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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Friday, September 8, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Kam StJohn
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
M-63
MILNE PT UNIT M-63
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 09/08/2023
M-63
50-029-23748-00-00
223-016-0
W
SPT
4038
2230160 1500
24 24 24 24
INITAL P
Kam StJohn
7/14/2023
This well is a Monobore
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT M-63
Inspection Date:
Tubing
OA
Packer Depth
38 2195 2144 2124IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitKPS230714132956
BBL Pumped:5 BBL Returned:4.9
Friday, September 8, 2023 Page 1 of 1
MILNE POINT FIELD /
SCHRADER BLUFF OIL POOL
Hilcorp Alaska, LLC
By Grace Christianson at 3:05 pm, Jul 10, 2023
Completed
6/2/2023
JSB
RBDMS JSB 071223
GDSR-10/15/23MGR08JUL2023
Drilling Manager
07/10/23
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.07.10 11:46:37 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Revised By: JNL 6/5/2023
SCHEMATIC
Milne Point Unit
Well: MPU M-62
Last Completed: 6/2/2023
PTD: 223-016
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,290’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,290’ 8,750’ 0.0758
5-1/2” Liner solid/slotted 17 / L-80 / JFE Bear 4.892” 8,547’ 11,440’ 0.0232
4-1/2” Liner solid/slotted 13.5 / L-80 / Hyd 625 3.920” 11,440’ 19,800’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 8,557’ 0.0087
OPEN HOLE / CEMENT DETAIL
42” 18 yds Concrete
12-1/4"Stg 1 –Lead 910 sx / Tail 400 sx
Stg 2 –Lead 755 sx / Tail 270 sx
8-1/2” Cementless Injection Liner
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#: 50-029-23748-00-00
Completion Date: 6/2/2023
WELL INCLINATION DETAIL
KOP @ 334’
90° Hole Angle @ 9,542’ MD
TD =19,800’(MD) / TD =4,116’(TVD)
20”
Orig. KB Elev.: 59.3’ / GL Elev.: 25.2’
3-1/2”
6
2
9-5/8”
1
3
See
Slotted
Liner
Detail
7
PBTD =19,798’(MD) / PBTD = 4,116’(TVD)
9-5/8” ‘ES’
Cementer @
2,309’
5-1/2” x
4-1/2”
4/5
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 7,413’ Sliding Sleeve 2.813” X profile, covered ports (opens down) 2.813”
2 7,469’ Zenith Gauge Carrier 2.992”
3 7,528’ XN Nipple, 2.813”, 2.75” No-Go 2.750”
4 8,556’ No Go Locater Sub (2.23’ off No-go) 6.210”
5 8,577’ Bullet Seals – TXP Top Box x Mule Shoe 6.210”
Lower Completion
6 8,547’ 9-5/8” SLZXP Liner Top Packer 6.190”
7 19,798’ Shoe
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 8758’ 4060’ 11440’ 4078’
4-1/2” 11484’ 4080’ 19758’ 4115’
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU M-63 Date:5/20/2023
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Vanderpool / Gruenberg
Csg Setting Depth:8750 TMD 4058 TVD
Mud Weight:9.3 ppg LOT / FIT Press =570 psi
.
LOT / FIT =12.00 Hole Depth =8775 md
Fluid Pumped=1.30 Bbls Volume Back =1.30 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
->1 112 ->890
->2 152 ->16 232
->3 198 ->24 467
->4 249 ->32 760
->5 288 ->40 1046
->6 324 ->48 1355
->7 373 ->56 1680
->8 417 ->60 1857
->9 452 ->64 2036
->10 502 ->68 2208
->11 535 ->72 2398
->12 570 ->76 2567
->13 ->77 2610
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 570 ->0 2610
->1 542 ->5 2580
->2 524 ->10 2568
->3 511 ->15 2560
->4 504 ->20 2551
->5 501 ->25 2544
->6 499 ->26 2543
->7 498 ->27 2542
->8 492 ->28 2540
->9 487 ->29 2540
->10 485 ->30 2539
->11 483 ->
->12 481 ->
->13 478 ->
->14 474
->15 471
->16
0
12
3
456
7
89
101112
0
8
16
24
32
40
48
56
60
64
68
72
76
77
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 102030405060708090
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
)
570542524511504501499498492487485483481478474471
2610 2580 2568 2560 2551 254425432542254025402539
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
Activity Date Ops Summary
5/7/2023 Install diverter tee, surface annular and bell nipple on M-63 with R&P crane. R&P haul in gravel and level pad. Finish up rig maintenance and welding projects. Set
mats around M-63. Lay mats for rig footprint and dance floor. Spot wellhead, tree and spacer spool behind the well. SimOps: Cleanup welding projects areas.
PJSM. Spot the rig and center over well M-63. Shim and level the rig.
5/8/2023 PJSM. Skid the rig floor into drilling position. Secure landings and exhaust stacks on the roof. Work on rig acceptance checklist. Spot auxiliary shacks. Spot the slop
tank, fuel trailer and rock washer. RU service lines to the rig floor. Spot pump house, water tanks and cement silos. Load BHA into the DS pipe shed. NU the diverter
line. Work on rig acceptance checklist. NU the diverter line. Replace drag chain roller. Finish hopper line repair and hydro test - good. Install mouse hole. Torque
surface annular flange to diverter tee. Rig on highline power at 16:00 hours. Work on rig acceptance checklist. Install the riser. Function test drag chain - good.
Mobilize bits and crossover to the rig floor. Perform derrick inspection. Weld holes in the pit floor. Changeout the saver sub. Rig back on generator power at 21:00
per Operations request. Work on rig acceptance checklist. Finish changing the out the saver sub. Inspect the grabber dies - good. Service the top drive. MU and
rack back 6 stands 5" HWDP including jar stand. Start loading the pits with spud mud and rig accepted at 02:30 hours. Perform the diverter function test with 5"
HWDP. The states right to witness was waived by AOGCC inspector Adam Earl on 5/8/2023 at 10:18 hours. Test PVT and flow sensors - good. Knife valve opened
in 15 seconds and the annular closed in 23 seconds. Accumulator Test: System pressure = 3,000 psi. Pressure after closure = 1,850 psi. 200 psi attained in 44
seconds. Full pressure attained in 170 seconds. Nitrogen Bottles - 6 at 1,983 psi (average). Diverter length = 435'. Nearest ignition source = 160' (wellhouse). MU
12-1/4" tricone bit, 8" mud motor with 1.5 AKO, crossover and 1 stand of 5" HWDP. Fill the stack with water and check for leaks - none. PT mud lines to 3,500 psi -
good test. RIH with stand and tag up at 39' MD. Pre-spud meeting with all parties involved. Discussed well objectives and surface hole hazards. Tabletop diverter
drill. Electrician changing out gas sensor above the flow line.
5/9/2023 Electrician continue to change out gas sensor above the flow line. Troubleshoot and calibrate gas sensors on rig floor. Complete and test alarms - good. Clean out
the conductor of ice at 38' to 114' (base of conductor). 390 GPM = 380 psi, 35 RPM = 1K ft-lbs TQ, WOB = 2-5K. Spud well and drill 12-1/4" surface hole from 114'
to 220' (220' TVD). 390 GPM = 380 psi, 40 RPM = 1-2K ft-lbs TQ, WOB = 5-8K. PU = 50K, SO = 55K & ROT = 52K. POOH and lay down conductor cleanout BHA.
Blow down top drive and clear rig floor. Found damaged drill line. PJSM. Slip and cut (double cut) 158' (24 wraps). PJSM. Make up and run in the hole with 12-1/4"
drilling assembly: 12-1/4" Kymera bit, 1.5 deg Sperry TerraForce motor with 12.0" OD sleeve stabilizer, GWD, DM, EWR-M5, in-line stabilizer (10.312" OD) and
TM collar to 99'. Initialize and download MWD tools. MU 3 NM flex collars to 191'. MU crossover and first stand of HWD. Establish drilling parameters, shallow test
MWD and wash to bottom at 220'. No fill encountered. Obtain first Gyro survey at 152'. Drill 12-1/4" surface hole from 220' to 668' (653' TVD). Drilled 448' = 99.6'/hr
AROP. 450 GPM = 1,180 psi, 50 RPM = 2-3K ft-lbs TQ, WOB = 7-10K. PU = 79K, SO = 81K & ROT = 76K. MW = 9.1 ppg, Vis = 278, ECD = 9.98 ppg. Start 3
deg/100' build at 469'. Rig back on highline power at 20:30 hours. Drill 12-1/4" surface hole from 668' to 1,321' (1,291' TVD). Drilled 653' = 108.8'/hr AROP. 450
GPM = 1,290 psi, 60 RPM = 3-9K ft-lbs TQ, WOB = 9-15K. PU = 90K, SO = 90K & ROT = 90K. MW = 9.2 ppg, Vis = 175, ECD = 10.26 ppg, max gas = 33 units.
At 1,224' increase build to 4.3 deg/100' build. Last survey at 1,278.33 MD / 1,254.17 TVD, 24.91 deg INC, 83.36 deg AZM. Distance from WP10 = 9.18, 9.11 high
& 1.17 left.
5/10/2023 Drill 12-1/4" surface hole from 1321' to 2133' (1911' TVD). Drilled 812' = 135.3'/hr AROP. 425-450 GPM = 1,290 psi, 60 RPM = 4-6K ft-lbs TQ, WOB = 7-20K. MW
= 9.4 ppg, Vis = 183, ECD = 10.26 ppg, max gas = 100 units. PU = 104K, SO = 93K & ROT = 99K. BOPF logged at 2098 MD / 1892' TVD. Drill 12-1/4" surface
hole f/ 2133' t/ 2747' (2146' TVD). Drilled 614' = 102'/hr AROP. 450 GPM, 1490 psi, 50 RPM, 5K Tq, WOB 12K. MW = 9.25 ppg, Vis 173, ECD 10.68 ppg, Max
Gas = 323u. PU 100K, SO 84K, ROT 92K. Drill 12-1/4" surface hole f/ 2747' t/ 3604' (2436' TVD). Drilled 857' = 143'/hr AROP. 520 GPM, 1930 psi, 50 RPM, 6-8K
Tq, WOB 12K. MW = 9.35 ppg, Vis 189, ECD 10.73 ppg, Max Gas = 153u. PU 105K, SO 85K, ROT 96K. Sweep @ 2844' back on time, w/ no increase. Top of
UG4 logged @ 2788 MD / 2170 TVD. Drill 12-1/4" surface hole f/ 3604' t/ 4650' (2806' TVD). Drilled 1046' = 174'/hr AROP. 550 GPM, 2240 psi, 80 RPM, 9-12K
Tq, WOB 15K. MW = 9.4 ppg, Vis 107, ECD 10.78 ppg, Max Gas = 141u. PU 120K, SO 85K, ROT 103K. Sweep @ 3800' back on time, w/ no increase. Last
survey at 4502.17' MD / 2752.95' TVD, 68.63 inc, 79.46 azm, 21.51' from plan, 2.91' high and 21.31' left.
5/11/2023 Drill 12-1/4" surface hole f/ 4650' t/ 5445' (3079' TVD). Drilled 797' = 132.8'/hr AROP. 550 GPM, 2210 psi, 80 RPM, 11-14K Tq, WOB 16K. MW = 9.3 ppg, Vis
178, ECD 10.68 ppg, Max Gas = 133u. PU 137K, SO 87K, ROT 107K. Sweep @ 4934' back 200 stks late, w/ 30% increase. Drill 12-1/4" surface hole f/ 5445' t/
6055' (3280' TVD). Drilled 610' = 102'/hr AROP. 550 GPM, 2160 psi, 80 RPM, 11-14K Tq, WOB 10-12K. MW = 9.4 ppg, Vis 114, ECD 10.38 ppg, Max Gas =
108u. PU 148K, SO 88K, ROT 110K. Pre-Treat system w/ 1.25% ScreenKleen in preparation for Ugnu L&M. Sweep @ 5981' back250 stks late, w/ 20% increase.
Drill 12-1/4" surface hole f/ 6055' t/ 6517' (3399' TVD). Drilled 462' = 77'/hr AROP. 550 GPM, 2130 psi, 80 RPM, 12-13K Tq, WOB 5K. MW = 9.3 ppg, Vis 71, ECD
10.26 ppg, Max Gas = 173u. PU 150K, SO 90K, ROT 115K. Drill 12-1/4" surface hole f/ 6517' t/ 7125' (3662' TVD). Drilled 608' = 101'/hr AROP. 550 GPM, 2210
psi, 80 RPM, 15-17K Tq, WOB 10K. MW = 9.4 ppg, Vis 254, ECD 10.85 ppg, Max Gas = 253u. PU 165K, SO 82K, ROT 122K. UG_LA3 logged at 6149' MD /
3311' TVD. Last survey at 7070.30' MD / 3642.63' TVD, 68.47 inc, 39.68 azm, 21.01' from plan, 20.88' high and 2.30' left.
