 0K & ROT = 108K. MW
= 9.0 ppg, Vis = 40, ECD = 11.48 ppg, max gas = 651u,Sweep at 15090', back on time, 20% increase. MPD
choke full open while drilling & trapping 100 psi on conn,Drill 8-1/2" lateral from 15695' to 16423'
(4101' TVD). Drilled 728' = 121'/hr AROP. 500 GPM = 2330 psi, 120 RPM = 15 ft-lbs Tq, WOB = 10K. PU =
175K, SO = 0K & ROT = 112K. MW = 8.95 ppg, Vis = 42, ECD = 11.55 ppg, max gas = 484u,Sweep at
16044', back on time, 30% increase. MPD choke full open while drilling & trapping 100 psi on conn. Exit
base of OA at 16225' in anticipation of fault #5. Fault #5 logged at 16236', 31' DTN throw, faulting from
below the OA package into the OA-1,Drill 8-1/2" lateral from 16423' to 17143' (4128' TVD). Drilled 720'
= 120'/hr AROP. 500 GPM = 2430 psi, 120 RPM = 18 ft-lbs Tq, WOB = 14K. PU = 202K, SO = 0K & ROT =
107K. MW = 9.0 ppg, Vis = 41, ECD = 11.60 ppg, max gas = 676u
10/18/23
Maintain 88 deg trajectory, dropping down from OA-1 through the OA-2 and into the OA-3 then follow
formation dip at 89 deg.. Sweep at 17090', in the hole at report time.. MPD choke full open while
drilling & trapping 100 psi on conn,We have drilled 54 concretions for a total thickness of 395' (3.9% of
the lateral).. Last survey at 17018.36' MD / 4128.40' TVD, 89.14 inc, 5.21 azm, 21.86' from plan, 20.91'
high and 6.40' left. Drill 8-1/2" lateral from 17143' to 17655' (4137' TVD). Drilled 512' = 85'/hr AROP.
500 GPM = 2260 psi, 120 RPM = 20 ft-lbs Tq, WOB = 16K. PU = 196K, SO = 0K & ROT = 109K. MW = 8.9
ppg, Vis = 41, ECD = 11.50 ppg, max gas = 769u. MPD choke full open while drilling & trapping 100 psi
on conn,Drill 8-1/2" lateral from 17655' to 18340' (4181' TVD). Drilled 685' = 114'/hr AROP. 500 GPM =
2440 psi, 120 RPM = 19 ft-lbs Tq, WOB = 11K. PU = 190K, SO = 0K & ROT = 107K. MW = 9.0 ppg, Vis = 39,
ECD = 11.78 ppg, max gas = 829u,Drill 8-1/2" lateral from 18340' to 18920' (4190' TVD). Drilled 580' =
97'/hr AROP. 500 GPM = 2490 psi, 100 RPM = 19 ft-lbs Tq, WOB = 11K. PU = 200K, SO = 0K & ROT =
113K. MW = 9.05 ppg, Vis = 41, ECD = 11.71 ppg, max gas = 506u,Fault #7 at 17747' MD, 21' DTN throw
from OA-3 into the OA-1. Sweep at 18042', back 200 stks late, 10% increase. MPD choke full open while
drilling & trapping 100 psi on conn,MPD choke full open while drilling & trapping 100 psi on conn.. Fault
#8 at 18420' MD, 30' DTN throw from OA-4 into the OA-1,Drill 8-1/2" lateral from 18920' to TD at 19386'
(4215' TVD). Drilled 466' = 133'/hr AROP. 475 GPM = 2650 psi, 120 RPM = 19K ft-lbs Tq, WOB = 18K. PU
= 224K, SO = 0K & ROT = 126K. MW = 9.1 ppg, Vis = 42, ECD = 11.83 ppg, max gas = 508 units,Fault #9 at
19240' MD, 2' DTN throw from upper OA-3 to skirting the top of OA-3. Final survey at TD = 19316.06'
MD, 4210.22' TVD, 85.92 deg INC, 4.94 deg AZM. Distance from Wp15 at TD = 14.01' (12.21' low & 6.86'
right). Pump 30 bbl hi-vis sweep around and circulate 2 of 3 BU, reciprocating 90' and racking a stand
back every BU, 450-475 GPM = 2450-2650 psi, 120 RPM = 19K ft-lbs Tq, MW = 9.0+ ppg, Vis = 41. ECDs =
11.74-11.9
10/19/23
Finish circulating a total of 3 BU at 465 GPM = 2,670 psi, 100 RPM = 19K ft-lbs TQ. reciprocating 90' and
racking a stand back every BU to 19,106'. PU = 230, SO = 0K & ROT = 130K.
,TIH from 19,109' to 19,386' at 350 GPM = 1,480 psi, 60 RPM = 17K ft-lbs TQ. Pump 30 bbls hi-vis spacer,
25 bbls 8.45 ppg vis brine, 30 bbls SAPP pill #1, 25 bbls brine, 30 bbls SAPP pill #2, 25 bbls brine, 30 bbls
SAPP pill #3 then 30 bbls high vis spacer. Displace with 1,576 bbls of 8.45 ppg viscosified brine with 3%
lubes (1.5% 776 and 1.5% LoTorq) at 5 BPM = 1,040 psi (ICP), 110 RPM = 15K ft-lbs TQ & 27 BPM = 810
psi (FCP), 110 RPM = 21K ft-lbs TQ. Shut down the pumps with clean 8.45 ppg viscosified brine to
surface. Obtain passing PST: 2.9, 2.9 & 2.9 seconds per 1L sample. ,Monitor the wellbore pressure with
MPD choke 3 times 5 minutes each = 18, 2 & 0 psi. EMW = 8.5 ppg. Obtain new SPRs. Wash and ream to
TD.
