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Alaska Oil and Gas Conservation Commission
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RBDMS JSB 072623
Completed
6/27/2023
JSB
By Meredith Guhl at 3:35 pm, Aug 24, 2023
G
DSR-8/28/23MGR17MAY2024
Drilling Manager
07/25/23
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.07.26 07:33:04 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Edited By: JNL 6/30/2023
SCHEMATIC
Milne Point Unit
Well: MPU M-64
Last Completed: 6/27/2023
PTD: 223-034
TD =20,052’(MD) / TD =4,131’(TVD)
4
20”
Orig. KB Elev.: 59.14’ / GL Elev.: 25.4’
7”
6
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =20,050’(MD) / PBTD =4,131’(TVD)
9-5/8” ‘ES’
Cementer @
2,622’
5
7
9
12
8
4-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,605’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,605’ 8,941’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 8,749’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / JFE Bear 4.780 8,746’ 11,691’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 11,691’ 20,052’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 8,762’ 0.0152
OPEN HOLE / CEMENT DETAIL
42” 12 yds Concrete
12-1/4"Stg 1 Lead – 1000 sx / Tail – 400 sx
Stg 2 Lead – 870 sx / Tail 270 sx
8-1/2” Uncemented Screened Liner
WELL INCLINATION DETAIL
KOP @ 242’
90° Hole Angle = @ 9,096’
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: 50-029-23753-00-00
Completion Date: 6/27/2023
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 7,069’ Viking X Profile Sliding Sleeve (opens down) 3.813”
3 7,130’ Baker Zenith Gauge Carrier 3.865”
7,193’ X Nipple 3.813”
4 7,252’ Baker Retrievable Packer 3.960”
5 7,320’ XN Nipple, 3.813”, 3.725” No Go 3.725”
6 8,727’ WLEG/Mule Shoe 3.958”
7 8,746’ SLZXP Liner Top Packer 6.180”
8 8,767’ 7” H563 x 4.5” TSH 625 XO 4.810”
9 20,050’ Shoe 3.970”
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 8920’ 4083’ 11691’ 4099’
4-1/2” 11735’ 4098’ 20010’ 4129’
Activity Date Ops Summary
6/3/2023 Spot the rig and center over well M-64. Shim and level the rig. PJSM. Skid the rig floor into drilling position. 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. NU knife valve. Work on rig
acceptance check list. Spot the rock washer and RU. Install the surface bell nipple, riser and mouse hole. NU the diverter line. Install the 4" conductor valves. Load
HWDP and BHA into the DS pipe shed. Load DP in the ODS pipe shed. Rig on highline power at 12:30 hours. Work on rig acceptance check list. Ready pit for
taking on fluid and load the hopper room with mud product. NU the diverter line. Remove hopper #2 and install new hopper. Changeout valves and seats in mud
pump #1. Work on rig acceptance check list. Slip and cut 46' (7 wraps) of drilling line. Calibrate the block height, service the top drive. Work on rig acceptance
check list. Changeout the saver sub. Inspect grabber dies. MU and rack back 6 stands 5" HWDP including jar stand. Start loading the pits with spud mud and rig
accepted at 03:30 hours. Mobilize BHA components to the rig floor. Perform the diverter function test with 5" HWDP. The states right to witness was waived by
AOGCC inspector Kam StJohn on 6/03/2023 at 06:27 hours. Test, gas alarms, PVT and flow sensors - good. Knife valve opened in 14 seconds and the annular
closed in 20 seconds. Accumulator Test: System pressure = 3,100 psi. Pressure after closure = 1,950 psi. 200 psi attained in 41 seconds. Full pressure attained in
155 seconds. Nitrogen Bottles - 6 at 1,970 psi (average). Diverter length = 437'. Nearest ignition source = 123' (facility). MU 12-1/4" tricone bit, 8" mud motor with
1.5 AKO, crossover and 1 stand of 5" HWDP. RIH with stand and tag up at 113' MD. Fill the stack with water and check for leaks - none. PT mud lines to 3,500 psi -
good test.
6/4/2023 Pre-Spud meeting with all personnel. Clean out conductor from 113' to 114' and spud well. Drill 12-1/4" surface hole from 114' to 218'. Spud well and drill 12-1/4""
surface hole from 114' to 218' (218' TVD). 400 GPM = 450 psi, 50 RPM = 1-2K ft-lbs TQ, WOB = 1-5K. PU = 50K, SO = 50K & ROT = 0K. Swap to spud mud on
the fly. Pull out of the hole and lay down 12-1/4" VMD-3 cleanout bit. Bit grade: 1-1-WT-A-E-I-NO-BHA. Clean and clear rig floor. MU BHA #2, 12-1/4" drilling
assembly with Kymera bit, 1.5 AKO motor, Gyro and MWD tools. Scribe motor and obtain tool face offsets for Gyro and MWD. Plug in and upload MWD tools. TIH
to 188', shallow test BHA and continue to TIH on 5" HWDP to 218'. Obtain first Gyro survey at 176'. Drill 12-1/4"" surface hole from 218' to 470' (469' TVD). Drilled
252' = 56'/hr AROP. 425 GPM = 910 psi, 40 RPM = 2-4K ft-lbs TQ, WOB = 5-6K. PU = 70K, SO = 74K & ROT = 0K. MW = 9.1 ppg, Vis = 220, ECD = 9.75 ppg.