5/12/2023 Drill 12-1/4" surface hole f/ 7125' t/ 7415' (3770' TVD). Drilled 290' = 48.33'/hr AROP. 550 GPM, 2300 psi, 80 RPM, 15-20K Tq, WOB 2-5K. MW = 9.3+ ppg, Vis
140, ECD 10.19 ppg, Max Gas = 183u. PU 185K, SO 75K, ROT 125K. Sweep at 7125' not seen at shakers. 4 deg/100 planned turn to 334 - not getting desired
motor yield, getting 3.0 -3.5 deg/100'. Struggling to hold tool face in hard streaks. Increasing lube concentrations to 0.5%, Lo-Torq. Drill 12-1/4" surface hole f/ 7415'
t/ 7717' (3870' TVD). Drilled 302' = 50.33'/hr AROP. 550 GPM, 2200 psi, 80 RPM, 15-22K Tq, WOB 10-15K. MW = 9.2 ppg, Vis 79, ECD 10.15 ppg, Max Gas =
81u. PU 180K, SO 77K, ROT 125K. Drill 12-1/4" surface hole f/ 7717' t/ 7982' (3923' TVD). Drilled 265' = 44'/hr AROP. 550 GPM, 2210 psi, 80 RPM, 16-19K Tq,
WOB 1-5K. MW = 9.4 ppg, Vis 93, ECD 10.57 ppg, Max Gas = 269u. PU 180K, SO 75K, ROT 124K. Sweep at 7980' not seen at shakers. Drill 12-1/4" surface hole
f/ 7982' t/ 8487' (4030' TVD). Drilled 505' = 84'/hr AROP. 500 GPM, 2040 psi, 80 RPM, 15-20K Tq, WOB 10-12K. MW = 9.3 ppg, Vis 80, ECD 10.77 ppg, Max Gas
= 290u. PU 175K, SO 70K, ROT 115K. SB_NA logged at 7714' MD / 3871' TVD. Last survey at 8402.00' MD / 4020.77' TVD, 81.91 deg inc, 336.99 deg azm,
18.39' from plan, 0.70' Low and 18.37' Right.
50-029-23748-00-00API #:
Well Name:
Field:
County/State:
MP M-63
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
5/9/2023Spud Date:
5/13/2023 Drill 12-1/4" surface hole f/ 8487' t/ 8755' (4058' TVD). Drilled 268' = 67'/hr AROP. 480 GPM, 2040 psi, 80 RPM, 15-20K Tq, WOB 6-8K. MW = 9.5 ppg, Vis 67,
ECD 10.53 ppg, Max Gas = 107u. PU 175K, SO 75K, ROT 122K. Geo called TD at 8755', ~5' below top of the SB_OA. Circulate hole clean with 3x bottoms up
strokes, racking back a stand with each bottoms up f/ 8755' t/ 8555'. 550 GPM, 2160 psi, 60 RPM, 18-22K Tq. Sweep came back 300 stks late with no increase.
MW in/out 9.3/9.3+ Vis in/out 51/86. Run back to TD with no issues and no fill noted on bottom. Monitor well prior to coming out of the hole - static. BROOH from
8755' to 7218' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 2030 psi, 60 RPM = 16-20K ft-bs TQ, ECD= 10.07 ppg,
max gas = 57u. PU = 185K, SO = 80K, ROT = 125K. BROOH from 7218' to 5319' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550
GPM = 1800 psi, 60 RPM = 10-13K ft-bs TQ, ECD= 10.76 ppg, max gas = 55u. PU = 147K, SO = 80K, ROT = 107K. BROOH from 5319' to 2990' pulling 5-10
minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1500 psi, 60 RPM = 6-8K ft-bs TQ, ECD= 9.99 ppg, max gas = 56u. PU = 110K, SO =
85K, ROT = 96K. Loss @ 3-6 BPH.
5/14/2023 BROOH from 2909' to 750' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1250 psi, 60 RPM = 2-4K ft-bs TQ, max gas =
164u. PU = 88K, SO = 88K, ROT = 86K. Loss @ 3-6 BPH. Hole unloaded from base of permafrost to 1250' - lot of sand and clay. Pull out of the hole and rack back
5" HWDP f/ 750' t/ 191'. Lost 91.2 bbls total while BROOH. Lay down flex collars to pipe shed. Download MWD and lay down. Break out bit and lay down motor.
PDC: 1-2-CT-S-X-I-LT-TD, Roller Cone: 1-1-WT-A-E-I-NO-TD. Clear and clean the rig floor. Flush flow line. Mobilize casing running tools to the rig floor. RU Volant
CRT, bail extensions, 9-5/8" handling equipment and casing tongs. M/U crossover to FOSV. PJSM. M/U 9-5/8", 40#, L-80, TXP-BTC shoe track to 170' Baker Lok
connections 1-4 with 21K ft-lbs TQ. Pump through shoe track and check floats - good. HES rep installed top hat above float collar. RIH with 9-5/8", 40#, L-80, TXP-
BTC casing from 170' to 1650'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Loss rate 2 bph. Continue to
RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 1650' to 1670'. String take wt at 1670'. Attempt to work through hard spot 15-40k dn, with no pumps/rotary, no
success. Work string 15-40k dn, with and without rotary and pumps making minor headway, no overpull observed when PU. Notify engineer and discuss options.
Continue working string with varying parameters while prep floor and shed to lay down casing. Start to make steady progress with 5-8 RPM 4-8k Tq, 1 BPM- 70
PSI, 5-10k WOB, 20-80 FPH. ROT casing down to 1730'. Continue ROT casing down f/ 1730' t/ 1898'. 5-8 RPM 2-5k Tq, 1 BPM- 70 PSI, 5k WOB, 100-250 FPH.
Attempt to RIH with no rotary after each connection - Wt stacking up, no success. RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 1898' to 1980'. TQ = 21K ft-lbs
with Volant tool. Seeing 5-20k intermittent drag. Total 16 bbls loss running casing.
5/15/2023 RIH with 9-5/8", 40# casing from 1980' to 2392'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. PU = 115K
& SO = 97K. CBU while RIH slowly f/ 2392' t/ 2475'. Stage pumps up to 6 BPM,230 psi. 12 bbls loss while circulating. RIH with 9-5/8", 40# casing from 2475' to
4033'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. PU = 170K & SO =102K. 8 BPH Losses. RIH with 9-
5/8", 40# casing from 4033' to 4950'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. PU = 175K & SO =
90K. 8 BPH Losses. Stack out wt at 4950'. Attempt to circulate down, 2 BPM 400 psi w/ no success. Stage pumps up to 5 BPM 400 psi, rotate 5 RPM 10k Tq and
attempt to work down w/ no success. Notify engineer and discuss plan forward. Continue attempting to work through varying dn wt and parameters. No Success.
L/D 1 jt and CBU @ 5 BPM, 250 PSI. Reciprocate string 40. Pin on jt laid down and box on jt in slips show significant damage. Jts will be replaced. 9 BBL Loss
while circ. Lay down next jt (#121) Pick up 2 jts and stage pumps up to 5 BPM. RIH tagging up at 4960. Work down past tight spot f/ 4960' t/ 4970' with 30-50k dn.
Once broke through, continue pump in hole t/ 4980'. RIH with 9-5/8" 40#, L-80, TXP-BTC casing. Take Wt at 5000' (40' past previous hard spot), work through 10'
tight spot using same parameters then wash down next 3 jts t/ 5147', 5 BPM - 270 PSI. RIH with 9-5/8", 40# casing from 5147' to 5495'. TQ = 21K ft-lbs with Volant
tool. Fill on the fly. Installing centralizer per tally. PU = 200K & SO = 85K. Take Wt at 5495'. Pump 35 bbls lube pill, 3.75% Lo-torq. Work down past tight spot f/
5495' t/ 5522'. 4-5 BPM, 280 PSI, 30-50k dn. Continue RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 5522' to 5642'. RIH with 9-5/8", 40#, L-80, TXP-BTC
casing from 5642' to 5766, while circulate lube pill out of string and spot at 4950. 5 BPM 300 psi. Continue to RIH with 9-5/8", 40#, L-80, TXP-BTC casing from
5766 to 6421'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Install centralizer per tally. Bakerloc & MU the ES cementer to 6460, HES
rep verify pinned correctly (6x brass screws set for 3300 psi shear). RIH with 9-5/8", 47# casing from 6460' to 7180'. TQ 47# to 24K ft-lbs, Fill on the fly, top off
every 10 joints. Installing centralizer per tally. PU = 260K & SO = 70K.
4-7 BPH losses.
5/16/2023 RIH with 9-5/8", 47# casing from 7180' to 8755'. TQ 47# to 24K ft-lbs, Fill on the fly, top off every 10 joints. Installing centralizer per tally. PU = 255K & SO = 70K. 4-
7 BPH losses. Circulate and condition mud for cementing. Stage up pumps 2.5 bpm - 760 psi, 3 bpm - 750 psi, 4 bpm - 700 psi, 4.5 bpm, 620 psi
6 bpm - 480 psi ICP, 170 psi FCP. Reciprocating pipe 40' strokes. MW in/out 9.4 ppg,. Shut down pump, B/D TD and breakout Volant. R/U plug valves and cement
hose. Re-dope and M/U Volant. Close upper and lower IBOP. Re-establish circulation @ 6 BPM, 300 psi. Hold PJSM with all parties involved. HES batch up while
finish prepping the mud pits. Blow air to cement unit. HES filled lines with 5 bbls fresh water. PT surface lines to 1,200/4,200 psi, good. Rig pump 50 bbls mud
treated with Desco, swap back to HES. Pump 1st stage cement job: Mix & pump 55 bbls of 10 ppg tuned spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at
4.5 BPM = 295 psi. Drop bypass plug. Mix and pump 381 bbls of 12.0 ppg lead cement (EconoCem, Type I/II), 2.347ft^3/sk yield, 910 sks total) at 7.5 BPM = 770
psi. P/U wt at 400k and start to lose SOW with 360 bbls Lead Cement pumped. Park casing on depth at 8750' and short stroke, 24" casing stretch, with 200-250k
Pull. Mix and pump 82 bbls of 15.8 ppg tail cement (HalChem type 1-2 cement, 1.155 ft^3/sk yield, 400 sks total) at 3.5 BPM = 420 psi. Drop shut off plug. HES
pump 20 bbls water at 7 BPM = 330 psi. Displace with 449 bbls of 9.3 ppg spud mud from the rig at 7 BPM = 200 psi ICP & 690 psi FCP. Pumped 80 bbls of 9.4
ppg tuned spacer from Halliburton at 5 BPM = 700 psi. Pumped 101.2 bbls 9.3 ppg mud from the rig at 6 BPM = 820 psi ICP & 980 psi FCP. See poly-flake at
shakers at 4800 stks pumped. Slow rate to 3 BPM for last 10 bbls = 870 psi FCP, Bumped the plug at 5447 stks, 2.12 bbls late, CIP @ 22:44. Pressure to 1,400
psi, Hold 3 min, bleed off pressure, floats held. Pressure to 2,870 psi shifting ESC open. Shoe set at 8,750'. 15 bbl losses cementing and displacing. Circulate
through ES cementer at 2312', 4 BPM 260 psi, good interface at 1252 stks, start divert to RW. Dump 87 bbls cement, 60 bbls spacer, 97 bbls interface. Take
returns to pits. Stage up to 6 BPM, circulate 5 BU total. FCP= 240 psi. Disconnect knife valve accumulator lines. Drain stack and flush with black water 3 times. Re-
connect knife valve accumulator lines. Clean rig floor cement valves. Break out the Volant, clean same and re-dope the cup, MU the Volant. Continue to circulate
through the ES cementer at 2312' pumping 6 BPM = 220 psi while prepping for the 2nd stage cement job.
5/17/2023 Continue to circulate through the ES cementer at 2312' pumping 6 BPM = 240 psi while prepping for the 2nd stage cement job. Hold PJSM with all parties involved.
Break out the Volant, dope the cup and MU the Volant. Clean both pumps suction screens. Blow air through the cement line to the cement unit. Pump 5 bbls of
water, test lines to 500/4000 psi. Pump 2nd stage cement job: Mix & pump 60 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 4.5
BPM, 170 psi. Mix & pump total 384 bbls 10.7 ppg ArcticCem lead cement (755 sx at 2.855 ft^3/sk yield) at 6.5 BPM, ICP= 600, FCP= 735 psi. Mix & pump 56 bbls
of 15.8 ppg HalCem tail cement (270 sx at 1.156 ft^3/sk yield) at 3.5 BPM= 410 psi. Drop the closing plug. Pump 20 bbls of 8.34 ppg fresh water at 6.5 BPM = 210
psi. Displace with 150.5 bbls 9.3 ppg spud mud at 6BPM = 310 psi ICP, Slow to 4 BPM at 125 bbls pumped, 570 psi FCP. Bumped the plug at 1.0 bbls over calc.
CIP at 10:10. Pressure to 1700 psi shifting ESC closed (observe shift at 1520 psi), hold for 5 min, bleed off psi, open block valve to casing, no flow. 148 BBLS
spacer & interface and 246 bbls good 10.7 ppg cement returned, 100% returns. Blow down cement line. R/D the Volant tool. Suck out casing joint. Disconnect the
koomey lines from the knife valve. Drain the cement from the stack into the cellar box. Flush the stack with black water 3x. Power down the accumulator and
disconnect lines from diverter annular. Vac out 35 of mud from casing in prep for cut. R/D diverter line from knife valve. Hoist the diverter stack. Center casing &
Install the casing slips per wellhead rep with 100K on the slips. R/D Casing running equipment. N/D riser, bag, and diverter tee. Remove 4" conductor valves and
install 4" conductor outlet caps. Install Slip Loc well head as per well head rep. Test 500pis/5min 3800psi/10min-good test. N/U Adapter flange, spacer spool and
BOP's. Cont N/U BOP's, grease choke manifold, manuals and HCR's. Sim ops- Mobilize test plug, wear ring, and trip nipple to rig floor. C/O upper rams to 2 7/8" x
5" variables. Sim-ops M/U 3-1/2" and 5" TIW and dart valves.