SimOps: Clean pit #3 and load 8.45 ppg 3% lube brine in pits #3 & 4.
,BROOH from 19,386' to 18,325' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight
spots. Rack back 7 stands HWDP on DS then laying down DP in the mouse hole.
500 GPM = 1,910 psi, 120 RPM = 18K ft-lbs TQ, max gas = 201 units. Loss rate = 15-25 BPH.
,BROOH from 18,325' to 16,327' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight
spots. Laying down DP in the mouse hole.
450 GPM = 1,570 psi, 110 RPM = 18K ft-lbs TQ, max gas = 296 units. Loss rate = 10-20 BPH.
,BROOH from 16,327' to 13,375' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight
spots. Laying down DP in the mouse hole.
450 GPM = 1,490 psi, 110 RPM = 15K ft-lbs TQ, max gas = 102 units. Loss rate = 5-10 BPH.
10/20/23
BROOH from 13,375' to 10,470' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight
spots. Laying down DP in the mouse hole.
450 GPM = 1,490 psi, 110 RPM = 14K ft-lbs TQ, max gas = 79 units. Loss rate = 5-10 BPH. BROOH from
10,470' to 7,857' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying
down DP in the mouse hole.
At 7,798' experienced a pack off with 410 psi pressure increase, ECD spike to 12.0 ppg and increase in
losses. ,BROOH from 7,857' to 6,999' pulling 5-10 minutes/stand slowing as needed to clean up
465 GPM = 1,170 psi, 120 RPM = 5K ft-lbs TQ, max gas = 327 units. Loss rate = 5-15 BPH. Slow rotary to
30 RPM while pulling into the shoe from 6,999' to 6,870'. 465 GPM = 1,170 psi, 30 RPM = 3-5K ft-lbs TQ.
Observed 5-10K drag. Lost a total of 398 bbls while BROOH. ,Pump 30 bbl hi-vis sweep at 450 GPM =
1,110 psi, 80 RPM = 5K ft-lbs TQ reciprocating 60' and circulate the casing clean with 2 BU. Sweep back
,PU to 6,811'. Monitor for pressure build with MPD 3 times at 5 minutes each = 10, 1 & 0 psi. ,Phase 3
weather. Circulate at 3 BPM = 270 psi. MW = 9.1+ ppg in & 9.2 ppg out. Obtain passing PST: 2.4, 2.3 &
2.3 seconds per 1L sample. ,Shut down the pump and blow down the top drive. Monitor for pressure
Still Phase 2 weather. ,PJSM. Remove RCD bearing and install the MPD riser. Fill riser and check for leaks
- none. ,POOH laying down DP from 6,811' to 6,333'. PU = 140K & SO = 110K. Pump dry job and blow
down the top drive. Drop 2.45" OD drift on 100' of wire. ,TOOH from 6,333' to 247'. Monitor the well for
flow at the HWDP - well on a slight vac.
10/21/23
LD HWDP and jars. Recovered drift. LD NMFC and float sub to 120'. Rig went dark at 07:20 and on
generators. LD remaining NMFC and float sub to 91'. Download MWD data and LD remaining BHA. Bit
grade = 1-1-CT-T-X-I-NO-TD. Normail wear on the BHA from drilling and BROOH. Clear and clean the rig
floor. Remove split bushings and install master bushings. Mobilize casing equipment, centralizers,
crossovers to the rig floor. RU double stack tongs and elevators. MU crossover to FOSV and MU safety
joints. Static loss rate = 4 BPH. PJSM with all parties involved. PU round nose float shoe on 4 1/2''
crossover joint (H625 box x BTC pin) to 40'. RIH with Cal IV 4-1/2", 13.5#, L-80, Hydril 625, 100-micron
screens per tally from 40' to 9,795'. Torque to 9,600 ft-lbs with Doyon double stack tongs and verify MU
mark. PU = 130K & SO = 77K. Loss rate = 2 BPH. Rig back on high-line power at 15:14 hours. ,MU 5-1/2"
EZGO HT box x 4-1/2" H625 pin crossover. Change handling equipment to 5-1/2" and changeout tong
heads. RIH with Delta 5-1/2", 20#, L-80, EZGO HT, 100-micron screens per tally from 9,795' to 12,676'.
Torque to EZGO HT to 8,850 ft-lbs & JFE Bear to 7,400 ft-lbs with Doyon double stack tongs. PU = 155K
& SO = 980K. Lost 19.5 bbls while running liner. Break down safety joints. Change elevators to 5" DP. RD
double stack tongs. MU Baker SLZXP liner top packer to 12,718' then RIH with one stand of DP to
12,810'. Pump 10 bbls at 3 BPM = 220 psi to ensure clear flow path through the packer. Attempt to
obtain rotational parameters. Only would rotate slowly at 7K ft-lbs TQ limit while moving pipe. Blow
down the top drive.