Start 3 deg/100' build at 240'. Drill 12-1/4"" surface hole from 470' to 968' (951' TVD). Drilled 498' = 83'/hr AROP. 500 GPM = 1,330 psi, 80 RPM = 2-5K ft-lbs TQ,
WOB = 5-7K. PU = 86K, SO = 86K & ROT = 86K. MW = 9.0+ ppg, Vis = 189, ECD = 9.82 ppg. Start 3.5 deg/100' build at 860'. Drill 12-1/4"" surface hole from
968' to 1,601 (1,481' TVD). Drilled 633' = 105.5'/hr AROP. 500 GPM = 1,528 psi, 80 RPM = 5K ft-lbs TQ, WOB = 5-9K. PU = 91K, SO = 90K & ROT = 92K. MW =
9.1+ ppg, Vis = 197, ECD = 10.16 ppg, max gas = 31 units. Last Gyro survey at 1,180' MD, Swap to MWD surveys. Distance from WP11= 4.76, 1.91 low & 4.36
right.
6/5/2023 Drill 12-1/4"" surface hole from 1,601' to 2,363 (1,906' TVD). Drilled 762' = 127'/hr AROP. 500 GPM = 1,570 psi, 80 RPM = 6K ft-lbs TQ, WOB = 5-12K. PU =
105K, SO = 84K & ROT = 93K. MW = 9.3+ ppg, Vis = 161, ECD = 10.16 ppg, max gas = 80 units. Start 4.2 deg/100' build at 1,610'. On generator power at 11:30
per request from MPU due to plant issues. Base of permafrost at 2,344 (1,895 TVD). Drill 12-1/4"" surface hole from 2,363' to 3,220' (2,203' TVD). Drilled 857' =
142.8'/hr AROP. 550 GPM = 2,080 psi, 80 RPM = 6-7K ft-lbs TQ, WOB = 4-7K. PU = 110K, SO = 80K & ROT = 93K. MW = 9.3+ ppg, Vis = 153, ECD = 10.66
ppg, max gas = 634 units. Start 69 deg tangent section at 2,363'. Pump 30 bbl hi-vis sweep at 2,555', back on time with 20% increase. Rig back on high line power
at 15:30 hours. Drill 12-1/4"" surface hole from 3,220' to 4,076' (2,500' TVD). Drilled 856' = 142.7'/hr AROP. 507 GPM = 2,000 psi, 60 RPM = 8-10K ft-lbs TQ,
WOB = 6-7K. PU = 124K, SO = 79K & ROT = 99K. MW = 9.3+ ppg, Vis = 156, ECD = 10.69 ppg, max gas = 107 units. Pump 30 bbl hi-vis sweep at 3,507', back
on time with 30% increase. Drill 12-1/4"" surface hole from 4,076' to 4,970' (2,835' TVD). Drilled 894' = 149'/hr AROP. 550 GPM = 2,350 psi, 80 RPM = 12-14K ft-
lbs TQ, WOB = 10-18K. PU = 133K, SO = 81K & ROT = 104K. MW = 9.3 ppg, Vis = 114, ECD = 10.61 ppg, max gas = 133 units. Pump 30 bbl hi-vis sweep at
4,555', back on time with 100% increase.
6/6/2023 Drill 12-1/4" surface hole from 4,970' to 5,599' (3,071' TVD). Drilled 629' = 104.8'/hr AROP. 500 GPM = 2,530 psi, 80 RPM = 15K ft-lbs TQ, WOB = 10-18K. PU =
145K, SO = 75K & ROT = 106K. MW = 9.4 ppg, Vis = 224, ECD = 10.62 ppg, max gas = 133 units. Pump 30 bbl hi-vis sweep at 5,409': came back 250 strokes
late with 50% increase. Drill 12-1/4" surface hole from 5,599' to 6,459' (3,387' TVD). Drilled 629' = 104.8'/hr AROP. 540 GPM = 2,430 psi, 80 RPM = 14-15K ft-lbs
TQ, WOB = 10K. PU = 158K, SO = 78K & ROT = 114K. MW = 9.4 ppg, Vis = 300+, ECD = 10.98 ppg, max gas = 82 units. Logged the Ugnu L sand at 6,319'.
Pump 30 bbl hi-vis sweep at 6,455', did not see at surface due to high viscosity of the mud. Drill 12-1/4" surface hole from 6,459' to 7,050' (3,603' TVD). Drilled 591'
= 98.5'/hr AROP. 544 GPM = 2,500 psi, 80 RPM = 15-17K ft-lbs TQ, WOB = 5-7K. PU = 165K, SO = 77K & ROT = 117K
MW = 9.4+ ppg, Vis = 214, ECD = 11.02 ppg, max gas = 208 units. Begin build at 4.3 deg/100' and turn at 6,550'. Drill 12-1/4" surface hole from 7,050' to 7,693'
(3,836' TVD). Drilled 643' = 107.2'/hr AROP. 561 GPM = 2,550 psi, 80 RPM = 20K ft-lbs TQ, WOB = 15K. PU = 185K, SO = 77K & ROT = 120K. MW = 9.3+ ppg,
Vis = 130, ECD = 10.80 ppg, max gas = 216 units. Logged the Ugnu M sand at 7,072'. Distance from WP11 at survey depth of 7,545 = 1.99, 1.13 high & 1.64 left.