5/18/2023 C/O upper rams to 2 7/8" x 5" VBRs. Sim-ops: M/U Floor valves to test manifold. M/U test sub to TopDrive. Rig up test hoses. C/O liners and Swabs on #2 MP. Line
up stack and install trip nipple. Install master bushings, Install test plug, Fill Stack w/ H2O, purge lines and system of air. SimOps: Load Pits with 8.8 ppg Flow-Pro.
Conduct initial BOPE test to 250/3,000 psi: LPR (2-7/8" x 5" VBRs) with 3-1/2 & 5 test joints, UPR (2-7/8" x 5" VBRs) with 3-1/2" & 5" test joints, annular with 3-1/2"
test joints, accumulator drawdown test, test gas alarms & PVT. All tests performed with fresh water against test plug. Upper and Lower IBOP bad test. Complete
remaining tests. Valves to be changed after test. AOGCC state inspector Guy Cook waived witness on May 17th at 19:05. 1. Annular on 3.5" test joint, Choke valves
1, 12, 13, 14, Kill valve 20, 3.5" TIW. 2. 3.5" Test JT on Upper rams (2-7/8" x 5" VBRs), Choke valves 9 & 11, HCR Kill, 3.5" Dart valve. 3. Choke Valves 5,8,10,
Manual kill 21, 5" TIW , Upper IBOP failed. 4. Choke Valves 5,8,10, Manual kill 21 5" TIW. 5. Choke Valve 4,6,7,5" Dart Valve. 6.Choke Valve 2. 7.HCR Choke 16.
8. 3.5" Test JT Lower Rams (2-7/8" x 5" VBR's). 9. Manual Choke 15. Koomey test, L/D 3.5" test JT P/U 5" test JT. 10. 5" Test JT with Upper Rams (2-7/8" x 5"
VBR's). 11. 5" Test JT with Lower Rams (2-7/8" x 5" VBR's). 12. Blind Rams, Choke valve 3 Lower IBOP-Lower IBOP failed. 13. Blinds, Choke Valve 3. 14.Manual
Choke Valve B. 15. Super Choke Valve A. 16. 5" Test JT with Lower Rams (2-7/8" x 5" VBR's)-Repeat test. Troubleshoot thermal contraction from warm test H2O.
17.Upper IBOP. 18. Lower IBOP. Accumulator Test: System pressure = 3,025 psi. Pressure after closure = 1,700 psi. 200 psi attained in 43 seconds. Full pressure
attained in 193 seconds. Nitrogen Bottles - 6 at 2,000 psi. PJSM, Remove bails, set 10' pup jt in hole. Remove upper torque ring. Cont to remove Upper/Lower
IBOP's. Clean and prep. Install new Upper IBOP and torque to specs. Torque lock ring in place. Sim-ops: Rig mechanic rebuild lower IBOP.
5/19/2023 Finish installing the upper IBOP and torque lock ring. Mobilize rebuilt lower IBOP to rig floor and install same. Rig up test sub to TD. Fill lower TD with fresh H2O,
purge air and attempt to test IBOPs. Seeing a psi loss, suspect a leak in the test equip. Troubleshoot psi loss and determine the system is experiencing thermal
contraction from warm H2O being pumped into the small test volume and cooling. Test Upper and Lower IBOPs. Test to 250 psi low / 3000 psi high for 5 min each
with fresh H2O - Good tests. Blow down and RD BOPE testing equipment. Pull Test plug and install 9" ID wear bushing. Install TopDrive bails, elevators and
mousehole. P/U M/U 8.5" clean out BHA T/588'. RIH w/ 5" DP from derrick f/588' t/2203'. Wash down f/2203' t/2299' GPM=350 PSI=630 RPM=30 TQ=3-6k ROT
WT=90k. Tag cement @ 2299' Drill cement f/2299' GPM=350 PSI=640 RPM=30 TQ=2-7k ROT WOB=7-10k. Tag ES Cementer on depth @ 2309' MD Ream
through x3. Wash and ream in hole f/2309' t/2585' GPM=350 PSI=630 RPM=30 TQ=3-6k ROT WT=90k. Cont. RIH w/ 5" DP from derrick f/2585 t/ 8201'. Fill pipe
every 2000' or as needed to maintain slack off weight. Ran out of down weight. Wash down f/8201' t/8611' GPM=400 PSI=1100 RPM=30 TQ=17-20k P/U 230k
ROT WT=90k. Tag cement @ 8600'. Parked at 8,578'. Blow down the top drive. RU head pin, cement line and testing equipment. Flood the lines and purge the air.
PT the 9-5/8" casing to 2,500 psi for 30 minutes charted - good test. Pumped 7.5 bbls & bled back 7.5 bbls. Blow down and RD testing equipment. Obtain SPR's
Drill cement f/8611' t/ 8621' drill FE and cement f/8621' t/8750'. BA at 8621' Flt at 8664 and shoe at 8748'. Work through each x3.' GPM=450 PSI=1340 RPM=30
TQ=17-20k PU=230k ROT WT=120k. Drill 20' of new formation f/8755' t/8775'. PU single to drill last 5'. GPM=450 PSI=1340 RPM=30 TQ=22k RU=230k ROT
WT=120k. LD 5" single. Pull into casing, CBU x2. To get mud in shape for FIT. GPM=490 PSI=1550 RPM=30 TQ=23k PU=230k ROT WT=120k. Added 2 drums
of low torque for trip out. R/U for FIT to 12.0ppg. Parked at 8674'. Blow down the top drive. RU head pin, cement line and testing equipment. Flood the lines and
purge the air.
5/20/2023 Close the UPR on 5" DP, pump down the DP and the kill line. Perform FIT to 12.0 ppg, with 9.3 ppg MW at 4,058' TVD, 570 psi applied at surface. 1.3 bbls
pumped and 1.3 bbls returned when bled down. R/D and blow down testing equip. Monitor Well - Static. Pump dry job and blow down TopDrive. TOOH from 8677
to 588 Racking all DP in Derrick. 250k PU, 50k SO at start of trip. L/D 10 jts 5" HWDP from 588', rack back the jar stand and L/D remaining 5 jts HWDP. L/D mud
motor and bit. Bit grade: 1-1-WT-A-E-I-NO-BHA. Record 7 bbls loss on trip out of hole. Clear and clean Rig floor. Mobilize BHA components and MPD bearing to
the rig floor. Remove the master bushings and install the split bushings. PJSM, M/U BHA t/102' Download MWD. Cont to M/U BHA to 289'. TIH from derrick on 5"
DP t/2175'. Kelly up and fill pipe. After filling pipe power was lost field wide (Minle Point). Monitor well - static. Get Gens fired up and and swap rig over to generator
power. On Gen power @ 19:15. Cont to TIH w/ 5" DP out of Derrick f/2175' t/4065'. Fill pipe. Shallow pulse test MWD, test geo-span downlink and break in geo-pilot
seals. Cont to TIH w/ 5" DP out of Derrick f/4065' t/8470'. P/U=250k S/O=55k. TIH on 5" singles from pipe shed f/8470' t/8724'. Monitor well - static. PJSM. Drain
the riser. Pull the MPD riser and install the MPD RCD. Install the RCD head skirt for the drip pan - no leaks. PJSM, Pump pit 4 empty. Pump spacer. Wash to TD.
Displace the well from 9.3 ppg spud mud to 8.8 ppg FloPro at 6 BPM = 760 psi ICP, 30 RPM = 23K ft-lbs TQ. With new mud out the bit, pull into the 9 5/8' casing.
FCP= 520 psi and final TQ= 11K ft-lbs. PU 195K, SO 90K, ROT 120K. Obtain SPRs. Slip and cut 77' drill of line. Service blocks & Topdrive. Inspect saversub and
grabber dies. Calibrate block height. Sim-ops clean surface equipment
Code 99 blue at Minle camp @ 05:30. Muster crew at 5 star shack. Code 99 blue (Medical Emergency) at Minle camp @ 05:30. Muster crew at 5 star shack.
5/21/2023 Finish slip and cut 77' drilling of line. Service blocks & Topdrive. Inspect saversub and grabber dies. Calibrate block height. SimOps: Clean underneath shakers,
trough and pit #4. Monitor Well against shut in MPD choke, 0 psi build. Establish flow and rotary parameters. Wash/Ream down to bottom at 8775'. 450 GPM 1160
psi, 60 RPM 10k Tq. Drill 8-1/2" lateral from 8775' to 9035' (4075' TVD), 260' drilled, 74.3'/hr AROP. 500 GPM = 1410 PSI, 120 RPM = 15K ft-lbs Tq, 12K WOB.
MW = 8.8 ppg, vis = 43, ECD = 10.1, Max Gas = 840u. PU = 165K, SO = 83K & ROT = 119K. MPD choke full open while drilling and shut in on connections, 0 psi
build. Drill 8-1/2" lateral from 9035' to 9611' (4089' TVD), 576' drilled, 96'/hr AROP. 500 GPM = 1480 PSI, 120 RPM = 16K ft-lbs Tq, 10-12K WOB. MW = 8.9 ppg,
vis = 40, ECD = 10.3, Max Gas = 1236u. PU = 155K, SO = 85K & ROT = 115K. MPD choke full open while drilling, trapping 100 psi on connections. Drill 8-1/2"
lateral from 9611' to 10277' (4088' TVD), 666' drilled, 111'/hr AROP. 550 GPM = 1800 PSI, 120 RPM = 14K ft-lbs Tq, 10-12K WOB. MW = 8.9 ppg, vis = 40, ECD
= 10.62, Max Gas = 1211u. PU = 155K, SO = 78K & ROT = 115K. MPD choke full open while drilling, trapping 100 psi on connections. Pumped sweep at 9,992',
back on time with 100% increase. Rig on Highline power @ 23:30. Drill 8-1/2" lateral from 10277' to 10713' (4080' TVD), 436' drilled, 79'/hr AROP. 548GPM =
1820 PSI, 120 RPM = 13K ft-lbs Tq, 14K WOB. MW = 8.8 ppg, vis = 41, ECD = 10.4, Max Gas = 1002u. PU = 163K, SO = 77K & ROT = 115K. MPD choke full
open while drilling, trapping 100 psi on connections. Drilled 25 concretions for a total thickness of 226 (11.9% of the lateral). Last survey at 10492.80' MD /
4,086.87' TVD, 90.87 deg INC, 330.23 deg AZM. Distance from Wp10 = 15.47', 10.88' low & 11.0' right.
5/22/2023 Drill 8-1/2" lateral from 10713' to 11245' (4067' TVD). Drilled 532' = 88.66'/hr AROP. 550 GPM = 1950 psi, 120 RPM = 11k Tq, WOB = 15k. MW = 8.9 ppg, Vis =
42, ECD = 10.7 ppg, Max Gas = 961u. PU = 158k, SO = 75k, ROT = 115k. Back ream 30' on connections. MPD chokes full open while drilling, trapping 100 psi on
connections. Hi-Vis sweep at 11038', returned on time w/ 100% increase. Crossed the OA top at 11,190' due to unexpected formation change. Drill 8-1/2" lateral
from 11245' to 11895' (4089' TVD). Drilled 650' = 108.33'/hr AROP. 550 GPM = 2000 psi, 120 RPM = 9k Tq, WOB = 8-10k, MW = 9.0 ppg, Vis = 40, ECD = 10.94
ppg, Max Gas = 804u. PU = 155k, SO = 77k, ROT = 112k. Back ream 30' on connections. Re-enter the OA1 at 11330' for a total of 140' drilled above zone. MPD
chokes full open while drilling, trapping 150 psi on connections. Drill 8-1/2" lateral from 11895' to 12248' (4091' TVD). Drilled 353' = 59'/hr AROP. 550 GPM = 2050
psi, 120 RPM = 10k Tq, WOB = 7k, MW = 9.0 ppg, Vis = 40, ECD = 10.95 ppg, Max Gas = 831u. PU = 160k, SO = 73k, ROT = 111k. MPD chokes full open while
drilling, trapping 130 psi on connections. Back ream 30' on connections. Hi-Vis sweep at 11988', returned 300 strks late w/ 50% increase. Drill 8-1/2" lateral from
12248' to 12690' (4103' TVD). Drilled 442' = 74'/hr AROP. 548 GPM = 2160 psi, 120 RPM = 12k Tq, WOB = 14k, MW = 9.0 ppg, Vis = 40, ECD = 11.0 ppg, Max
Gas = 811u. PU = 170k, SO = 65k, ROT = 112k. MPD chokes full open while drilling, trapping 130 psi on connections. Back ream 60' on connections. Faults
encountered at 12405' and 12515' with aprox 10' and 2' DTW throws respectively.