10/22/23
TIH with 4-1/2" x 5-1/2" screen liner on 5" DP from 12,810' to 18,805'. TIH on 5" HWDP from 18,805' to
tag on TD at 19,386' with 10K down. PU = 220K & SO = 80K. Lay down 2 singles and break circulation at
3 BPM = 470 psi. Drop 1.125" phenolic setting ball. RU 10' pup, FOSV, side entry sub, 10' pup joint &
circulating equipment. PJSM. PT lines to 4,300 psi - good test. Place liner in tension at 19,386' set
depth. Pump ball down with 30 bbl hi-vis sweep at 4 BPM = 730 psi. Slowed to 2.5 BPM = 490 psi. Ball
on seat on time. Pressure up to 2,200 psi & hold for 5 minutes. SO to 40K to confirm set. Pressure up &
observe release at 2,750 psi. Hold for 5 minutes. Continue to pressure up with rig pump and observe
ball seat shear at 4,014 psi. PU & observe travel at 155K to confirm release. Top of liner at 6,683'. Open
kill line & purge air. Close the annular & PT the IA/LTP to 1,500 psi for 10 minutes charted - good test.
Bleed off the pressure & open the annular. Blow down & RD circulating equipment. Pump out of the
LTP at 2 BPM = 300 psi. Once the liner running tool is out of the LTP bring pumps up to 500 GPM =
1,520 psi and circulate the sweep out of the hole. Sweep back on time with 0% increase. Flow Check
well- static. ,Pump 10.0 ppg dry job and blow down the top drive. POOH laying down 5" HWDP and 5"
DP from 6,683' to 29'. Lay down liner running tool.
Lost 32 bbls while POOH.
Wellname: MP I-31
API Number: 50-029-23763-00-00
Well Permit Number: 223-066
Date Summary
10/22/23
See drilling report for details,MU the stack washing tool, flush the BOP stack and LD the stack washing
tool. Pull the wear ring. Blow down the top drive. Perform dummy casing hanger run. Mobilize and RU
Doyon casing equipment. MU crossover to FOSV. PJSM. Static loss rate = 1 BPH. PU 7" tieback seal
assembly and RIH with 7", 26#, L-80, TXP-BTC from 18' to 3,621'. Torque to 14,750 ft-lbs with Doyon
double stack tongs.
10/23/23
RIH with 7", 26#, L-80, TXP-BTC from 3,621' to no-go at 6,683' with 10K down. Close annular and
pressure up to 200 psi to ensure seal are engaged into the tieback sleeve. Torque to 14,750 ft-lbs with
Doyon double stack tongs. Lost 35.5 bbls while running casing. Lay down 3 joints (167,166 & 165). MU
2.82' pup jiont and MU joint #167. MU the mandrel casing hanger with landing joint. Land the casing
hanger 1.12' off no-go. Change to DP elevators. MU crossover, side entry sub and 10' DP pup joint. RU
cement hose and circulating equipment. Flood lines. PT to 1,000 psi - good test. PU and expose port.
Break circulation confirming returns. Close the annular and reverse circulate confirming returns. PJSM.
Reverse circulate 129 bbls of 9.1 ppg corrosion inhibited brine at 5 BPM = 1,300 psi (ICP) & 1,000 psi
(FCP) followed by 71 bbls diesel at 4 BPM = 900 psi (ICP) & 720 psi (FCP). Strip through the annular,
closing the ports and land the casing hanger with 72K on the hanger (1.12' off no-go). Bleed off the
pressure and drain the BOP stack. Blow down and RD the circulating lines and equipment. Lay down the
landing joint. MU 2 joints of 5" HWDP and pack-off running tool. Install 7" pack-off and RILDS. PT pack-
off void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good test. LD HWDP and pack-off
running tool. Rig up injection line and test equipment. Flood lines. PT 7" x 9-5/8" OA to 1,500 psi for 30
minutes charted - good test. Pumped 2.6 bbls. Bleed off pressure. RD circulating and test
equipment.,Mobilize 4-1/2" handling equipment, double stack, spooling unit with Tec wire, job box,
cannon clamps, crossovers, pup joint and tubing hanger. MU crossover to 3-1/2" TIW. Static loss rate =
1 BPH. PJSM. PU mule shoe joint and RIH on 4-1/2", 12.6#, L-80, TXP-BTC tubing to 1,149'. Torque to
6,170 ft-lbs with Doyon double stack tongs. MU XN nipple, 1 joint, Baker Premier Packer, 1 joint, X
nipple, 1 joint and gauge carrier. MU Zenith gauge and Tec wire. MU 1 joint and sliding sleeve with
covered ports for Tec wire bypass to 1,359'. RIH on 4-1/2", 12.6#, L-80, TXP-BTC tubing from 1,359' to
6,663' spooling TEC wire, installing cannon clamps per tally and checking electrical continuity of the TEC
wire every 1,000'. Torque to 6,170 ft-lbs with Doyon double stack tongs. PU = 88K & SO = 73K
Hilcorp Alaska, LLC
HEC Composite
Well Operations Summary
10/24/23
MU the tubing hanger with BPV installed and 4-1/2" TC-II landing. Terminate the Tec wire and feed
through the tubing hanger. Land the tubing hanger with the mule shoe at 6,696' with 35K on the
hanger. RILDS. Lay down the landing joint. PU = 98 & SO = 75K. RD and demobilize completion running
equipment. Clear and clean the floor. PJSM. Pull the MPD riser. ND the BOP stack and rack back on the
stump. Install CTS plug into the BPV. Mobilize the tree into the cellar. NU the tubing head adapter and
tree. PT the tubing hanger void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good tests. RU,
fill the tree with water and purge the air. PT the tree to 250/5,000 psi - good test.
Obtain final Zenith gauge readings: Tubing = 1,580.0 psi, 72.7°F & 19.3 volts,RD testing equipment.
Drain the tree through the wing valve. Pull the CTS plug. Check for pressure under the BPV- the well is
on a slight vac. Pull the BPV with dry rod. RU the squeeze manifold to reverse circulate. Fill and PT lines
to 4,000 psi - good test.