6/7/2023 Drill 12-1/4" surface hole from 7693' to 7978' (3915' TVD). Drilled 285' = 47.5'/hr AROP. 550 GPM = 2,700 psi, 80 RPM = 20-24K ft-lbs TQ, WOB = 17K. PU =
185K, SO = 75K & ROT = 120K. MW = 9.3+ ppg, Vis = 94, ECD = 10.70 ppg, max gas = 131 units. Increase lubes to 0.75% to help with directional. Drill 12-1/4"
surface hole from 7978' to 8430' (4020' TVD). Drilled 452' = 75.3'/hr AROP. 540 GPM = 2740 psi, 80 RPM = 19-21K ft-lbs Tq, WOB = 15-16K. PU = 190K, SO =
76K & ROT = 125K. MW = 9.3+ ppg, Vis = 108, ECD = 10.56 ppg, max gas = 434 units. Pump 30 bbl high-vis sweep at 8265': Mud returns viscosity at 300, sweep
was not recognized at surface. Drill 12-1/4" surface hole f/ 8430' t/ 8816' (4072' TVD). Drilled 386' = 64.3'/hr AROP. 560 GPM, 2900 psi, 80 RPM, 19-21K Tq,
WOB 22-25K. MW = 9.4 ppg, Vis 136, ECD 11.07 ppg, Max Gas = 208u. PU 195K, SO 70K, ROT 120K. Drill 12-1/4" surface hole f/ 8816' t/ 8946' (4084' TVD).
Drilled 130' = 43.3'/hr AROP. 550 GPM, 2550 psi, 80 RPM, 20-24K Tq, WOB 5-15K. MW = 9.35 ppg, Vis 130, ECD 10.80 ppg, Max Gas = 216u. PU 184K, SO
80K, ROT 120K. Geo called TD at 8946', ~10' below top of the SB_OA. SB_OA sand at 8817' MD / 4074' TVD. Distance from WP11 at survey depth of 8895 =
7.93', 8.84' low & 1.99' left. BROOH t/ 8835' MD while loading Hi-Vis sweep in string. Circulate hole clean and condition mud, racking back a stand with each
bottoms up f/ 8835' t/ 8644'. 550 GPM, 2220 psi, 60 RPM, 18-22K Tq. Sweep return was not recognized. MW in/out 9.35/9.45 Vis in/out 56/224.
50-029-23753-00-00API #:
Well Name:
Field:
County/State:
MP M-64
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
6/4/2023Spud Date:
6/8/2023 Continue circulate and condition mud, rotating and reciprocating pipe f/ 8739' T/8644', alternating stop points. 550 GPM, 2200 psi, 80 RPM, 19K Tq. Add 0.25% Lo-
Torq. Circulated a total of 3.5x bottoms up strokes. MW (in/out) 9.3/9.4+ ppg, Vis (in/out) 50/160 sec. Run in the hole on elevators f/ 8739' t/ 8946', no issues and no
fill on bottom. Monitor well prior to coming out of the hole - static. BROOH from 8946' to 7788' pulling 8-12 minutes/stand slowing as needed to clean up slides/tight
spots. 550 GPM = 2250 psi, 80 RPM = 18-22K ft-bs Tq, ECD= 10.19 ppg, max gas = 7u. BROOH from 7788' to 5905' pulling 8-12 minutes/stand slowing as
needed to clean up slides/tight spots. 550 GPM = 1900 psi, 60 RPM = 12-15K ft-bs Tq, ECD= 10.40 ppg, max gas = 57u. PU = 155K, SO = 85K, ROT = 110K. 5-8
BPH losses. BROOH from 5905' to 3983' pulling 5-12 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1840 psi, 60 RPM = 10-15K ft-bs
Tq, ECD= 9.97 ppg, max gas = 32u. PU = 136K, SO = 76K, ROT = 101K. 5-8 BPH losses. BROOH from 3983' to 1633' pulling 5-12 minutes/stand slowing as
needed to clean up slides/tight spots. 500 GPM = 1250 psi, 60-80 RPM = 6-10K ft-bs Tq, ECD= 10.42 ppg, max gas = 208u. PU = 105K, SO = 88K, ROT = 101K.
5-8 BPH losses.
6/9/2023 BROOH from 1633' to top of HWDP at 778' pulling 5-12 minutes/stand slowing as needed to clean up slides/tight spots. 500 GPM = 1250 psi, 60-80 RPM = 6-10K
ft-bs Tq, ECD= 10.42 ppg, max gas = 208u. PU = 105K, SO = 88K, ROT = 101K. 5-8 BPH losses. Monitor well - static. Pull and stand back HWDP and jars from
778' to 190'. Pull and lay down NM flex collars from 190' to 98'. 5-15K drag noted while pulling jars into conductor. Lay down 12-1/4" drilling BHA per DD and MWD
from 98'. Plug in and download MWD tools. 12-1/4" Kymera Dull Bit Grade-- PDC: 1-2-CT-G-X-I-NO-TD Cones: 1-3-LT-A-F-I-WT-TD. Clean and clear rig floor.