Currently in OA-3 Targeting 88 deg. Last survey at 12396.05' MD / 4094' TVD, 89.11 deg INC, 331.11 deg AZM. Distance from Wp10 = 6.97', 5.82' High, 3.84'
right. Drilled 48 concretions for a total thickness of 460' (11.8% of the lateral).
5/23/2023 Drill 8-1/2" lateral from 12690' to 13110' (4096' TVD), 420' drilled, 70'/hr AROP. 550 GPM = 2180 PSI, 120 RPM = 11K ft-lbs Tq, 15K WOB. MW = 9.0 ppg, vis =
39, ECD = 10.8, Max Gas = 755u. PU = 173K, SO = 40K & ROT = 112K. Hi vis sweep @ 13034' back 400 stks late with a 70% increase. MPD choke full open
while drilling and trapping 130 psi on connections. Drill 8-1/2" lateral from 13110' to 13421' (4097' TVD), 311' drilled, 51.83'/hr AROP. 550 GPM = 2000 PSI, 120
RPM = 13K ft-lbs Tq, 6-8K WOB. MW = 8.9 ppg, vis = 42, ECD = 10.72, Max Gas = 817u. PU = 165K, SO = 0K & ROT = 113K. MPD choke full open while drilling
and trapping 130 psi on connections. Performed 325 bbls whole mud dilution at 13150 reducing MBTs from 6.5 down to 4.8. Drill 8-1/2" lateral from 13421' to
13705' (4103' TVD), 284' drilled, 47'/hr AROP. 550 GPM = 2040 PSI, 120 RPM = 17K ft-lbs Tq, 15-18K WOB. MW = 8.9 ppg, vis = 42, ECD = 10.77, Max Gas =
672u. PU = 170K, SO = NA & ROT = 112K. MPD choke full open while drilling and trapping 130 psi on connections. Drill 8-1/2" lateral from 13705' to 14208'
(4094' TVD), 503' drilled, 84'/hr AROP. 544 GPM = 2190 PSI, 120 RPM = 15K ft-lbs Tq, 12K WOB. MW = 8.9 ppg, vis = 42, ECD = 10.72, Max Gas = 684u. PU =
170K, SO = NA & ROT = 113K. Pumped Sweep at 13990' back 200 strks late 20% increase in cuttings. Encountered a fault #3 at 13868 suspected DTW 10.
Drilled 76 concretions for a total thickness of 695' (13% of the lateral). Drilling with MPD chokes open and trapping 130 psi on connection. Last survey: Distance
from WP10 = 2.39', 2.23' Low & 0.84' Left.
5/24/2023 Drill 8-1/2" lateral from 14,208' to 14,790' (4,108' TVD). Drilled 582' = 97'/hr AROP. 550 GPM = 2,320 psi, 120 RPM = 15K ft-lbs TQ, WOB = 7K. PU = 177K, SO =
0K & ROT = 113K. MW = 9.0 ppg, Vis = 40, ECD = 11.1 ppg, max gas = 725 units. MPD choke full open while drilling and trapping 130 psi on connections. Begin
undulating up at 14,697'. Drill 8-1/2" lateral from 14,790' to 15,130' (4,084' TVD). Drilled 340' = 56.7'/hr AROP. 550 GPM = 2,280 psi, 120 RPM = 16K ft-lbs TQ,
WOB = 10-12K. PU = 168K, SO = 0K & ROT = 110K. MW = 9.0 ppg, Vis = 41, ECD = 11.24 ppg, max gas = 609 units. MPD choke full open while drilling and
trapping 130 psi on connections. Pump 30 bbl hi-vis sweep at 14,940', back 300 strokes late with 20% increase. Exited the OA-3 at 15,012'. Drill 8-1/2" lateral from
15,130' to 15,606', (4,065' TVD). Drilled 476' = 79'/hr AROP. 550 GPM = 2,400 psi, 120 RPM = 17K ft-lbs TQ, WOB = 10-15K. PU = 170K, SO = 0K & ROT =
111K. MW = 9.1 ppg, Vis = 41, ECD = 11.55 ppg, max gas = 657 units. MPD choke full open while drilling and trapping 130 psi on connections. Entered the OA-1
at 15,163'. Encountered fault #4 at 15,241' with 9' DTE throw. Placing well bore back in upper OA-3. Undulate up exiting the OA-3 at 15,450' and entering the OA-1
at 15,507'. Drill 8-1/2" lateral from 15,606' to 16176', (4,065' TVD). Drilled 570' =95'/hr AROP. 550 GPM = 2,210 psi, 120 RPM = 20K ft-lbs TQ, WOB = 10-15K.
PU = 183K, SO = 0K & ROT = 108K. MW = 9.1ppg, Vis = 41, ECD = 11.58 ppg, max gas = 646 units. MPD choke full open while drilling and trapping 115 psi on
connections. Pump 30 bbl hi-vis sweep at 15,986', back 100 strokes late with no increase. Performed 290 bbls whole mud dilution at 16,081' reducing MBTs from
6.5 down to 4.8. Drilled 107 concretions for a total thickness of 846' (11.5% of the lateral). Distance from WP10 = 11.61', 6.48 Low, 9.63 Left.
5/25/2023 Drill 8-1/2" lateral from 16,176' to 16,748', (4,058' TVD). Drilled 572' = 95.3'/hr AROP. 550 GPM = 2,360 psi, 120 RPM = 20K ft-lbs TQ, WOB = 12K. PU = 188K,
SO = 0K & ROT = 109K. MW = 9.0 ppg, Vis = 41, ECD = 11.1 ppg, max gas = 630 units. MPD choke full open while drilling and trapping 115 psi on connections.
Begin undulation down at 16,651'. Drill 8-1/2" lateral from 16,748' to 17,221', (4,071' TVD). Drilled 570' = 95'/hr AROP. 500 GPM = 2,090 psi, 120 RPM = 18K ft-
lbs TQ, WOB = 10K. PU = 178K, SO = 0K & ROT = 111K. MW = 9.0 ppg, Vis = 39, ECD = 11.2 ppg, max gas = 760 units. MPD choke full open while drilling and
trapping 115 psi on connections. Exit the OA-1 at 16,960', entered the OA-3 at 17,050' and leveled out. Pump 30 bbl hi-vis sweep at 16,936', back 470 strokes late
with 20% increase. Drill 8-1/2" lateral from 17,221' to 17,506', (4,074' TVD). Drilled 285' = 48'/hr AROP. 550 GPM = 2,430 psi, 120 RPM = 20K ft-lbs TQ, WOB =
15K. PU = 198K, SO = 0K & ROT = 110K. MW = 9.0 ppg, Vis = 39, ECD = 11.21 ppg, max gas = 826 units. MPD choke full open while drilling and trapping 115
psi on connections. Drill 8-1/2" lateral from 17,506' to 18,076', (4,102' TVD). Drilled 570' = 95'/hr AROP. 550 GPM = 2,430 psi, 120 RPM = 20K ft-lbs TQ, WOB =
15-20K. PU = 195K, SO = 0K & ROT = 111K. MW = 9.0 ppg, Vis = 39, ECD = 11.30 ppg, max gas = 826 units. MPD choke full open while drilling and trapping
115 psi on connections. Exited the OA-3 at 17,623' into the OA-2 and reentered the OA-3 at 17,800'. Pump 30 bbl hi-vis sweep at 17,981', back 400 strokes late
with 0% increase. Encountered fault # 5 at 17,946' with 28' DTW throw moving the wellbore from the OA-3 to the NF clays. Perform 580 bbl dump and dilute at
18,036'. Drilled 137 concretions for a total thickness of 1079' (11.7% of the lateral). Distance from WP10 = 13.97', 8.63' Low, 10.99' Right.
5/26/2023 Drill 8-1/2" lateral from 18,076' to 18,647', (4,113' TVD). Drilled 571' = 95.2'/hr AROP. 550 GPM = 2,280 psi, 120 RPM = 20K ft-lbs TQ, WOB = 15-20K. PU =
191K, SO = 0K & ROT = 109K. MW = 8.8 ppg, Vis = 39, ECD = 11.1 ppg, max gas = 866 units. MPD choke full open while drilling and trapping 115 psi on
connections. Reacquired the OA-1 sand at 18,060' and level out. Drill 8-1/2" lateral from 18,647' to 19,123', (4,113' TVD). Drilled 476' = 79.3'/hr AROP. 550 GPM =
2,400 psi, 120 RPM = 20-24K ft-lbs TQ, WOB = 15-18K. PU = 190K, SO = 0K & ROT = 111K. MW = 8.9+ ppg, Vis = 39, ECD = 11.31 ppg, max gas = 594 units.
MPD choke full open while drilling and trapping 115 psi on connections. Pump 30 bbl sweep at 18,838', back 450 strokes late with 0% increase. Drill 8-1/2" lateral
from 19,123' to 19,676', (4,113' TVD). Drilled 553' = 92'/hr AROP. 550 GPM = 2,590 psi, 120 RPM = 19K ft-lbs TQ, WOB = 10-15K. PU = 198K, SO = 0K & ROT =
120K. MW = 9.0 ppg, Vis = 41, ECD = 11.41 ppg, max gas = 738 units. MPD choke full open while drilling and trapping 115 psi on connections. Drill 8-1/2" lateral
from 19,676' to TD at 19,800', (4,112' TVD). Drilled 124' = 124'/hr AROP. 550 GPM = 2,500 psi, 120 RPM = 19K ft-lbs TQ, WOB = 10-15K. PU = 198K, SO = 0K &
ROT = 120K. MW = 9.0 ppg, Vis = 41, ECD = 11.32 ppg, max gas = 746 units. MPD choke full open while drilling and trapping 115 psi on connections. TD called
by town geologist at 19,800' in the OA-1 sand. Obtain SPR's and final survey. Downlink Geo-Pilot to home position. Last survey at 19730.64' MD / 4,115.52' TVD,
89.73 deg INC, 334.46 deg AZM. Distance from WP10 = 15.71', 15.38' low & 3.19 right. Drilled 160 concretions for a total thickness of 1,258' (11.4% of the lateral).
Pump 30 bbl hi-vis sweep, back 500 strokes late with no increase in cuttings. On circulation 3 of 4 BU at 500 GPM = 2410 psi, 120 RPM = 19K ft-lbs TQ. ECD =
11.12 ppg with 9.0 ppg MW. Racking back a stand per bottoms up.
5/27/2023 Finish circulating the last BU for a total of 4 BU at 500 GPM = 2,410 psi, 120 RPM = 19K ft-lbs TQ. PJSM. Wash from 19,464' to TD at 19,800' at 400 GPM = 1,580
psi, 30 RPM = 15K 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 1,434 bbls of 8.45 ppg viscosified brine with 3% lubes (1.5% 776 and 1.5% LoTorq). 6 BPM = 1,130
psi (ICP), 40 RPM = 21K ft-lbs TQ & 7 BPM = 850 psi (FCP), 40 RPM = 20K ft-lbs TQ, reciprocating 90' alternating stopping points. Shut down the pumps with
clean 8.45 ppg viscosified brine to surface. No losses. PU= 225K, SO= 0K, ROT= 126K. Monitor the wellbore pressure with MPD choke 3 times 5 minutes each =
53, 44 & 32 psi. EMW = 8.7 ppg. Obtain new SPRs and parameters. SimOps:Clean pit #3 and load 8.45 ppg 3% lube brine in pits #3 & 4. BROOH from 19,800' to
19,123' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Rack back 7 stands HWDP on DS. 500 GPM = 1,800 psi, 120 RPM = 21 ft-lbs
TQ, max gas = 177 units. PU = 190K, SO = 0K & ROT = 110K. BROOH from 19,123' to 16,558' pulling 5-10 minutes/stand slowing as needed to clean up
slides/tight spots. Laying down DP in the mouse hole. 16,558' to 16,271' rack back DP in derrick. 450 GPM = 1,430 psi, 120 RPM = 21K ft-bs TQ, ECD= 10.03
ppg, max gas = 203 units. PU = 180K, SO = 0K, ROT = 116K. BROOH from 16,558' to 14,467' pulling 5-10 minutes/stand slowing as needed to clean up
slides/tight spots. Racking back DP in derrick. Due to skate being down. 450 GPM = 1,430 psi, 120 RPM = 15K ft-bs TQ, ECD= 9.92 ppg, max gas = 6 units. PU =
190K, SO = 70K, ROT = 116K. Regained SO weight at 15,505'. BROOH from 14,467' to 13,228' pulling 5-10 minutes/stand slowing as needed to clean up
slides/tight spots. Laying down DP in mouse hole. 460 GPM = 1,355 psi, 120 RPM = 15K ft-bs TQ, ECD= 9.8 ppg, max gas = 0 units. PU = 190K, SO = 70K, ROT
= 116K.