Rig on generator power at 16:30 hours. PJSM. Reverse circulate 163 bbls of 9.1 ppg of corrosion
,Check the tubing for pressure and had 150 psi. Likely ballooning from fluid loss during reverse
circulating. Mobilize the lubricator extension to location. Close the master valve, bleed off the pressure
and drain the tree through the wing valve. Set the 1-7/8" ball & rod on top of the master valve. Install
the lubricator extension. Open the master valve dropping the ball & rod allowing it to gravitate to seat.
Close the master valve and RD the lubricator extension.
,Pressure up on the tubing to 2,000 psi and hold for 5 minutes. Continue to pressure up to 3,000 psi
setting the Premier packer at 2,390 psi and hold for 5 minutes. Pressure up and PT the tubing to 3,700
psi for 30 minutes - good test. Bleed the tubing to 2,000 psi. PT the 4-1/2" x 7" annulus to 3,600 psi for
30 minutes charted - good test. Bleed the IA and tubing to 0 psi. Secure the tree. Blow down and RD
the squeeze manifold and circulating lines. Clean the cellar box. Rig welder cut off the mouse hole
extension and seal weld. Blow down and RD rig floor service lines.
Rig released at midnight.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
108
1
1
1
54
1
X Yes No X Yes No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns ?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns ?Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
1.16
10/11/2023 37
Spud Mud
EconoCem Type I/II 624 2.35
HalCem Type I/II 400 1.16
5
2,271.48
Casing 9 5/8 47.0 L-80 TXP Tennaris 2,215.13 2,271.48 56.35
2,289.17 2,286.33
Casing Pup Joint 9 5/8 40.0 L-80 TXP Tennaris 14.85 2,286.33
12.83 2,302.00 2,289.17
ES Cementer 10 3/4 TXP Halliburton 2.84
Casing Pup Joint 9 5/8 40.0 L-80 TXP Tennaris
6,746.91
Casing 9 5/8 40.0 L-80 TXP Tennaris 4,444.91 6,746.91 2,302.00
6,789.00 6,748.30
Baffle Adapter 10 3/4 TXP Halliburton 1.39 6,748.30
1.30 6,790.30 6,789.00
Casing 9 5/8 40.0 L-80 TXP Tennaris 40.70
Float Collar 10 3/4 TXP Innovex
84 total 9-5/8" x 12-1/4" bow spring centralizers ran. Two in shoe joint w/ stop rings 10' from each end. One floating
on joint #2. One each with stop rings mid-joint on joint #3 & #4. One each on joints #5 to #21, every other joint to #45
then every third joint to #102. One each on joints #104 to #108. One each with stop rings on pup joints above and
below ES cementer. One each on joints #109 to #113 then every third joint #116 to #158.
Casing 9 5/8 40.0 L-80 TXP Tennaris 82.10 6,872.40 6,790.30
www.wellez.net WellEz Information Management LLC ver_04818br
3.2
Ftg. Returned
Ftg. Cut Jt. Ftg. Balance
No. Jts. Delivered No. Jts. Run
Length Measurements W/O
Threads
Ftg. Delivered Ftg. Run
34.10 RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
12 261
HES ES Cemente Closure OK
56
ArcticCem Type I/II
Type
HalCem Type I/II 270
Tuned Spacer
744 2.88
Stage Collar @
60
Bump press
100
233
6,874.006,879.00
CEMENTING REPORT
Csg Wt. On Slips:100,000
Spud Mud
22:56 10/10/2023 2,289
2289.17
15.8 82
Bump press
Returns to surface
Bump Plug?
Yes
3
9.4 5.5 148.5/147.5
503/506
1250
34
Rig
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
550
9.4 7
1700
10
10.7 388 6.5
97.24
650
Bump Plug?
Csg Wt. On Hook:330 Type Float Collar:Innovex No. Hrs to Run:17.5
9 5/8 47.0 L-80 TXP Tennaris
TXP Innovex 1.60 6,874.00 6,872.40
23.52 56.35 32.83
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP I-31 Date Run 9-Oct-23
CASING RECORD
County State Alaska Supv.D. Yessak / J. Vanderpool
6,790.30
Floats Held
408.9 787
267 520
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 6874 FC @ Top of Liner
SE
C
O
N
D
S
T
A
G
E
Rig
13:33
Returns to surface
374.4 467.1 24.76
Casing (Or Liner) Detail
Shoe
Cut joint
10 3/4
David Douglas Hilcorp Alaska, 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:
Date: 11/15/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU I-31
PTD: 223-066
API: 50-029-23763-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (10/05/2023 to 10/19/2023)
x EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL Geosteering Subfolders:g
Please include current contact information if different from above.
PTD: 223-066
T38131
11/16/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.11.16
09:04:34 -09'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT I-31
JBR 12/05/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
Tested with 4.5", 5", & 7" Test joints. All tests were 250/3000. All LEL and H2s alarms tested good. Tested 3.5" IF & 4.5 "IF
TIW and Dart valves. Back up Nitrogen bottles 18 @ 952 average. Fail/pass on upper IBOP/Kelly valve, Functioned and
passed retest.