Mobilize casing running equipment to rig floor. Make up Volant CRT, bail extensions, elevators, spiders and tongs. Make up XO on rig floor. Verify pipe counts and
tally. PJSM with rig crew, DDI Casing and Halliburton Cementing. MU 9-5/8", 40#, L-80, TXP-BTC shoe track to 161' Baker Lok connections 1-4 with 21k ft-lbs Tq.
HES rep installed top hat above float collar. Pump through shoe track and check floats - good. Static loss rate = 4 BPH. RIH with 9-5/8", 40#, L-80, TXP-BTC casing
from 161' to 1621', Tq = 21k ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. PU = 97K, SO = 82K. Loss rate = 5-12
BPH. RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 1621' to 2439'. Tq = 21k ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer
per tally. PU = 125K, SO = 90K. Loss rate = 7-8 BPH. Circulate one casing volume, stage up to 6 BPM = 160 psi. PU = 140K, SO = 90K. 7 bbls loss while
circulating. Continue RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 2439' to 3258'. Tq = 21k ft-lbs with Volant tool. Fill on the fly and top off every 10 joints.
Installing centralizer per tally. PU = 145K, SO = 95K. Loss rate = 7-10 BPH.
6/10/2023 Continue RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 3258' to 5185'. Tq = 21k ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing
centralizer per tally. PU = 225K, SO = 90K. Loss rate = 7-8 BPH. Continue RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 5185' to 6134'. Tq = 21k ft-lbs with
Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. PU = 243K, SO = 105K. Loss rate = 7-13 BPH. CBU, stage up to 6 BPM = 310
psi. No losses recorded while circulating. Continue RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 6134' to 6298'. Tq = 21k ft-lbs with Volant tool. Fill on the fly
and top off every 10 joints. Installing centralizer per tally. Baker Loc and M/U ESC with pup joints as per HES rep to 6337'. RIH with 9-5/8", 47#, L-80, TXP-BTC
casing from 6337' to 8945'. Tq = 23.8K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizers per tally. Wash down last 57', no fill
encountered. Loss rate 5-12 bph, 379 bbls total loss running casing. Stage the pumps up to 6 BPM = 540 psi. Rot & Recip string 50', 5 RPM 15k Tq. Circulate and
condition the mud for the cement job. SimOps: Cementers spotted in and RU. Prep the Mud Pits. Final MW 9.4 ppg, 47 vis, YP= 14. 10 bbl losses circulating. PU=
325K, SO= 90K. HES pump truck lost power to deck motors that run the engine. Call out new pump truck. Continue circulating 6 BPM while wait on truck. Blow
down top drive. Rig up cement lines to Volant tool cement swivel. Re-dope Volant cup and clean dies. Continue to circulate 6 BPM = 230 psi FCP. Sim Ops: Rig up
on new HES pu.mp truck. Hold PJSM with all parties involved. HES prime up system. Rig pump 50 bbls of mud treated with Desco. Shut down the rig pumps. HES
flood lines with fresh water and pump 5 bbls downhole. PT lines to 1,000/4,000 psi - good test.
6/11/2023 Pump 1st stage cement job: Mix & pump 60 bbls of 10 ppg tuned spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 4.5 BPM = 300 psi. Drop bypass plug.
Mix and pump 393 bbls of 12.0 ppg lead cement (EconoCem, Type I/II), 2.347ft^3/sk yield, 1000 sks total) at 4.8 BPM = 410 psi. 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 3.6 BPM = 600 psi. Drop shut off plug. HES pump 20 bbls water at 5 BPM. Displace
with 440 bbls of 9.4 ppg spud mud from the rig at 6 BPM = 520 psi ICP & 450 psi FCP. Pumped 80 bbls of 9.4 ppg tuned spacer from Halliburton at 5 BPM = 520
psi. Pumped 128 bbls 9.4 ppg mud from the rig at 6 BPM = 520 psi ICP & 750 psi FCP. Slow rate to 3 BPM for last 12 bbls = 690 psi FCP, Bumped the plug at
5629 stks, 6.5 bbls late, CIP @ 10:51. Pressure to 1,250 psi, Hold 3 min, bleed off pressure, floats held. Pressure to 3350 psi shifting ESC open. Shoe set at 8941'.
36 bbl losses cementing and displacing. P/U wt at 425k and losing SOW at 400 bbls into displacement. Parked casing on depth at 8941'. Circulate through ES
cementer at 2622', 6 BPM 230 psi, good interface at 1730 stks, start divert to RW. Dump 50.2 bbls cement, 42.1 bbls spacer, 70.2 bbls interface. Take returns to
pits. Stage up to 6 BPM, circulate 5 BU total. FCP= 230 psi. Flush surface bag, clean cement valves and jet flow line with blackwater. 24 hr BOP notification
submitted to AOGCC at 14:47. Continue to circulate through the ES cementer 6 BPM 220 psi while waiting on cement for 2nd stage. Prep for 2nd stage cement job.
Clean both pumps suction screens. General housekeeping around rig. Break out the Volant, dope the cup and M/U the Volant. Hold PJSM with all parties involved.
Continue circulating while finish staging H2O truck and prime up. Blow air through the cement line to the cement unit. Pump 2nd stage cement job: Pump 5 bbls of
water and PT lines to 1,000/4,000 psi (good test). Mix & pump 60 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 4 BPM = 150 psi.