5/28/2023 BROOH from 13,228' to 8,948' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in mouse hole. 450 GPM = 1,110 psi,
120 RPM = 10K ft-bs TQ, ECD= 9.5 ppg, max gas = 6 units. PU = 150K, SO = 102K, ROT = 95K. BROOH into the shoe from 8,948' to 8,726' at 450 GPM = 1,070
psi, 30 RPM = 5K ft-lbs TQ. Lost 367 bbls while BROOH. Pump 30 bbl hi-vis sweep at 450 GPM = 1,130 psi, 60 RPM = 8-9K ft-lbs TQ reciprocating 60' and
circulate the casing clean with 1.5 BU. Sweep back on time with no increase. Monitor the wellbore pressure with MPD choke 4 times 5 minutes each = 44, 34, 29, &
25 psi. EMW = 8.9 ppg. Weight up the surface system to 8.9 ppg. Circulate 8.9 ppg while weighting up the returns on the fly to 9.1 ppg at 7 BPM = 570 psi, 60
RPM = 6-7K ft-lbs TQ reciprocating 60' until good 9.1 ppg in/out. Monitor the wellbore pressure with MPD choke 4 times 5 minutes each = 26, 10, 1, & 0 psi. Close
obit valve and monitor well on 2" - No flow. PJSM. Slip and cut 86' of drill line. Adjust band rollers, check equalizer bar and calibrate block height. PJSM. Remove
RCD and install the trip nipple. Fill riser and no leaks. Pump 10.2 ppg dry job at 6 BPM = 490 psi. POOH laying down 5" DP from 8,726' to 6,094'. Drop 2.45" drift
with wire tail. TOOH racking back stands in derrick from 6094' to 1145'. Loss rate = 3-5 bbls/hr.
5/29/2023 TOOH from 1,145' to 289'. Observe the well for flow - slight static losses. Lost 39 bbls while TOOH. LD HWDP, jars and NMDCs from 289' to 97'. Download MWD
tools. LD BHA from 97' to surface. Bit graded: 2-1-CT-N-X-I-BT-TD. Normal 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 4-1/2"" double stack tongs and elevators. MU
crossover to FOSV. Static loss rate = 3.5 BPH. PJSM. PU round nose float shoe on 4-1/2'' crossover joint (H625 box x BTC pin) to 42'. RIH with 4-1/2", 13.5#, H625
slotted liner per tally installing a centralizer on every joint, torque to 9,600 ft-lbs to 8,357'. Lost 45 bbls while running 4-1/2" liner. MU 5-1/2" safety joint and
changeout tong heads. MU 4-1/2" H625 x 5-1/2" JFE Bear crossover and RIH w/ 5-1/2" 17#, L-80 JFE Bear slotted liner per tally installing a centralizer on every
joint, torque to 7,400 ft-lbs from 8,357' to 11,227'. PU = 113K & SO = 78K. MU Baker SLZXP liner top packer and RIH with one stand of DP to 11,359'. Pump 5 bbls
at 2.5 BPM = 130 psi to ensure clear flow path through the packer. Obtain rotational parameters: 10 RPM = 5K ft-lbs TQ, 20 RPM = 6K ft-lbs TQ. PU = 115K SO =
78K & ROT = 98K. Blow down the top drive. TIH with 4-1/2" x 5-1/2" slotted liner on 5" DP from 11,359' to 13,070'. Loss rate = 1.5 bbl/hr.
5/30/2023 TIH with 4-1/2" x 5-1/2" slotted liner on 5" DP from 13,070' to 19,159'. TIH on 5" HWDP from 19,159' to tag at 19,800' (TD) with 10K. PU = 185K & SO = 92K. Lost
44 bbls while TIH. Only used HWDP because it was used to TD and racked back in the derrick. LD 1 joint HWDP and MU 1 joint of DP. Pump 7 bbls at 4 BPM =
580 psi to ensure clear flow path. Drop 1.125"" phenolic setting ball. RU FOSV, side entry sub, 10' pup joint & circulating equipment. PT lines to 4,500 psi. Place
liner in tension at 19,800' set depth. Pump ball down with 30 bbl hi-vis sweep at 4 BPM = 640 psi then slowed to 2 BPM = 310 psi. Ball on seat 182 strokes early at
1,211 strokes. Pressure up to 2,000 psi, observed initial shear at 1,850 psi & hold for 3 minutes. Set down 40K to confirm set. Pressure up & observe release at
3,130 psi. Continue to pressure up with rig pump and observe ball seat shear at 4,130 psi. PU & observe travel at 157K to confirm release. Top of liner at 8,546.53'.
Open kill line & purge air. Close the annular & PT the 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 = 280 psi. Once the liner running tool is out of the LTP bring pumps up to 444 GPM = 1,210 psi, PU to
8,508' and circulate the sweep out of the hole. Sweep back on time with 10% increase. Pump 10.2 ppg dry job and blow down the top drive. POOH laying down 5"
HWDP to the pipe shed from 8,508' to 7,923'. POOH laying down 5" DP from 7,923' to 31'. Lay down liner running tool. Lost 31 bbls while POOH. MU stack
washing tool, flush BOP stack and LD stack washing tool. Remove wear bushing. Mobilize Centrilift equipment to the rig floor. Mobilize & RU Doyon casing
equipment. Static loss rate = 2 BPH. PJSM for running completion with all parties involved.
Activity Date Ops Summary
5/31/2023 PU 7" bullet seal assembly and RIH to 22'. RIH with 3-1/2", 9.3#, L-80, EUE 8rd tubing from 22' to 774'. Optimum TQ = 3,130 ft-lbs. Double stack tubing tong back-
up ram O-ring leaking. RD tubing tongs and demobilize off the rig floor. Mobilize the backup tong to the rig floor and RU. RIH with 3-1/2", 9.3#, L-80, EUE 8rd
tubing from 774' to 1,027'. Optimum TQ = 3,130 ft-lbs. MU XN assembly, tubing joint, Baker Zenth gauge assembly, tubing joint and Viking sliding sleeve assembly
spooling TEC wire and installing cannon clamps per tally from 1,027' to 1,164'. PU = 77K & SO = 65K. Optimum TQ = 3,130 ft-lbs. Check TEC wire continuity
every 1,000'. Loss rate = 2 BPH,RIH with 3-1/2", 9.3#, L-80 EUE 8rd tubing spooling TEC wire and installing cannon clamps per tally from 1,164' to 6,721'.
Optimum TQ = 3,130 ft-lbs. Check TEC wire continuity every 1,000'. Hydraulic oil filter housing cracked in the hydraulic room. Changeout hydraulic oil filter
housing. RIH with 3-1/2", 9.3#, L-80 EUE 8rd tubing spooling TEC wire and installing cannon clamps per tally from 6,721' to no-go at 8,558.59' (bottom of mule
shoe) with 10K down. Liner top at 8,548.99' (2.46' deeper than liner tally). Optimum TQ = 3,130 ft-lbs. Check TEC wire continuity every 1,000'. PU = 82K & SO =
65K. Lost 26 bbls while running tubing. Average loss rate = 1.7 BPH,Lay down joints #270 - 268. MU 2.17' pup joint and joint #268. Change elevators to 5", PU 5"
landing joint, 4-1/2" IF x 3-1/2" IF crossover, 3-1/2" IF x 3-1/2" TC-II crossover and tubing hanger. Terminate the TEC and feed through the tubing hanger. Land
tubing on hanger at 8,555.74' with locator sub 2.85' of no-go. Centrilift readings: Tubing = 1,823.43 psi, 76.5 deg F & 19.0 volts. RU circulating equipment to
reverse circulate. PU 5' to expose the circulating ports. Flood lines and PT to 3,900 psi - good. test. PJSM. Reverse circulate 565 bbls of 9.1 ppg corrosion inhibited
brine at 6 BPM = 1,210 psi ICP / 1,350 psi FCP,Strip through the annular closing the circulating ports leaving the tubing hanger 2' from landing. Drain the stack,
blow down lines and rinse the stack. Land the tubing hanger and RILDS. SimOps: RD and blow down circulating equipment on landing joint. RU testing equipment.
Attempt to PT the IA but getting returns up the tubing at 0.8 BPM = 140 psi. Pumped a total of 6 bbls with no pressure build filling the BOP stack. Discuss options
with town completion Engineer. No slickline personnel due to helicopter issues and changeout. Wait for delayed slickline personnel to arrive on the helicopter.
6/1/2023 Wait for slickline to arrive. Monitor the well via the trip tank. Static loss rate = 2 BPH. SimOps: General housekeeping and rig maintenance. Mobilize the Geo Span
to the rig floor. PJSM. Mobilize tools to the rig floor and RU slickline. RIH with sliding sleeve shifting tool. Attempt to verify sliding sleeve shifted closed, had several
friction bites and able to get a jar hit with shifting tool in sliding sleeve. Unable to get tool to engage after jar hit. POOH with slickline and stand back. SimOps:
General housekeeping and rig maintenance. Work on rig welding projects. Loss rate = 2 BPH,RU and attempt to PT the IA to 3,500 psi but unable to pressure up.
Continued to see T x IA communication. Discuss options with completions Engineer. RD slickline. Move fluids in pits and build additional 9.1 ppg brine. Pump down
the IA at 6 BPM = 800 psi. MU landing joints. MU landing joint and LD in the pipe shed. Loss rate = 2 BPH,Wait for slickline to arrive. Monitor the well via the trip
tank. Static loss rate = 2 BPH. SimOps: General housekeeping and rig maintenance. PJSM. Mobilize tools to the rig floor and RU slickline. MU cat standing valve
plug and RIH. Set in XN nipple but did not have a good shear indication at surface. POOH and plug is still on. Redress the plug and add more weight bar to the tool
string. RIH with cat standing valve plug. Set in XN nipple but did not have a good shear indication at surface. POOH and plug is set. Line up and purge the kill line
of air. Close the blind rams. Pressure up on the tubing to 1,500 psi and seen no pressure on the IA. Line up to the IA a pump 3 BPM = 490 psi, pumped 5 bbls. Line
back up to the tubing and pressure up to 2,500 psi with no pressure observed on the IA. Bleed the pressure up and open the blinds. MU retrieval tool and RIH.
Engage retrieval tool into plug and POOH. Successfully retrieved the plug. RD slickline and demob equipment from the rig floor.
6/2/2023 MU the landing joint to the tubing hanger. BOLDS. Pull the tubing hanger and lay down. RU spooling unit and splice TEC wire. Run in the hole with 2 joints of 3-1/2
EUE tubing and tag TOL at 8,559' (same as previous tag) with 10K and observe some pipe movement. Able to work down to 8,562' with 10-15K drag, unable to get
past 8,562'. Lay down 1 joint of 3-1/2 EUE tubing and make up crossover back to landing joint. MU the top drive and RIH to 8,557' with mule shoe 2 off tie-back.
Close annular and bullhead 30 bbls at 6 BPM = 820 psi to flush debris. Had 410 psi trapped pressure after bull heading. Bleed off slowly through choke back to
pits, 24 bbls bled back. Verify no flow and no pressure. Open annular. Tag liner top at 8,559' with 15K and no movement. Pick up and put 1/4 turn in string and
work up 20'. Slack off pumping at 2 BPM = 70 psi. Observe pressure increase of 100 psi and 5-10K drag as bottom seals entered tieback. Shut off pumps and no-
go at 8,571'. Lay down landing joint and crossover and space out with additional 10' pup. Verify TEC wire integrity. Redress hanger body seals and make up to
landing joint. Terminate TEC wire and feed through the tubing hanger. Blow down the top drive, kill line, choke line and hole fill. Land the tubing hanger and RILDS.
RU testing equipment. PT the IA to 3,800 psi for 30 minutes charted - good test. Install BPV into the tubing hanger. PJSM. Pull the MPD riser and ND BOPE stack.
Rack back stack on stump. Mobilize tree into the cellar. Install CTS plug into BPV. NU 3-1/8" Cameron injection tree and adapter head adapter to the tubing spool.
Obtain final Zenith gauge readings: Tubing = 1,713.5 psi & 75.8 deg, & 20.4 volts. PT tubing hanger void to 500 psi for 5 min and 5,000 psi for 10 minutes - good
test. RU and fill tree with diesel. PT the tree to 250/5,000 psi - good test. Pull the CTS plug and BPV with dry rod. Shut in and secure well. Final well pressures:
tubing = 0 psi & IA = 0 psi. No BPV installed,Clean the cellar box. Rig welder cut off the mouse hole extension and seal weld. SimOps: Prep the rig floor for skidding.
RDMO 24:00.
50-029-23748-00-00API #:
Well Name:
Field:
County/State:
MP M-63
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
PT the IA to 3,800 psi for 30 minutes charted - good test
ACTIVITYDATE SUMMARY
6/3/2023
WELLHEAD: M/U hanger to LJ then to string ran 1/4¿¿ tech wire through hanger and
terminated. Landed hanger to RKB of 31.88 RILDS, set BPV N/D stack. Set CTS plug
N/U tree/adatper terminated tech wire through adapter. Pressure tested void 500 low
5000 high 5/10 minutes test good, tested tree 250 low 5000 high 5/10 minutes test
good. Pulled CTS plug and BPV secured well.
6/3/2023
***WELL S/I ON ARRIVAL***
PRESSURE UP ON IA TO 500 psi., LOCATE & OPEN SLEEVE @ 7415' SLM /
7413' MD, SEE PRESSURE DROP OFF TO 0 psi.
SET 3'' JET PUMP (ser# BP-1017, ratio: 13B, screen, oal= 88''), SET IN VIKING SS
@ 7415' SLM / 7413' MD
***WELL S/I ON ARRIVAL***
7/7/2023
Well Support Techs R/D temp production piping and power fluid lines. instlled new
injection piping and pressure tested to 3650 psi.Foundation and well house was set.