Test Results
TEST DATA
Rig Rep:J. Hansen / N. HamiltonOperator:Hilcorp Alaska, LLC Operator Rep:D. Yessak / J. Vanderpool
Rig Owner/Rig No.:Doyon 14 PTD#:2230660 DATE:10/12/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopJDH231014083848
Inspector Josh Hunt
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 6
MASP:
1340
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 FP
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 2 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8"P
#1 Rams 1 4-1/2"x7"P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 2 3-1/8" 5M P
HCR Valves 2 3-1/8" 5M P
Kill Line Valves 2 3-1/8" 5M P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3050
Pressure After Closure P1650
200 PSI Attained P46
Full Pressure Attained P188
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@1963
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P12
#1 Rams P7
#2 Rams P7
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9
9 9 9 9
9
9
9
FP
Fail/pass on upper IBOP/Kelly valve,
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-31
Hilcorp Alaska, LLC
Permit to Drill Number: 223-06
Surface Location: 2338' FSL, 3891' FEL, Sec. 33, T13N, R10E, UM, AK
Bottomhole Location: 426' FSL, 135' FEL, Sec. 17, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of August 2023. 14
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.14 14:32:12
-08'00'
1a.
Contact Name:Nathan Sperry
Contact Email:nathan.sperry@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8450
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
5
21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated
from without prior written approval.
Drill
Type of Work:
Redrill
Lateral
1b.Proposed Well Class:Exploratory - Gas
5
Service - WAG
5
1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple Zone Exploratory - Oil
Gas Hydrates
Geothermal
Hilcorp Alaska, LLC Bond No. 22224484
11.Well Name and Number:
MPU I-31
TVD:19726'4189'
12. Field/Pool(s):
MD:
ADL 025906, 025517 & 025515
88-004 September 10, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
2338' FSL, 3891' FEL, Sec. 33, T13N, R10E, UM, AK
1626' FNL, 2165' FEL, Sec. 32, T13N, R10E, UM, AK
Kickoff Depth:250 feet
Maximum Hole Angle: 95 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:1734 1340
17.Deviated wells:16.
Surface: x-y- Zone -551480 6009453 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
67.0'
33.3'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
2041'
Surface
3937'
19.PRESENT WELL CONDITION SUMMARY
Production
Surface
Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements
Shallow Hazard Analysis
55
Commission Use Only
See cover letter for other
requirements:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No
H2S measures Yes No
Spacing exception req'd: Yes No
Mud log req'd: Yes No
Directional svy req'd: Yes No
Inclination-only svy req'd: Yes No
Other:
Date:
Address:
Location of Well (State Base Plane Coordinates - NAD 27):
129.5#
6875'12851'
50-
Intermediate
Conductor/Structural
Single Zone
Service - Disp
No YesPost initial injection MIT req'd:
No Yes 5
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
426' FSL, 135' FEL, Sec. 17, T13N, R10E, UM, AK
Time v. Depth Plot555 5Drilling Program
3653'
Stg 1 L - 673 sx / T - 268 sx
(To be completed for Redrill and Re-Entry Operations)
8-1/2"
7"
L-8020#/13.5#5-1/2"x4-1/2"
9-5/8"
3947'
12-1/4"
7030'Uncemented Tieback
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stratigraphic Test
Development - Gas Service - Supply
Coalbed Gas
Shale Gas
2.Operator Name:5.Bond Blanket 5 Single Well
3.
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
6. Proposed Depth:
7. Property Designation (Lease Number):
8. DNR Approval Number:13.Approximate spud date:
9.Acres in Property: 14. Distance to Nearest Property:
Location of Well (Governmental Section):
4b.
7659
609'
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
12-1/4"
Tieback
9-5/8" 47#
40#
26#
L-80
L-80
L-80 TXP
TXP
TXP
2500'
4525'
7030'
Surface
2500'
Surface
2500'
7025'
19726'
2041'
3947'
4189'
Stg 1 L - 611 sx / T - 395 sx
Uncemented Screen Liner
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured):
Casing Length Size MD
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
150'150'Driven 20"X-52 150'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
MILNE POINT FIELD
SCHRADER BLUFF OIL POOL
EZGO HT /
Hyd 625
7.18.2023
By Grace Christianson at 8:11 am, Jul 19, 2023
Drilling Manager
07/18/23
Monty M
Myers
1340
029-23763-00-00
A.Dewhurst 11AUG2023
* Approved for reverse circulating jet pump.
*SSV's high and low trip pressures approved as described.
* SSV closure on IA will initiate closure on SSV on
production tubing within 2 minutes and visa versa.
* 9-5/8" Casing test and FIT to AOGCC upon completing FIT.
BOPE test to 3000 psi. Annular to 2500 psi.
DSR-7/19/23MGR20JULY2023
223-066
GCW 08/14/2023
JLC 8/14/2023
08/14/23
08/14/23
Brett W. Huber, Sr.Digitally signed by Brett W. Huber,
Sr.