Mix & pump total 440 bbls 10.7 ppg ArcticCem lead cement (870 sx at 2.855 ft^3/sk yield) at 4.5 BPM, ICP= 317 FCP= 694 psi. At 295 bbls pumped start seeing
spacer returns, dump returns to rock washer. At 434 bbls pumped seeing good cement returns. Mix & pump 56 bbls of 15.8 ppg HalCem tail cement (270 sx at
1.165 ft^3/sk yield) at 4 BPM= 694 psi. Drop the closing plug. Pump 20 bbls of 8.34 ppg fresh water at 4 BPM = 210 psi. Displace cement with 9.4 ppg spud mud. 6
BPM = 370 psi ICP, 700 psi FCP. Slowed to 3 BPM = 650 PSI for last 10 bbls. Bumped plug at 1733 strokes, 3 bbls late of calc. Pressure up & shift ES cementer
closed at 1650 PSI. Pressure up to 2200 psi, hold for 5 min. Bleed pressure off. No flow, confirm cementer closed. CIP at 00:05. 89 bbls Interface, 60 bbls spacer
and 317 bbls of cement returned to surface, overboarded to Rockwasher. Blow down lines. Disconnect the knife valve from the accumulator. Drain the cement from
the stack to the cellar and flush with black water three times. Rig down the Volant CRT and vacuum out mud from the casing. N/D diverter vent line from knife valve.
L/D 90' mousehole. Hoist the diverter stack. Install casing slips as per wellhead rep with 110K on the slips. Cut 9-5/8" casing and L/D cut joint and pup joint. Cut
joint length = 19.51'. SimOps: N/D diverter line. Empty and clean mud pits & Rockwasher. N/D surface riser, diverter stack and diverter tee. Clean cement from knife
valve.
6/12/2023 Nipple down surface riser, annular, diverter T and vent lines. Install slip-lock wellhead per wellhead rep and pressure test void 500 psi for 5 min, 3800 psi for 10 min
- good test. Nipple up tubing spool and BOPE stack. SIMOPS: Welder repairing crack on top drive bracket. Change upper rams to 4-1/2" x 7" VBRs. Install trip
nipple, Obtain RKBs, Grease choke manifold. Install 1502 flange on annulus vavle. M/U top drive test sub. R/U BOPE testing equipment. Install the test plug. Flood
the stack, lines and choke manifold with fresh water. Purge air from the system. Shell test the BOP stack to 250/3,000 psi (passed). Conduct initial BOPE test to
250/3,000 psi: UPR (4-1/2" x 7" VBR) with 4-1/2", 5'' & 7" test jts. LPR (2-7/8" x 5" VBRs) with 4-1/2" & 5" test jts, annular with 4-1/2" test jt. All tests performed with
fresh water against test plug. Accumulator drawdown test & test gas alarms. Tests: 1. Annular on 4.5" test joint, choke valves 1, 12, 13 & 14, Kill Demco & 5" Dart
Valve. 2. UPR 4.5"x7" VBR on 4.5" test joint, choke valves 9,11 & 5" FOSV. 3. LPR 2.875"x5" VBR on 4.5" test joint ** Failed **. 4. UPR 4.5"x7" VBR on 7" test
joint, choke valves 5, 8 & 10, HCR kill & Upper IBOP. 5. Choke valves 4, 6, & 7, Manual Kill & Lower IBOP. 6. Choke valve 2. 7. HCR choke & 3.5" Dart Valve. 8.
Manual Choke & 3.5" FOSV. 9. Blind rams & Choke valve 3. 10. Hyd, Super Choke A. 11. Manual Super Choke B. Perform Accumulator test: 3100 psi sys
pressure, 1700 psi after closure, 200 psi recovery in 44 sec, full recovery in 205 sec, 6 N2 bottle avg = 1850 PSI. Rig electrician tested rig gas alarms. Bag close in
17 sec, UPR close in 7 sec, LPR close in 7 sec, HCRs in 2 sec. PJSM, Change out 2-7/8"x5" LPR.
6/13/2023 Flood the stack, lines and choke manifold with fresh water. Purge air from the system. Test Lower 2-7/8x5 VBRs to 250/3,000 psi (passed). Pull test plug. Install 9-
1/8 wear bushing. Rig down test equipment and blow down lines. M/U 8-1/2 Clean-Out assembly to 590'. 8-1/2" Smith XR+CPS Tricone bit, 6-3.4" Mud Motor with
non-ported float installed in top and ABH set at 1.5 deg, 2 stands 5"HWDP, Jar Stand and final 3 stands 5" HWDP. Trip in hole with clean out assembly on 5" DP f/
590' t/ 2588. PU=97k, SO=70k. Fill the pipe, wash and ream from 2588'. Tag hard cement at 2615. Drill cement, plug and ES cementer from 2615' to 2622' at 400
GPM = 770psi, 40 RPM = 7K ft-lbs Tq, WOB = 10-12k. Wash and ream through ESC 2 times and drift through without pump/rotary. Trip in hole with clean out
assembly on 5" DP f/ 2622 to 8678 MD. PU=225K, SO= 55K. Wash/Ream down f/ 8678. 400 GPM = 1200 psi, 30 RPM = 22-25K ft-lbs Tq. Tag cement at 8801 w/
10k. CBU. Rack back 1 stand DP. R/U test equipment and purge air from the system. Close upper pipe rams. PT the 9-5/8" ,40#/47# casing to 2,500 psi for 30
minutes, charted (good test). Blow down and R/D test equipment. Pumped 6.3 bbls & bled back 6.3 bbls. Continue to drill cement, plugs, BA, 9-5/8" shoe track and
float equipment from 8801' to 8941' at 400 GPM = 1230 psi, 40 RPM = 22K ft-lbs Tq, WOB = 10-12K. PU = 275K, SO = 55K & ROT = 120K. All equipment on
depth. Clean out rat hole from 8941' to 8946'. Drill 20' of new formation from 8946' to 8966' at 450 GPM = 1580 psi, 50 RPM = 24k ft-lbs Tq, WOB = 5-12k. Lay
down a single and pull assembly into the 9-5/8 casing. Circulate and condition the mud for the FIT at 475 GPM = 1450 psi, 50 RPM = 23ft-lbs Tq reciprocating 61'.