No issues.
7/7/2023
T/I = 770/72 Freeze Protect Tubing, Pumped 33 bbls diesel down Tubing, Pumped
290 bbls Inhibited 1% KCL down IA, Pumped 125 bbls diesel down IA, Pumped 30
bbls 60/40 down IA, Presssured up IA to 2500 psi to ensure sliding sleeve is shut,
MIT-IA Passed. FWP = 530/175
7/7/2023
***WELL S/I ON ARRIVAL***
PULL 3'' JET PUMP @ 7407' SLM / 7413' MD (ratio: 13B)
CLOSE SLEEVE @ 7407' SLM / 7413' MD, MADE 5 PASSES THROUGH SLEEVE,
LRS PRESSURE UP & VARIFY SLEEVE CLOSED
***WELL S/I ON DEPARTURE***
Daily Report of Well Operations
PBU MPM-63
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
153
1
1
1
54
2
1
1
Yes X 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? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns? 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:
1.17
5/17/2023 Surface
Spud Mud
EconoCem Type I/II 910 2.35
HalCem Type I/II 400 1.16
7
2,290.08
Casing 9 5/8 47.0 L-80 TXP Tenaris 2,158.76 2,290.08 131.32
2,312.24 2,309.42
Casing Pup Joint 9 5/8 47.0 L-80 TXP 19.34 2,309.42
16.68 2,328.92 2,312.24
ES Cementer 10 3/4 TXP Halliburton 2.82
Casing Pup Joint 9 5/8 40.0 L-80 TXP
8,621.23
Casing 9 5/8 40.0 L-80 TXP Tenaris 6,292.31 8,621.23 2,328.92
8,664.16 8,622.64
Baffle Adapter 10 3/4 TXP Halliburton 1.41 8,622.64
1.31 8,665.47 8,664.16
Casing 9 5/8 40.0 L-80 TXP Tenaris 41.52
Float Collar 10 3/4 TXP Innovex
101 total 9-5/8" x 12"1/4" bowspring 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 25, every other joint to #47 then
every third joint to #149. One each on joints #151 to #162. One each with stop rings on pup joints above and below ES
cementer. One each on every third joint #164 to #209 & one on jt # 211.
Casing 9 5/8 40.0 L-80 TXP Tenaris 82.94 8,748.41 8,665.47
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
Ftg. Returned
Ftg. Cut Jt.16.78 Ftg. Balance
No. Jts. Delivered 232 No. Jts. Run 215
Length Measurements W/O
Threads
Ftg. Delivered Ftg. Run
34.10 RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
12 381
HES ES Cemente Closure OK
56
ArcticCem Type I/II
Type
HalCem Type I/II 270
Tuned Spacer
755 2.85
Stage Collar @
60
Bump press
100
246
8,750.008,755.00
CEMENTING REPORT
Csg Wt. On Slips:100,000
Spud Mud
22:44 5/16/2023 2,312
2312.24
15.8 82
Bump press
Cement returns to surface
Bump Plug?
Y
3.5
9.3 6 150.49/149.58
550.15/547.99
1400
87
Rig
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 55
15.8
570
9.3 6.5
1700
10
10.7 384 6.5
99
870
Bump Plug?
Csg Wt. On Hook:255,000 Type Float Collar:Innovex Round Nose No. Hrs to Run:41
19.82
51.77
9 5/8 47.0 L-80 TXP
9 5/8 47.0 L-80 TXP
91.479 5/8 47.0 L-80 TXP Tenaris 39.70
TXP Innovex 1.59 8,750.00 8,748.41
51.77 31.95
39.85 131.32 91.47
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP M-63 Date Run 14-May-23
CASING RECORD
County State Alaska Supv.B. Anderson / J. Vanderpool
8,665.47
Floats Held
521.9 903
333 570
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.3
Shoe @ 8750 FC @ Top of Liner
SE
C
O
N
D
S
T
A
G
E
Rig
10:10
Cement to Surface
481.7 529.8 10
Cut joint
Casing (Or Liner) Detail
Shoe
Casing Pup Joint
Casing
10 3/4
Surface
87
99
2,312
Cement to Surface
X
100
X
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: 06/28/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU M-63
PTD: 223-016
API: 50-029-23748-00-00
FINAL LWD FORMATION EVALUATION LOGS (05/09/2023 to 05/27/2023)
x EWR-M5, AGR, ABG, 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: 223-016
T37784
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.06.28
14:13:02 -08'00'
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manger
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-63
Hilcorp Alaska, LLC
Permit to Drill Number: 223-016
Surface Location: 5037’ FSL, 291' FEL, Sec. 14, T13N, R09E, UM, AK
Bottomhole Location: 1872' FSL, 141' FEL, Sec. 35, T14N, R09E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of February, 2023. 27
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.02.27 12:27:31 -09'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address: 6. Proposed Depth: 12. Field/Pool(s):
MD: 19712' TVD: 4109'
4a. Location of Well (Governmental Section): 7. Property Designation:
Surface:
Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.9' 15. Distance to Nearest Well Open
Surface: x-533874 y- 6027890 Zone- 4 25.2' to Same Pool:402'
16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 94 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
42" 20" 129.5# X-52 80' Surface Surface 105' 105'
47# L-80 TXP 2500' Surface Surface 2500' 2086'
40# L-80 TXP 6400' 2500' 2086' 8900' 4074'
8-1/2" 5-1/2" 17#/13.5# L-80 JFE Bear 10962' 8750' 4061' 19712' 4109'
x4-1/2" /Hyd 625
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name: Nathan Sperry
Monty Myers Contact Email:nathan.sperry@hilcorp.com
Drilling Manager Contact Phone:907-777-8450
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
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 Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
4271'
12-1/4" 9-5/8"
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Uncemented Slotted Liner
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Conductor/Structural
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
14 cu yds Concrete
Stg 1 L - 936 sx / T - 395 sx
9563
18. Casing Program: Top - Setting Depth - BottomSpecifications
1793
Total Depth MD (ft): Total Depth TVD (ft):
22224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 673 sx / T - 268 sx
1386
2582' FNL, 518' FEL, Sec. 12, T13N, R09E, UM, AK
1872' FSL, 141' FEL, Sec. 35, T14N, R09E, UM, AK
16-004
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
5307' FSL, 291' FEL, Sec. 14, T13N, R09E, UM, AK ADL 025514, 388235 & 355018
MPU M-63
Milne Point Field
Schrader Bluff Oil Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
2.22.2023
5/4/23
By Samantha Carlisle at 9:14 am, Feb 22, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.22 08:09:40 -09'00'
Monty M
Myers
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing test of 9-5/8" surface casing and FIT digital data to AOGCC
immediately upon performing the FIT.
* MIT-IA to 3600 psi. 24 hour notice to AOGCC for opportunity
to witness. * MIT-IA to 2000 psi 5 days after stabilized injection. 24 hour notice to AOGCC.
* Approved to pre-produce for 30 days with reverse circulating jet pump. 24/7 manned monitoring on MPU M-pad if no surface safety valve
while on IA power fluid injection when on 30 day pre-production.
386
5,037'
SFD 2/23/2023
223-016
DSR-3/22/23MGR27FEB2023
113
50-029-23748-00-00
JLC 2/27/2023
2/27/23
2/27/23
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.02.27 12:27:48 -09'00'
M-63 Planned Schrader
Bluff Oa intersection Point
TD of M-64
planned Injector
M-63 AOR Map
•All Wells Labelled at top Oa intersection point
•Greenlines represent the footage inwellsthat are within
Schrader Bluff inside the ¼ mile radius of proposed
injector, M-63
•Red triangles indicatewells thathavenot been drilledyet
PTD API WELL STATUS
Top of SB
OA (MD)
Top of SB
OA (TVD)
Top of
Cement
(MD)
Top of
Cement
(TVD) Schrader OA status Zonal Isolation
222-128 50-029-23734-00-00 MPU M-32 Oa Producer 8352 3993 Surface Surface Open Cement returns observed at surface.
222-137 50-029-23736-00-00 MPU M-33 Oa Injector 8020 4026 Surface Surface Open Cement returns observed at surface.
TBD TBD MPU M-62 Oa Producer N/A N/A N/A N/A N/A Not Drilled
218-022 50-029-23599-00-00 MPU F-110 Oa Injector 7413 4039 Surface Surface Open Cement returns observed at surface.
218-014 50-029-23596-00-00 MPU F-109 Oa Producer 6401 4063 Surface Surface Open
Cement behind 9-5/8" pipe - covering Schrader Bluff OA, 2 stage cement job
w/ cement returned to surface.
200-066 50-029-22959-00-00 MPU F-81 Kuparuk Producer 7204 4044 Surface Surface Closed
Cement behind 9-5/8" pipe - covering Schrader Bluff OA, 770 bbls of Artic
lite 10.7 ppg followed by 42 bbls of class G 15.8 ppg. Plug bumped floats
198-217 50-029-22928-00-00 MPU F-80 P&A'd Kuparuk Producer 6258 4074 Surface Surface Closed
7" production casing cemented to surface.
9-5/8" x 7" annulus cemented to surface.
208-186 50-029-23406-00-00 MPU F-96 Kuparuk Producer 7781 4025 Surface Surface Closed
Cement behind 10 3/4" pipe - covering Schrader Bluff OA, 2 stage cement
job cement returns observed at surface.
Area of Review MPU M-63 SB OA
Agree. SFD 2/23/2023
Milne Point Unit
(MPU) M-63
Application for Permit to Drill
Version 1
2/20/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 N/U BOP and Test.................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ...................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 39
18.0 RDMO ...................................................................................................................................... 40
19.0 Post-Rig Work ......................................................................................................................... 41
20.0 Doyon 14 Diverter Schematic .................................................................................................. 42
21.0 Doyon 14 BOP Schematic ........................................................................................................ 43
22.0 Wellhead Schematic ................................................................................................................. 44
23.0 Days vs Depth ........................................................................................................................... 45
24.0 Formation Tops & Information............................................................................................... 46
25.0 Anticipated Drilling Hazards .................................................................................................. 48
26.0 Doyon 14 Layout ...................................................................................................................... 51
27.0 FIT Procedure .......................................................................................................................... 52
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 53
29.0 Casing Design ........................................................................................................................... 54
30.0 8-1/2” Hole Section MASP ....................................................................................................... 55
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 57
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M-63 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU M-63
Pad Milne Point “M” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Oa Sand
Planned Well TD, MD / TVD 19,712’ MD / 4,109’ TVD
PBTD, MD / TVD 19,712’ MD / 4,109’ TVD
Surface Location (Governmental) 242' FNL, 291' FEL, Sec. 14, T13N, R9E, UM, AK
Surface Location (NAD 27) X= 533874 Y= 6027890
Top of Productive Horizon
(Governmental)2582' FNL, 518' FEL, Sec 12, T13N, R9E, UM, AK
TPH Location (NAD 27) X= 538910 Y= 6030854
BHL (Governmental) 1872' FSL, 141' FEL, Sec 35, T14N, R9E, UM, AK
BHL (NAD 27) X= 533956 Y= 6040563
AFE Drilling Days 21 days
AFE Completion Days 4 days
Maximum Anticipated Pressure
(Surface) 1386 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1793 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 25.2 ft = 58.9 ft
GL Elevation above MSL: 25.2 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
M-63 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
M-63 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2”5-1/2” 4.892”4.767”6.050”17 L-80 JFE Bear 7,740 6,290 397
4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80
EUE 8RD 9289 7399 163
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 GPDS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
M-63 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp, nathan.sperry@hilcorp.com
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 mmyers@hilcorp.com
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 Todd Sidoti 907.777.8443 Todd.Sidoti@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 reedwards@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
Page 6
Milne Point Unit
M-63 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Milne Point Unit
M-63 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
MPU M-63 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-63 is part of a
multi well development program targeting the Schrader Bluff sand on M-pad. Hilcorp requests to pre-
produce M-63 for up to 30 days.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in the
open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately May 4th, 2023, pending rig schedule.
Surface casing will be run to 8,900’ MD / 19,712’ 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 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 & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 5-1/2” x 4-1/2” injection liner.
7. Run 3-1/2” tubing.
8. 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)
p
o pre-ppg
produce M-63 for up to 30 days.
Page 8
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M-63 SB Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
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 M-63. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 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)”.
Page 9
Milne Point Unit
M-63 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for a test period of pre-producing M-63 for up to 30 days via a reverse
circulating jet pump completion. This will allow us to measure skin and evaluate the benefits of pre-
producing our injectors in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is
online and producing. Section 19 details the steps required to make this happen. Note also that the MIT-IA
has been changed from 2,500 psi to 3,500 psi.
mgr
* Approved to pre-produce for 30 days with reverse circulation jet pump.
* 24/7 manned monitoring on MPU M pad if no surface safety valve while on IA power fluid injection when on
30 day pre-production period.