Date: 2023.08.14 14:32:26 -08'00'
Milne Point Unit
(MPU) I-31
Application for Permit to Drill
Version 1
7/12/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 5-1/2” x 4-1/2” Screened Liner ........................................................................................ 33
17.0 Run 7” Tieback ........................................................................................................................ 38
18.0 Run Upper Completion – Jet Pump ........................................................................................ 41
19.0 Doyon 14 Diverter Schematic .................................................................................................. 43
20.0 Doyon 14 BOP Schematic ........................................................................................................ 44
21.0 Wellhead Schematic ................................................................................................................. 45
22.0 Days Vs Depth .......................................................................................................................... 46
23.0 Formation Tops & Information............................................................................................... 47
24.0 Anticipated Drilling Hazards .................................................................................................. 49
25.0 +Doyon 14 Rig Layout ............................................................................................................. 52
26.0 FIT Procedure .......................................................................................................................... 53
27.0 Doyon 14 Rig Choke Manifold Schematic ............................................................................... 54
28.0 Casing Design ........................................................................................................................... 55
29.0 8-1/2” Hole Section MASP ....................................................................................................... 56
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 58
Page 2
Milne Point Unit
I-31 SB Producer
PTD Application
1.0 Well Summary
Well MPU I-31
Pad Milne Point “I” Pad
Planned Completion Type Jet Pump
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 19,726’ MD / 4,189’ TVD
PBTD, MD / TVD 19,726’ MD / 4,189’ TVD
Surface Location (Governmental) 2338' FSL, 3891’ FEL, Sec 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551480, Y=6009453
Top of Productive Horizon
(Governmental)1626' FNL, 2165' FEL, Sec 32, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 547913, Y=6010745
BHL (Governmental) 426' FSL, 135' FEL, Sec 17, T13N, R10E, UM, AK
BHL (NAD 27) X= 549823, Y=6023368
AFE Drilling Days 22
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1340 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1734 psig
Work String 5” 19.5# S-135 NC 50
Doyon 14 KB Elevation above MSL: 33.7 ft + 33.3 ft = 67.0 ft
GL Elevation above MSL: 33.3 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
I-31 SB Producer
PTD Application
2.0 Management of Change Information
Page 4
Milne Point Unit
I-31 SB Producer
PTD Application
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604
8-1/2”5-1/2”
Screens 4.780” 4.653” 6.000” 20 L-80
EZGO HT 9,189 8,830 466
8-1/2”4-1/2”
Screens 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279
Tubing 4-1/2" 3.958”3.833”4.729”12.6 L-80 TXP 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
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
Milne Point Unit
I-31 SB Producer
PTD Application
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 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 nathan.sperry@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 nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Edited By: JNL 7/14/2023
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU I-31
Last Completed: TBD
PTD: TBD
TD =19,726’(MD) / TD =4,189’(TVD)
4
20”
Orig. KB Elev.: 67.00’ / GL Elev.: 33.3’
7”
5
6
9
9-5/8”
1
2
3
5-1/2” XO
4-1/2”
@7870’
See
Screen/
Solid
Liner
Detail
PBTD =19,726’(MD) / PBTD = 4,189’(TVD)
9-5/8” ‘ES’
Cementer
@~2500’
4-1/2”
Shoe @
16,538’
7
8
12
10
4-1/2”
1
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 150’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface ~2,500’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 ~2,500’ 7,025’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 7,030’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.780 6,875’ 10,726’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 10,726’ 19,726’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 6,892’ 0.0152
OPEN HOLE / CEMENT DETAIL
20” Driven
12-1/4"Stg 1 Lead – 611 sx / Tail – 395 sx
Stg 2 Lead – 673 sx / Tail 268 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 7,340’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 5,555’ Haliburton X-Profile Sliding Sleeve (opens down) 2.813”
3 5,565’ Zenith Ported Pressure Sub 2.913”
4 5,595' Baker Retrievable Premier Packer 3.870”
5 5,625’ XN Nipple, 3.813” Packing Bore, 3.725” No-Go 2.750”
6 6,875’ Mule Shoe Joint 3.958”
7 6,875’ SLZXP Liner Top Packer 6.190”
8 6,885’ 7” H563 x 5.5” EZGO HT XO 4.810”
9 10,726’ 5-1/2” x 4-1/2” XO 3.920”
10 19,726’ Shoe 3.970”
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2”
4-1/2”
Page 7
Milne Point Unit
I-31 SB Producer
PTD Application
7.0 Drilling / Completion Summary
MPU I-31 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. I-31 is part of a
multi well program targeting the Schrader Bluff sand on I-pad
The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the top of the Schrader Bluff
OA sand. An 8-1/2” lateral section will be drilled and completed with a 5-1/2” x 4-1/2” liner. The well will
be produced with a jet pump.
Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately September 10, 2023, pending rig schedule.
Surface casing will be run to 7,025’ MD / 3,947’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run 5-1/2” x 4-1/2” production liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
Page 8
Milne Point Unit
I-31 SB Producer
PTD Application
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-31. 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:
x None
Page 9
Milne Point Unit
I-31 SB Producer
PTD Application
Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 10
Milne Point Unit
I-31 SB Producer
PTD Application
9.0 R/U and Preparatory Work
9.1 I-31 will utilize a newly set 20” conductor on I-pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
Page 11
Milne Point Unit
I-31 SB Producer
PTD Application
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
Page 12
Milne Point Unit
I-31 SB Producer
PTD Application
10.4 Rig & Diverter Orientation:
x May change on location
Page 13
Milne Point Unit
I-31 SB Producer
PTD Application
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Use GWD until MWD surveys are clean and then swap to MWD.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled.
x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100-
2,400’ TVD (just below permafrost). Be prepared for hydrates:
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
Page 14
Milne Point Unit
I-31 SB Producer
PTD Application
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid
will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with
a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate zone
PVT System: 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, and mud
loggers office.
Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total)
can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore.
Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to
reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of
the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with
caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Page 15
Milne Point Unit
I-31 SB Producer
PTD Application
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
Page 16
Milne Point Unit
I-31 SB Producer
PTD Application
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.5” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” 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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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface
x Ensure drifted to 8.525”
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12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.11 Displacement calculation:
See calculation in step 13.8
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
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool.
13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
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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13.15 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.17 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.19 Fill surface lines with water and pressure test.
13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.21 Mix and pump cmt per below recipe for the 2
nd stage.
13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.25 Displacement calculation:
2500’ x 0.0732 bpf = 183.0 bbls mud
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
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13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.27 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.28 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
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 nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
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” VBRs
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test 4-1/2” x 7” rams with 4-1/2” and 7” test joints
x Test 2-7/8” x 5” rams with the 4-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 8.9 ppg FloPro for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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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.