Good 9.3 ppg in & out. Flow check the well - static. Rack stand back. Blow down the top drive. Flow check the well - static. RU testing equipment, flood the lines and
purge the air. Close the UPR on 5" DP, pump down DP & kill line. Perform 12.0 ppg FIT with 9.3 ppg MW at 4084' TVD, 575 psi at surface - good test. RD and blow
down testing equipment. TOOH from 8867' to 8393'. Pump dry job and blow down the top drive. TOOH from 8393' to 8293'. 260k PUW.
6/14/2023 TOOH from 8293 to 590 Monitor Well on last stand DP- Static. Rack last stand DP in Derrick. L/D 5" HWDP from 10 jts HWDP, stand back the jar stand & L/D 5
remaining jts HWDP. L/D mud motor and bit. Bit grade: 1-1-WT-A-E-2-NO-BHA. Lost 21 bbls while TOOH. Clear and clean rig floor. Remove the master bushings
and install the split bushings. MU 8-1/2" NOV PDC bit, NRP-A2 bit sleeve, 7600 Geo-Pilot, iStar suite, GWD, Telemetry collar and stabilizer to 119'. Plug in &
initialize MWD. M/U ADR recorded only collar & IBS, plug in and initialize. M/U remaining BHA #4, NM float sub, 3 NM flex collars, NM float sub and 2 HWDP with
jars to 342'. TIH with 8-1/2" lateral BHA from 340' to 2247' on 5'' drill pipe. M/U top drive fill pipe, Break in geo pilot seals, shallow pulse test tools, 425 gpm, 1070
psi, 30 rpm, 8K torque, good. TIH from 2247' to 8715' with stands 5'' drill pipe. Single in with 5'' DP to 8905'. Correct displacement TIH. PU 275K, SO 50K. Rig up
and jet the flowline clean. 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. Displace the well from 9.3 ppg spud mud to 8.8 ppg FloPro at 6 BPM = 710 psi ICP, 40 RPM = 24K ft-lbs Tq. Wash to TD then with new
mud out the bit pull into the 9 5/8' casing.
6/15/2023 Finish displacing the Well from 9.3 ppg spud mud to 8.8 ppg FloPro at 6 BPM. Total of 670 bbls Flo-Prop pumped. 100 bbls spacer and interface dumped to RW.
FCP= 600 psi and final Tq= 17K ft-lbs. PU 225K, SO 75K, ROT 118K. Obtain SPRs. Slip and cut 79' of drilling line. Service top drive, Inspect brake bands
equalizer bar. Obtain SPR's and establish drilling parameters. Drill 8-1/2" lateral from 8966' to 9191' (4088' TVD), 225' drilled, 112'/hr AROP. 450-500 GPM = 1590
PSI, 120 RPM = 19-20K ft-lbs Tq, 11-17K WOB. MW = 8.8 ppg, vis = 42, ECD = 10.26, Max Gas = 679u. PU = 190K, SO = 60K ROT = 113K. Back ream full
stands. MPD choke full open while drilling and shut in on connections, 0 psi build. Drill 8-1/2" lateral from 9191' to 9763' (4095' TVD), 572' drilled, 95.3'/hr AROP.
500 GPM = 1680 PSI, 120 RPM = 10K ft-lbs Tq, 11-17K WOB. MW = 9.0 ppg, vis = 41, ECD = 10.30, Max Gas = 402u. PU = 155K, SO = 76K ROT = 115K. Back
ream 30'. MPD choke full open while drilling and shut in on connections, 0 psi build. Add 0.5% Lube 776 @ 9500'. Decreased Tq f/ 17-20k to 9-10k, PUW f/ 190k
to 155k and increased SOW f/ 60k to 76k. Drill 8-1/2" lateral from 9763' to 10334' (4100' TVD), 571' drilled, 95.2'/hr AROP. 550 GPM = 2100 PSI, 120 RPM = 9-
11K ft-lbs Tq, 5K WOB. MW = 9.1 ppg, vis = 41, ECD = 10.61, Max Gas = 333u. PU = 155K, SO = 75K ROT = 112K. Pump Hi-Vis sweep at 9953', Back on time
w/ 20% increase. MPD choke full open while drilling, trapping 80 psi on connections. Drill down section from OA-1 to OA-3 then follow dip at 88.7 deg-89 deg. Drill
8-1/2" lateral from 10334' to 10809' (4111' TVD), 475' drilled, 79.17'/hr AROP. 550 GPM = 2160 PSI, 120 RPM = 14K ft-lbs Tq, 15K WOB. MW = 8.9 ppg, vis = 39,
ECD = 10.5, Max Gas = 605u. PU = 163K, SO = 75K ROT. MPD choke full open while drilling, trapping 80 psi on con. Target 88.3 dip in OA-3. Last survey at
10714.14' MD / 4109.16' TVD, 88.99 inc, 329.27 azm, 22.49' from plan, 1.50' low and 22.50' left. We have drilled 19 concretions for a total thickness of 118' (6.7%
of the lateral).