Page 10
Milne Point Unit
M-63 SB Injector
Drilling Procedure
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 (BOP’s 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 PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11
Milne Point Unit
M-63 SB Injector
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 M-63 will utilize a newly set 20” conductor on M-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 12
Milne Point Unit
M-63 SB Injector
Drilling Procedure
10.0 N/U 21-1/4” 2M 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.
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Milne Point Unit
M-63 SB Injector
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
Page 14
Milne Point Unit
M-63 SB Injector
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Use GWD until MWD surveys clean up.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
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
packoff’s, 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 Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
x Gas hydrates have not been seen on M-pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be
prepared for hydrates:
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x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x AC:
x There are no wells with clearance factors < 1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate zone
x 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.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) can be used in the system while drilling the surface interval to
prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
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System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F
System Formulation:Gel + FW spud mud
Product- 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, 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.
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
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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 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 8-1/2” 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.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 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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12.4 Float equipment and Stage tool equipment drawings:
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12.5 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.
12.6 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 damage 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
Halliburton Type H ES-II Stage tool d at least 100’ TVD below
the permafrost.
yj (p g
Verify depth of lowest Ugnu water sand for isolation with Geologist
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12.7 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
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12.8 Ensure the permafrost is covered with 9-5/8” 47#. Estimated XO depth is 2500’.
x Ensure drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 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.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 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 amount 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.
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Estimated 1st Stage Total Cement Volume:
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 is in the Stage 1 Table in step 13.7.
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 if the plugs are not bumped.
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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13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.15 Increase pressure to 3300 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 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. 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 is in the Stage 2 table in step 13.22.
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 Land closing plug on stage collar and pressure up to 1000 – 1500 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
13.28 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 N/U BOP and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 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 2-7/8” x 5” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x N/U 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 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” 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
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg FloPro fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” 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 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 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. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swabbed kick at 9.2ppg
BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
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 Ensure MWD is R/U 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 DS50 & NC50.
x Run a ported float in the production hole section.
Email casing test and FIT digital data to AOGCC promptly upon completion of FIT. email: melvin.rixse@alaska.gov
mgr
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Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg 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 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.13 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 P/U
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 Surveys can be taken more frequently if deemed necessary.
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.
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 (under 250 fph) without having to backream
connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x 8-1/2” Lateral A/C:
x There are no wells with a clearance factor <1.0.
x Schrader Bluff OA Concretions: 4-6% Historically
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 sidetrack low and right 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 (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so 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.
x 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 (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
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Drilling Procedure
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
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 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud 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
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion)
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and
run them slick.
The uppermost 3,000’ of liner will be 5-1/2”.
16.1.Well control preparedness: In the event of an influx of formation fluids while running the
injection liner with slotted liner, the following well control response procedure will be followed:
x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” 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 5-1/2” liner.
x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 5-1/2” and 4-1/2” liner running equipment.
x Ensure 5-1/2” and 4-1/2” Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 5-1/2” x 4-1/2” injection liner.
x Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
x Uppermost 2,000’ will be 5-1/2”.
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 If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt
outside of the surface shoe. This is to mitigate 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” 17# L-80 JFE Bear
Casing OD Minimum Optimum Maximum
Operating Torque
5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs
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4-1/2” 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 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 5-1/2” 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
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16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball 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.
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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 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 R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD (Set below 70 degrees)
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
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17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i. Note this test must be witnessed by the AOGCC representative.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Pull BPV. Set TWC. Test tree to 5000 psi.
17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
3600 psi or maximum power fluid header pressure.
mgr
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19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 12B jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
mgr
mgr
24/7 manned monitoring on MPU M pad if no surface safety valve while on IA power fluid injection.
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20.0 Doyon 14 Diverter Schematic
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21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
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22.0 Wellhead Schematic
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23.0 Days vs Depth
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24.0 Formation Tops & Information
TOP
NAME
TVD
(FT)
TVDSS
(FT)
MD
(FT)
Formation
Pressure
(psi)
EMW
(ppg)
Base
Permafrost 1,889 1,830 2,084 831 8.46
SV1 1,930 1,871 2,155 849 8.46
UG4 2,154 2,095 2,700 948 8.46
UG_MB 3,590 3,531 6,888 1,579 8.46
SB NB 3,908 3,849 7,845 1,719 8.46
SB OA 4,066 4,007 8,805 1,789 8.46
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L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad)
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25.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate
gas behave 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 ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x There are no wells with a CF < 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.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
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1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is one mapped fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
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. Abnormal (offset injection) pressure has been seen on M-
Pad. 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 There are no wells with a clearance factor less than 1.0.
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26.0 Doyon 14 Layout
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27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
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28.0 Doyon 14 Choke Manifold Schematic
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29.0 Casing Design
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30.0 8-1/2” Hole Section MASP
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31.0 Spider Plot (NAD 27) (Governmental Sections)
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32.0 Surface Plat (As-Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
)HEUXDU\
3ODQ 0380ZS
+LOFRUS$ODVND//&
0LOQH3RLQW
03W0RRVH3DG
3ODQ 0380
0380
07501500225030003750True Vertical Depth (1500 usft/in)-2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000Vertical Section at 333.00° (1500 usft/in)MPU M-63 wp07 tgt01 Oa1MPU M-63 wp07 tgt02 Oa3MPU M-63 wp07 tgt03 Oa3MPU M-63 wp07 tgt04 Oa1MPU M-63 wp07 tgt05 Oa1MPU M-63 wp07 tgt06 Oa3MPU M-63 wp07 tgt07 Oa3MPU M-63 wp07 tgt08 Oa1MPU M-63 wp07 tgt09 Oa1MPU M-63 wp07 tgt10 Oa3MPU M-63 wp07 tgt11 Oa3MPU M-63 wp07 tgt12 Oa1MPU M-63 wp07 tgt13 Oa1MPU M-63 wp07 tgt14 Oa3MPU M-63 wp07 tgt15 Oa3MPU M-63 wp07 tgt16 Oa1MPU M-63 wp07 tgt17 Oa1MPU M-63 wp07 tgt18 Oa3MPU M-63 wp07 tgt19 Oa39 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008000850090009500100001050011000115001200012500130001350014000145001500015500160001650017000175001800018500190001950019712MPU M-63 wp07Start Dir 3º/100' : 500' MD, 500'TVDStart Dir 3.9º/100' : 1100' MD, 1092.46'TVDEnd Dir : 2512.19' MD, 2090.27' TVDStart Dir 4.1º/100' : 6159.1' MD, 3325.03'TVDEnd Dir : 8629.9' MD, 4050.65' TVDStart Dir 2.5º/100' : 8804.9' MD, 4065.9'TVDEnd Dir : 8822.74' MD, 4067.39' TVDBegin GeosteeringStart Dir 2.5º/100' : 9111.9' MD, 4090.43'TVDEnd Dir : 9268.95' MD, 4097.59' TVDStart Dir 2.5º/100' : 10618.95' MD, 4112.9'TVDEnd Dir : 10757.46' MD, 4110.29' TVDStart Dir 2.5º/100' : 10892.75' MD, 4103.66'TVDEnd Dir : 11005.21' MD, 4100.9' TVDStart Dir 2.5º/100' : 11955.21' MD, 4100.9'TVDEnd Dir : 12092.19' MD, 4104.99' TVDStart Dir 2.5º/100' : 12227.49' MD, 4113.07'TVDEnd Dir : 12380.54' MD, 4117.1' TVDStart Dir 2.5º/100' : 13555.54' MD, 4108.9'TVDEnd Dir : 13659.35' MD, 4105.87' TVDStart Dir 2.5º/100' : 13918.38' MD, 4092.54'TVDEnd Dir : 14028.35' MD, 4089.52' TVDStart Dir 2.5º/100' : 14778.35' MD, 4086.9'TVDEnd Dir : 14869.45' MD, 4087' TVDStart Dir 2.5º/100' : 15196.83' MD, 4088.82'TVDEnd Dir : 15270.72' MD, 4088.06' TVDStart Dir 2.5º/100' : 15620.72' MD, 4078.9'TVDEnd Dir : 15765.22' MD, 4072.27' TVDStart Dir 2.5º/100' : 15923.61' MD, 4061.9'TVDEnd Dir : 16079.29' MD, 4056.98' TVDStart Dir 2.5º/100' : 16323.73' MD, 4057.53'TVDEnd Dir : 16474.58' MD, 4062.7' TVDStart Dir 2.5º/100' : 16824.58' MD, 4085.9'TVDEnd Dir : 16986.68' MD, 4091.72' TVDStart Dir 2.5º/100' : 17384.45' MD, 4093.9'TVDEnd Dir : 17491.52' MD, 4092.13' TVDStart Dir 2.5º/100' : 17687.72' MD, 4084.56'TVDEnd Dir : 17781.64' MD, 4082.84' TVDStart Dir 2.5º/100' : 18391.64' MD, 4083.9'TVDEnd Dir : 18617.2' MD, 4095' TVDStart Dir 2.5º/100' : 18650.24' MD, 4098.19'TVDEnd Dir : 18871.93' MD, 4108.9' TVDTotal Depth : 19711.93' MD, 4108.9' TVDSV6Base