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.
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
Email casing test and FIT digital data to AOGCC upon completion. email: melvin.rixse@alaska.gov
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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 FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OA 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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x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OA Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x I-19L1 has a clearance factor of 0.009. I-19L1 is a reservoir abandoned leg
(abandoned 4/17/2020 via coil cement job) from a Schrader well. There is no HSE
risk due to a collision.
x I-24 WP02 has a clearance factor of 0.652. This is a plan that will not be drilled
prior to I-31. There is no HSE risk.
x J-09Ahas a 0.355 clearance factor. This well has been reservoir P&A’d.
x J-26, J-26L2, J-26PB1, J-26 PB2 have clearance factors ranging from 0.366 to 0.866.
This multi-lateral has been P&A’d with cement. There is no HSE risk associated
with a collision.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
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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
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
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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16.0 Run 5-1/2” x 4-1/2” Screened Liner
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them
slick.
16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” screened liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 5-1/2” crossover installed on bottom, TIW valve in open
position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 5-1/2” screened liner.
x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” screened 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.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 13.5# Hydril 625 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.
16.3 Run 4-1/2” screened production liner until XO point for 5-1/2” screens (planning 2,000’ of 5-
1/2” on top of 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 Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids)
x Install screen joints as per the Running Order (From Completion Engineer post TD).
o Do not place tongs or slips on screen joints
o Screen placement ±40’
o The screen connection is 4-1/2” 13.5# Hydril 625
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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5-1/2” 20# L-80 EZGO HT Torque
OD Minimum Optimum Maximum
5-1/2 6,997 ft-lbs 10,728 ft-lbs
4-1/2” 13.5# L-80 Hydril 625 Torque
OD Minimum Optimum Maximum
4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. 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 4-1/2” liner.
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 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.
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.
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.
Page 37
Milne Point Unit
I-31 SB Producer
PTD Application
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 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 38
Milne Point Unit
I-31 SB Producer
PTD Application
17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, TXP
=Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs
Page 39
Milne Point Unit
I-31 SB Producer
PTD Application
Page 40
Milne Point Unit
I-31 SB Producer
PTD Application
17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
Page 41
Milne Point Unit
I-31 SB Producer
PTD Application
18.0 Run Upper Completion – Jet Pump
18.1 RU to run 4-1/2”, 12.6#, L-80 TXP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, TXP x XT-39 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 RH with the following 4-1/2” JP completion (confirm tally with Operations
Engineer):
x WLEG/Mule shoe
x XX joints, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” XN profile (3.750” no-go), 4-1/2”, TXPM (RHC plug body installed Below
70 degrees)
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover Pup, 4-1/2” TC-II Box x 4-1/2” TXP Pin
x Retrievable Packer, Baker, 4-1/2”, 12.6#, L-80, TC-II ( Set Below 70 degrees ~4760 MD 67
degrees)
x Crossover Pup, 4-1/2”, TXP Box x 4-1/2”, TC-II Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin
x Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x Sliding Sleeve, 4-1/2”, 12.6#, L-80 TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x XXX joints, 4-1/2”, 12.6#, L-80, TXP
18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unused
control line ports are dummied off.
Page 42
Milne Point Unit
I-31 SB Producer
PTD Application
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 diesel freeze protect
to 2,500’ MD.
18.11 Drop the ball & rod.
18.12 Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30
minutes (charted).
18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,500 psi for 30 minutes (charted). Bleed
both the IA and tubing to 0 psi.
18.14 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.15 RDMO
18.16 Post-rig SSV set point verification:
x Power fluid SSV high pressure trip will not exceed 3650 psi
x Power fluid SSV low pressure trip will be set to 50 percent of header pressure
x Production SSV high pressure trip not to exceed 650 psi
x Production SSV low pressure trip not to be below 75 psi
Page 43
Milne Point Unit
I-31 SB Producer
PTD Application
19.0 Doyon 14 Diverter Schematic
Page 44
Milne Point Unit
I-31 SB Producer
PTD Application
20.0 Doyon 14 BOP Schematic
Page 45
Milne Point Unit
I-31 SB Producer
PTD Application
21.0 Wellhead Schematic
Page 46
Milne Point Unit
I-31 SB Producer
PTD Application
22.0 Days Vs Depth
Page 47
Milne Point Unit
I-31 SB Producer
PTD Application
23.0 Formation Tops & Information
MPU I-31 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1807 1740 2101 795 8.46
SV1 2006 1939 2440 883 8.46
UG4 2297 2230 2935 1011 8.46
UG_MB 3497 3430 5063 1538 8.46
SCHRADER NB 3737 3670 5626 1644 8.46
SCHRADER OA 3940 3873 6931 1733 8.46
Page 48
Milne Point Unit
I-31 SB Producer
PTD Application
Page 49
Milne Point Unit
I-31 SB Producer
PTD Application
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
Gas hydrates are generally not seen on I-pad. Remember that hydrate gas behaves differently from a gas
sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout
at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the
hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while
drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can
increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as
cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-
pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove
hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
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.
Page 50
Milne Point Unit
I-31 SB Producer
PTD Application
H2S:
Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I-
04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009.
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 51
Milne Point Unit
I-31 SB Producer
PTD Application
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. Maint. 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:
There are six planned fault crossings for I-31. The maximum expected throw for a fault is 62’ on the
fault crossed in the heel of the well.