6/16/2023 Drill 8-1/2" lateral from 10809' to 11290' (4111' TVD), 481' drilled, 80'/hr AROP. 565 GPM = 2160 PSI, 120 RPM = 14K ft-lbs Tq, 15K WOB. MW = 8.9 ppg, vis =
39, ECD = 10.5, Max Gas = 605u. PU = 163K, SO = 75K ROT= 113K. Pump Hi-Vis sweep at 11,001', Back 300 strks late w/ 100% increase. MPD choke full open
while drilling, trapping 110 psi on connections. Drilling up section in OA-3 at 91. Drill 8-1/2" lateral from 11290' to 11759' (4093' TVD), 469' drilled, 78'/hr AROP.
550 GPM = 2190 PSI, 120 RPM = 11K ft-lbs Tq, 10K WOB. MW = 9.0 ppg, vis = 41, ECD = 10.82, Max Gas = 492u. PU = 155K, SO = 74K ROT= 112K. MPD
choke full open while drilling, trapping 110 psi on connections. Start drilling up section, at 11353', from the OA-3 targeting the OA-1. Drill 8-1/2" lateral from 11759'
to 12234' (4095' TVD), 475' drilled, 79'/hr AROP. 550 GPM = 2310 PSI, 120 RPM = 9K ft-lbs Tq, 11K WOB. MW = 9.0 ppg, vis = 41, ECD = 11.05, Max Gas =
557u. PU = 154K, SO = 72K ROT = 115K. Pump Hi-Vis sweep at 11949', Back 300 strks late w/ 100% increase. MPD choke full open while drilling, trapping 110
psi on connections. Target the lower portion of the OA-1 in preparation for possible fault at 12300. Drill 8-1/2" lateral from 12234' to 12900' (4106' TVD), 666' drilled,
111'/hr AROP. 550 GPM = 2410 PSI, 120 RPM = 10K ft-lbs Tq, 9K WOB. MW = 9.1 ppg, vis = 41, ECD = 11.3, Max Gas = 426u. PU = 155K, SO = 72K ROT =
113K. MPD choke full open while drilling, trapping 110 psi on connections. No fault was discernable at 12300'. Continue to maintain the OA-1 until 12640' then
target 88 deg inc to undulate back down to OA-3. We have drilled 49 concretions for a total thickness of 256' (6.6% of the lateral). Last survey at 12805.25' MD /
4096.28' TVD, 88.07 inc, 336.29 azm, 6.83' from plan, 2.21' high and 6.46' left.
6/17/2023 Drill 8-1/2" lateral from 12900' to 13373' (4110' TVD), 473' drilled, 39'/hr AROP. 550 GPM = 2490 PSI, 120 RPM = 13K ft-lbs Tq, 11K WOB. MW = 9.1 ppg, vis =
41, ECD = 11.2, Max Gas = 425u. PU = 160K, SO = 68K ROT = 112K. Encountered fault #1 at 12900' - 5' DTW throw, Encountered fault #2 at 13065' - 3' DTW
throw. MPD choke full open while drilling, trapping 110 psi on connections. Pump Sweep at 12995' back 300 strks late 100% increase. Re-entered OA-3 at 13115'.
In lower OA-3 targeting 90.5 deg. Drill 8-1/2" lateral from 13373' to 13947' (4098' TVD),574' drilled, 96'/hr AROP. 550 GPM = 2400 PSI, 120 RPM = 14K ft-lbs Tq,
10K WOB. MW = 9.1 ppg, vis = 42, ECD = 11.09, Max Gas = 434u. PU = 155K, SO = 0K ROT = 111K. In lower OA-3 targeting formation dip at 91 deg. MPD
choke full open while drilling, trapping 115 psi on connections. At 13700', start building up section to revert to OA-1. Drill 8-1/2" lateral from 13947' to 14517' (4086'
TVD), 570' drilled, 95'/hr AROP. 550 GPM = 2380 PSI, 120 RPM = 12K ft-lbs Tq, 12K WOB. MW = 9.0 ppg, vis = 39, ECD = 11.1, Max Gas = 439u. PU = 160K,
SO = 62K ROT = 120K. MPD choke full open while drilling, trapping 120 psi on connections. Pump Hi-Vis sweep at 13947', Back 300 stks late w/ 50% increase.