PermafrostSV1UG4UG_MBSB_NBSB_OAHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU M-6325.20+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.006027889.680533873.790 70° 29' 14.0009 N 149° 43' 23.2815 WSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1500.00 MPU M-63 wp07 (MPU M-63) GYD_Quest GWD1500.00 8900.00 MPU M-63 wp07 (MPU M-63) 3_MWD+IFR2+MS+Sag8900.00 19711.93 MPU M-63 wp07 (MPU M-63) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation841.90 783.00 843.59 SV61888.90 1830.00 2083.60 Base Permafrost1929.90 1871.00 2154.94 SV12153.90 2095.00 2700.12 UG43589.90 3531.00 6888.09 UG_MB3907.90 3849.00 7844.95 SB_NB4065.90 4007.00 8804.90 SB_OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-63, True NorthVertical (TVD) Reference:MPU M-63 as built location @ 58.90usftMeasured Depth Reference:MPU M-63 as built location @ 58.90usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Moose PadWell:Plan: MPU M-63Wellbore:MPU M-63Design:MPU M-63 wp07CASING DETAILSTVD TVDSS MD SizeName4073.55 4014.65 8900.00 9-5/8 9 5/8" x 12 1/4"4108.90 4050.00 19711.93 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect TargetAnnotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00Start Dir 3º/100' : 500' MD, 500'TVD3 750.00 7.50 125.00 749.29 -9.37 13.38 3.00 125.00 -14.434 1100.00 15.41 87.34 1092.46 -20.34 78.73 3.00 -63.00 -53.87Start Dir 3.9º/100' : 1100' MD, 1092.46'TVD5 2512.19 70.21 77.14 2090.27 149.53 984.76 3.90 -11.72 -313.84End Dir : 2512.19' MD, 2090.27' TVD6 6159.10 70.21 77.14 3325.03 913.26 4330.21 0.00 0.00 -1152.15Start Dir 4.1º/100' : 6159.1' MD, 3325.03'TVD7 8629.90 85.00 333.22 4050.65 2786.01 5128.71 4.10 -99.58 153.96End Dir : 8629.9' MD, 4050.65' TVD8 8804.90 85.00 333.22 4065.90 2941.64 5050.16 0.00 0.00 328.30 MPU M-63 wp07 tgt01 Oa1Start Dir 2.5º/100' : 8804.9' MD, 4065.9'TVD9 8822.74 85.43 333.10 4067.39 2957.50 5042.13 2.50 -15.88 346.07End Dir : 8822.74' MD, 4067.39' TVD10 9111.90 85.43 333.10 4090.43 3214.55 4911.71 0.00 0.00 634.32Start Dir 2.5º/100' : 9111.9' MD, 4090.43'TVD11 9268.95 89.35 333.30 4097.59 3354.56 4840.98 2.50 2.96 791.17End Dir : 9268.95' MD, 4097.59' TVD12 10618.95 89.35 333.30 4112.90 4560.53 4234.44 0.00 0.00 2141.07 MPU M-63 wp07 tgt03 Oa3Start Dir 2.5º/100' : 10618.95' MD, 4112.9'TVD13 10757.46 92.81 333.16 4110.29 4684.16 4172.08 2.50 -2.27 2279.53End Dir : 10757.46' MD, 4110.29' TVD14 10892.75 92.81 333.16 4103.66 4804.73 4111.07 0.00 0.00 2414.66Start Dir 2.5º/100' : 10892.75' MD, 4103.66'TVD15 11005.21 90.00 333.25 4100.90 4905.07 4060.40 2.50 178.22 2527.07End Dir : 11005.21' MD, 4100.9' TVD16 11955.21 90.00 333.25 4100.90 5753.40 3632.81 0.00 0.00 3477.06 MPU M-63 wp07 tgt05 Oa1Start Dir 2.5º/100' : 11955.21' MD, 4100.9'TVD17 12092.19 86.58 333.37 4104.99 5875.72 3571.31 2.50 178.04 3613.96End Dir : 12092.19' MD, 4104.99' TVD18 12227.49 86.58 333.37 4113.07 5996.44 3510.77 0.00 0.00 3749.01Start Dir 2.5º/100' : 12227.49' MD, 4113.07'TVD19 12380.54 90.40 333.20 4117.10 6133.08 3442.00 2.50 -2.51 3901.97End Dir : 12380.54' MD, 4117.1' TVD20 13555.54 90.40 333.20 4108.90 7181.84 2912.24 0.00 0.00 5076.94 MPU M-63 wp07 tgt07 Oa3Start Dir 2.5º/100' : 13555.54' MD, 4108.9'TVD21 13659.35 92.95 333.69 4105.87 7274.65 2865.85 2.50 10.81 5180.69End Dir : 13659.35' MD, 4105.87' TVD22 13918.38 92.95 333.69 4092.54 7506.53 2751.18 0.00 0.00 5439.36Start Dir 2.5º/100' : 13918.38' MD, 4092.54'TVD23 14028.35 90.20 333.70 4089.52 7605.07 2702.47 2.50 179.73 5549.27End Dir : 14028.35' MD, 4089.52' TVD24 14778.35 90.20 333.70 4086.90 8277.43 2370.17 0.00 0.00 6299.21 MPU M-63 wp07 tgt09 Oa1Start Dir 2.5º/100' : 14778.35' MD, 4086.9'TVD25 14869.45 89.68 331.48 4087.00 8358.30 2328.23 2.50 -103.19 6390.31End Dir : 14869.45' MD, 4087' TVD26 15196.83 89.68 331.48 4088.82 8645.96 2171.93 0.00 0.00 6717.57Start Dir 2.5º/100' : 15196.83' MD, 4088.82'TVD27 15270.72 91.50 331.80 4088.06 8710.97 2136.84 2.50 9.89 6791.43End Dir : 15270.72' MD, 4088.06' TVD28 15620.72 91.50 331.80 4078.90 9019.32 1971.50 0.00 0.00 7141.23 MPU M-63 wp07 tgt11 Oa3Start Dir 2.5º/100' : 15620.72' MD, 4078.9'TVD29 15765.22 93.76 334.62 4072.27 9148.16 1906.46 2.50 51.31 7285.56End Dir : 15765.22' MD, 4072.27' TVD30 15923.61 93.76 334.62 4061.90 9290.961838.72 0.00 0.00 7443.54 MPU M-63 wp07 tgt12 Oa1Start Dir 2.5º/100' : 15923.61' MD, 4061.9'TVD31 16079.29 89.87 334.87 4056.98 9431.66 1772.35 2.50 176.46 7599.04End Dir : 16079.29' MD, 4056.98' TVD32 16323.73 89.87 334.87 4057.53 9652.95 1668.53 0.00 0.00 7843.35Start Dir 2.5º/100' : 16323.73' MD, 4057.53'TVD33 16474.58 86.20 334.00 4062.70 9788.93 1603.47 2.50 -166.76 7994.04End Dir : 16474.58' MD, 4062.7' TVD34 16824.58 86.20 334.00 4085.90 10102.82 1450.38 0.00 0.00 8343.22 MPU M-63 wp07 tgt14 Oa3Start Dir 2.5º/100' : 16824.58' MD, 4085.9'TVD35 16986.68 89.69 331.93 4091.72 10247.07 1376.77 2.50 -30.71 8505.17End Dir : 16986.68' MD, 4091.72' TVD36 17384.45 89.69 331.93 4093.90 10598.06 1189.61 0.00 0.00 8902.87 MPU M-63 wp07 tgt15 Oa3Start Dir 2.5º/100' : 17384.45' MD, 4093.9'TVD37 17491.52 92.21 332.82 4092.13 10692.90 1139.97 2.50 19.45 9009.91End Dir : 17491.52' MD, 4092.13' TVD38 17687.72 92.21 332.82 4084.56 10867.31 1050.43 0.00 0.00 9205.96Start Dir 2.5º/100' : 17687.72' MD, 4084.56'TVD39 17781.64 89.90 332.40 4082.84 10950.69 1007.23 2.50 -169.61 9299.86End Dir : 17781.64' MD, 4082.84' TVD40 18391.64 89.90 332.40 4083.90 11491.27 724.62 0.00 0.00 9909.83 MPU M-63 wp07 tgt17 Oa1Start Dir 2.5º/100' : 18391.64' MD, 4083.9'TVD41 18617.20 84.46 333.88 4095.00 11692.17 622.87 2.50 164.82 10135.02End Dir : 18617.2' MD, 4095' TVD42 18650.24 84.46 333.88 4098.19 11721.70 608.40 0.00 0.00 10167.90Start Dir 2.5º/100' : 18650.24' MD, 4098.19'TVD43 18871.93 90.00 333.80 4108.90 11920.37510.81 2.50 -0.84 10389.22End Dir : 18871.93' MD, 4108.9' TVD44 19711.93 90.00 333.80 4108.90 12674.06 139.95 0.00 0.00 11229.14 MPU M-63 wp07 tgt19 Oa3Total Depth : 19711.93' MD, 4108.9' TVD
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
12750
South(-)/North(+) (1500 usft/in)-2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500
West(-)/East(+) (1500 usft/in)
MPU M-63 wp07 tgt19 Oa3
MPU M-63 wp07 tgt18 Oa3
MPU M-63 wp07 tgt17 Oa1
MPU M-63 wp07 tgt16 Oa1
MPU M-63 wp07 tgt15 Oa3
MPU M-63 wp07 tgt14 Oa3
MPU M-63 wp07 tgt13 Oa1
MPU M-63 wp07 tgt12 Oa1
MPU M-63 wp07 tgt11 Oa3
MPU M-63 wp07 tgt10 Oa3
MPU M-63 wp07 tgt09 Oa1
MPU M-63 wp07 tgt08 Oa1
MPU M-63 wp07 tgt07 Oa3
MPU M-63 wp07 tgt06 Oa3
MPU M-63 wp07 tgt05 Oa1
MPU M-63 wp07 tgt04 Oa1
MPU M-63 wp07 tgt03 Oa3
MPU M-63 wp07 tgt02 Oa3
MPU M-63 wp07 tgt01 Oa1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"1000125017502000225025002750300032503
5
00
3750
4 0 0 0
4 1 0 9
MPU M-63 wp07
Start Dir 3º/100' : 500' MD, 500'TVD
Start Dir 3.9º/100' : 1100' MD, 1092.46'TVD
End Dir : 2512.19' MD, 2090.27' TVD
Start Dir 4.1º/100' : 6159.1' MD, 3325.03'TVD
End Dir : 8629.9' MD, 4050.65' TVD
Start Dir 2.5º/100' : 8804.9' MD, 4065.9'TVD
End Dir : 8822.74' MD, 4067.39' TVD
Begin Geosteering
Start Dir 2.5º/100' : 9111.9' MD, 4090.43'TVD
End Dir : 9268.95' MD, 4097.59' TVD
Start Dir 2.5º/100' : 10618.95' MD, 4112.9'TVD
End Dir : 10757.46' MD, 4110.29' TVD
Start Dir 2.5º/100' : 10892.75' MD, 4103.66'TVD
End Dir : 11005.21' MD, 4100.9' TVD
Start Dir 2.5º/100' : 11955.21' MD, 4100.9'TVD
End Dir : 12092.19' MD, 4104.99' TVD
Start Dir 2.5º/100' : 12227.49' MD, 4113.07'TVD
End Dir : 12380.54' MD, 4117.1' TVD
Start Dir 2.5º/100' : 13555.54' MD, 4108.9'TVD
End Dir : 13659.35' MD, 4105.87' TVD
Start Dir 2.5º/100' : 13918.38' MD, 4092.54'TVD
End Dir : 14028.35' MD, 4089.52' TVD
Start Dir 2.5º/100' : 14778.35' MD, 4086.9'TVD
End Dir : 14869.45' MD, 4087' TVD
End Dir : 15270.72' MD, 4088.06' TVD
Start Dir 2.5º/100' : 15620.72' MD, 4078.9'TVD
End Dir : 15765.22' MD, 4072.27' TVD
Start Dir 2.5º/100' : 15923.61' MD, 4061.9'TVD
Start Dir 2.5º/100' : 16323.73' MD, 4057.53'TVD
End Dir : 16474.58' MD, 4062.7' TVD
Start Dir 2.5º/100' : 16824.58' MD, 4085.9'TVD
End Dir : 16986.68' MD, 4091.72' TVD
Start Dir 2.5º/100' : 17384.45' MD, 4093.9'TVD
End Dir : 17491.52' MD, 4092.13' TVD
Start Dir 2.5º/100' : 17687.72' MD, 4084.56'TVD
End Dir : 17781.64' MD, 4082.84' TVD
Start Dir 2.5º/100' : 18391.64' MD, 4083.9'TVD
End Dir : 18617.2' MD, 4095' TVD
Start Dir 2.5º/100' : 18650.24' MD, 4098.19'TVD
End Dir : 18871.93' MD, 4108.9' TVD
Total Depth : 19711.93' MD, 4108.9' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4073.55 4014.65 8900.00 9-5/8 9 5/8" x 12 1/4"
4108.90 4050.00 19711.93 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt Moose Pad
Well: Plan: MPU M-63
Wellbore: MPU M-63
Plan: MPU M-63 wp07
WELL DETAILS: Plan: MPU M-63
25.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6027889.680 533873.790
70° 29' 14.0009 N 149° 43' 23.2815 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU M-63, True North
Vertical (TVD) Reference:MPU M-63 as built location @ 58.90usft
Measured Depth Reference:MPU M-63 as built location @ 58.90usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650 7125 7600 8075 8550 9025Measured Depth (950 usft/in)MPU F-110MPU M-62 wp06MPU M-11MPU M-64 wp07MPL-32 - revised gyroMPF-81MPU M-10No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU M-63 NAD 1927 (NADCON CONUS)Alaska Zone 0425.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027889.680533873.79070° 29' 14.0009 N149° 43' 23.2815 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-63, True NorthVertical (TVD) Reference:MPU M-63 as built location @ 58.90usftMeasured Depth Reference:MPU M-63 as built location @ 58.90usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU M-63 wp07 (MPU M-63) GYD_Quest GWD1500.00 8900.00 MPU M-63 wp07 (MPU M-63) 3_MWD+IFR2+MS+Sag8900.00 19711.93 MPU M-63 wp07 (MPU M-63) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650 7125 7600 8075 8550 9025Measured Depth (950 usft/in)MPU M-62 wp06MPU M-11Kup N1 from Slot 34MPU M-20MPU M-12GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference33.70 To 19711.93Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-63Wellbore: MPU M-63Plan: MPU M-63 wp07Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4073.55 4014.65 8900.00 9-5/8 9 5/8" x 12 1/4"4108.90 4050.00 19711.93 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 18000 18600 19200 19800 20400Measured Depth (1200 usft/in)MPF-96MPU F-110MPU M-62 wp06MPU M-64 wp07MPF-81MPU M-33MPF-80MPU M-32No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU M-63 NAD 1927 (NADCON CONUS)Alaska Zone 0425.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027889.680533873.79070° 29' 14.0009 N149° 43' 23.2815 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-63, True NorthVertical (TVD) Reference:MPU M-63 as built location @ 58.90usftMeasured Depth Reference:MPU M-63 as built location @ 58.90usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU M-63 wp07 (MPU M-63) GYD_Quest GWD1500.00 8900.00 MPU M-63 wp07 (MPU M-63) 3_MWD+IFR2+MS+Sag8900.00 19711.93 MPU M-63 wp07 (MPU M-63) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 18000 18600 19200 19800 20400Measured Depth (1200 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference33.70 To 19711.93Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-63Wellbore: MPU M-63Plan: MPU M-63 wp07Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4073.55 4014.65 8900.00 9-5/8 9 5/8" x 12 1/4"4108.90 4050.00 19711.93 4-1/2 4 1/2" x 8 1/2"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
Milne Point
MPU M-63
223-016
Schrader Bluff Oil
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT M-63Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230160MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes Surface Location lies within ADL0025514; Top Productive Interval lies in ADL0388235; TD lies in ADL0355018.2 Lease number appropriateYes3 Unique well name and numberYes Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05.4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes MPU M-32 (222-128), MPU M-33 (222-137), MPU F-110 (218-022), MPU F-109 (218-014),15 All wells within 1/4 mile area of review identified (For service well only)Yes MPU F-81 (200-066), MPU F-80 (198-217), MPU F-96 (208-186)16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 105'18 Conductor string providedYes 9-5/8" surface casing fully cemented with shoe set in the SB reservoir19 Surface casing protects all known USDWsYes Fully cemented with stage collar and excess cement20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented from surface to reservoir22 CMT will cover all known productive horizonsYes 9-5/8" 47# L-80 from surface to BOPF, 9-5/8" 40# L-80 from BOPF to reservoir23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 has adequate tankage and good trucking support24 Adequate tankage or reserve pitYes This is a grass roots well25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identified no close approaches26 Adequate wellbore separation proposedYes 16" diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to pore pressure28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram, 1 flow cross29 BOPEs, do they meet regulationYes 5M psi 13-5/8" stack tested to 3000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo MPU M pad has no history of H2S33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S: not expected. Rig has sensors and alarms; mitigation discussed on p. 50.35 Permit can be issued w/o hydrogen sulfide measuresYes Abnormal Pressure: low potential; mitigation on p. 50. Managed pressure drilling techniques will be used.36 Data presented on potential overpressure zonesNA Faulting: one fault crossing expected; mitigation discussed on p. 50.37 Seismic analysis of shallow gas zonesNA Lost circulation: some potential; mitigation discussed on p. 50.38 Seabed condition survey (if off-shore)NA Gas Hydrates: Not expected; mitigation discussed on p. 14, 15, 48.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate2/23/2023ApprMGRDate2/27/2023ApprSFDDate2/23/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 2/27/2023