H2S:
Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I-
04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific AC:
x I-19L1 has a clearance factor of 0.009. I-19L1 is a reservoir abandoned leg
(abandoned 4/17/2020 via coil cement job) from a Schrader well. There is no HSE
risk due to a collision.
x I-24 WP02 has a clearance factor of 0.530. This is a plan that will not be drilled
prior to I-31. There is no HSE risk.
x J-09A has a 0.361 clearance factor. This well has been reservoir P&A’d.
x J-26, J-26L2, J-26PB1, J-26 PB2 have clearance factors ranging from 0.366 to 0.866.
This multi-lateral has been P&A’d with cement. There is no HSE risk associated
with a collision.
Page 52
Milne Point Unit
I-31 SB Producer
PTD Application
25.0 +Doyon 14 Rig Layout
Page 53
Milne Point Unit
I-31 SB Producer
PTD Application
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 54
Milne Point Unit
I-31 SB Producer
PTD Application
27.0 Doyon 14 Rig Choke Manifold Schematic
Page 55
Milne Point Unit
I-31 SB Producer
PTD Application
28.0 Casing Design
Page 56
Milne Point Unit
I-31 SB Producer
PTD Application
29.0 8-1/2” Hole Section MASP
Page 57
Milne Point Unit
I-31 SB Producer
PTD Application
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 58
Milne Point Unit
I-31 SB Producer
PTD Application
31.0 Surface Plat (As Built) (NAD 27)
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-6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000
West(-)/East(+) (1500 usft/in)
MPU I-31 wp07 tgt22
MPU I-31 wp07 tgt21
MPU I-31 wp07 tgt19
MPU I-31 wp07 tgt18
MPU I-31 wp07 tgt16
MPU I-31 wp07 tgt14
MPU I-31 wp07 tgt13
MPU I-31 wp07 tgt12
MPU I-31 wp07 tgt10
MPU I-31 wp07 tgt8
MPU I-31 wp07 tgt7
MPU I-31 wp07 tgt5
MPU I-31 wp07 tgt3
MPU I-31 wp07 tgt1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
1
0
0
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1
5
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1
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3000
32503500
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4000
4189
MPU I-31 wp09
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 4º/100' : 500' MD, 499.29'TVD
Start Dir 3.8º/100' : 1000' MD, 984.53'TVD
End Dir : 1909.31' MD, 1694.14' TVD
Start Dir 4º/100' : 2923.68' MD, 2290.37'TVD
End Dir : 3028.46' MD, 2351.24' TVD
Start Dir 4º/100' : 3322.65' MD, 2519.98'TVD
End Dir : 3500.81' MD, 2621.66' TVDStart Dir 4.25º/100' : 4117.44' MD, 2970.89'TVD
End Dir : 6193.49' MD, 3870.53' TVD
Start Dir 2.5º/100' : 6443.49' MD, 3901'TVD
End Dir : 6596.02' MD, 3915.8' TVD
Fault A
Begin Geosteering
Total Depth : 19726.43' MD, 4189' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3946.75 3879.75 7025.00 9-5/8 9 5/8" x 12 1/4"
4189.00 4122.00 19726.43 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-31
Wellbore: MPU I-31
Plan: MPU I-31 wp09
WELL DETAILS: Plan: MPU I-31
33.30
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
6009452.86 551479.58 70° 26' 11.6722 N 149° 34' 49.0001 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-31, True North
Vertical (TVD) Reference:MPU I-31 as built RKB @ 67.00usft
Measured Depth Reference:MPU I-31 as built RKB @ 67.00usft
Calculation Method:Minimum Curvature
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
MILNE POINT
SCHRADER BLFF OIL
X
223-066
MPU I-31
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21
C
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v
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-
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9
-
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/
8
"
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u
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22
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w
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9
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/
8
"
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23
C
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&
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24
A
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q
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k
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g
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p
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T
h
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a
g
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s
w
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l
.
25
I
f
a
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h
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.
26
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v
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27
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28
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r
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3
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p
s
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.
29
B
O
P
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,
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h
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m
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s
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.
30
B
O
P
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p
r
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s
s
r
a
t
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n
g
a
p
p
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p
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;
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p
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)
Ye
s
31
C
h
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p
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w
/
A
P
I
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P
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5
3
(
M
a
y
8
4
)
Ye
s
32
W
o
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k
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t
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w
n
Ye
s
33
I
s
p
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n
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2
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g
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s
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b
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T
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l
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O
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D
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v
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p
m
e
n
t
w
e
l
l
.
34
M
e
c
h
a
n
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c
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c
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n
d
i
t
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n
o
f
w
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w
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h
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n
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v
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f
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d
(
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v
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c
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w
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l
l
o
n
l
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)
No
H
2
S
h
a
s
b
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n
m
e
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s
u
r
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d
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n
M
P
U
I
-
0
4
A
(
3
6
p
p
m
)
35
P
e
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
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d
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m
e
a
s
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r
e
s
Ye
s
P
o
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s
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b
l
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v
e
r
p
r
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s
s
u
r
e
i
n
U
g
n
u
/
S
c
h
r
a
d
e
r
B
l
u
f
f
36
D
a
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
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s
s
u
r
e
z
o
n
e
s
NA
37
S
e
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
38
S
e
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
C
o
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
AD
D
Da
t
e
8/
1
0
/
2
0
2
3
Ap
p
r
MG
R
Da
t
e
8/
1
0
/
2
0
2
3
Ap
p
r
AD
D
Da
t
e
8/
1
0
/
2
0
2
3
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
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n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
GC
W
0
8
/
1
4
/
2
0
2
3
JL
C
8
/
1
4
/
2
0
2
3