Perform 330 bbl whole mud dilution at 13947'. Drop MBT f/ 6.5 t/ 5.0. Drill 8-1/2" lateral from 14517' to 15182' (4095' TVD), 665' drilled, 111'/hr AROP. 550 GPM =
2470 PSI, 120 RPM = 14K ft-lbs Tq, 13K WOB. MW = 9.0 ppg, vis = 41, ECD = 11.2, Max Gas = 559u.
PU = 163K, SO = 0K ROT = 113K. MPD choke full open while drilling, trapping 120 psi on connections. Pump Hi-Vis sweep at 14992', Back 350 stks late w/ 30%
increase. Maintain the OA-1 to 14775' then start dropping trajectory to undulate back down to OA-3. We have drilled 58 concretions for a total thickness of 351'
(5.7% of the lateral). Last survey at 15086.50' MD / 4089.58' TVD, 90.89 inc, 337.59 azm, 16.10' from plan, 14.10' low and 7.70' left.
6/18/2023 Drill 8-1/2" lateral from 15182' to 15664' (4080' TVD), 482' drilled, 80'/hr AROP. 550 GPM = 2510 PSI, 120 RPM = 16K ft-lbs Tq, 15K WOB. MW = 8.9 ppg, vis =
39, ECD = 11.1, Max Gas = 428u. PU = 170K, SO = 0K ROT = 111K. Stayed low in OA-3 Targeting 90 deg to avoid F-96. At 15275' was closest with 136' of
separation. MPD choke full open while drilling, trapping 120 psi on connections. Drill 8-1/2" lateral from 15664' to 16042' (4080' TVD), 378' drilled, 63'/hr AROP.
550 GPM = 2420 PSI, 120 RPM = 20K ft-lbs Tq, 13K WOB. MW = 9 ppg, vis = 41, ECD = 11.26, Max Gas = 389u. PU = 175K, SO = 0K ROT = 110K. Pump
sweep at 15947' back 500 stks late w/ 30% increase. Drilling ahead in OA-3 prepping for up coming fault. MPD choke full open while drilling, trapping 120 psi on
connections. Drill 8-1/2" lateral from 16042' to 16706' (4078' TVD), 664' drilled, 110'/hr AROP. 550 GPM = 2430 PSI, 120 RPM = 15K ft-lbs Tq, 10K WOB. MW = 9
ppg, vis = 41, ECD = 11.47, Max Gas = 411u. PU = 168K, SO = 0K ROT = 107K. MPD choke full open while drilling, trapping 120 psi on connections. Fault #3 at
16221' with 15' DTW throw, placed wellbore from the OA-3 into the lower/middle OA-1. Drill 8-1/2" lateral from 16706' to 17277' (4079' TVD), 571' drilled, 95'/hr
AROP. 550 GPM = 2550 PSI, 120 RPM = 18K ft-lbs Tq, 17K WOB. MW = 8.9 ppg, vis = 43, ECD = 11.40, Max Gas = 652u. PU = 178K, SO = 0K ROT = 112K.
MPD choke full open while drilling, trapping 120 psi on connections. Pump Hi-Vis sweep at 16993', Back 500 stks late w/ 100% increase. Maintain the OA-1 to
17087' then start dropping trajectory to undulate back down to OA-3. We have drilled 92 concretions for a total thickness of 522' (6.4% of the lateral). Last survey at
17086.94' MD / 4078.18' TVD, 89.79 inc, 336.53 azm, 13.90' from plan, 2.31' low and 13.71 left.
6/19/2023 Drill 8-1/2" lateral from 17277' to 17840' (4107' TVD), 563' drilled, 94'/hr AROP. 500 GPM = 2420 PSI, 120 RPM = 17K ft-lbs Tq, 10K WOB. MW = 8.9 ppg, vis =
43, ECD = 11.50, Max Gas = 379u. PU = 180K, SO = 0K ROT = 114K. In OA-1 targeting 88 deg undulate down the the OA-3. MPD choke full open while drilling,
trapping 120 psi on connections. Drill 8-1/2" lateral from 17840' to 18133' (4115' TVD), 293' drilled, 49'/hr AROP. 410 GPM = 1570 PSI, 120 RPM = 18K ft-lbs Tq,
3-12K WOB. MW = 9 ppg, vis = 41, ECD = 11.1, Max Gas = 283u. PU = 190K, SO = 0K ROT = 113K. MPD choke full open while drilling, trapping 120 psi on
connections. Entered OA-3 at 17650' and targeting 86.5 deg. Swapped from High line to Gen power at 13:15. At 17944', due to traction motor blower fan going out,
limited to one mud pump @ 415 GPM and 100'/hr. Pump Sweep at 17943' - 250 stks late, 20% increase. Swap back to High line power at 17:30. Drill 8-1/2" lateral
from 18133' to 18418' (4119' TVD), 305' drilled, 51'/hr AROP. 500 GPM = 2360 PSI, 120 RPM = 19K ft-lbs Tq, 3-5K WOB. MW = 8.9 ppg, vis = 38, ECD = 11.23,
Max Gas = 433u. PU = 190K, SO = 0K ROT = 109K. MPD choke full open while drilling, trapping 120 psi on connections. #2 MP traction motor was replaced and
MP back on line at 18228'. Perform 580 bbl whole mud dump & dilute at 18355'. Dropped MBTs down from 6.75 to 3.5. Drill 8-1/2" lateral from 18418' to 19048'
(4107' TVD), 630' drilled, 105'/hr AROP. 550 GPM = 2475 PSI, 120 RPM = 20K ft-lbs Tq, 18K WOB. MW = 8.85 ppg, vis = 40, ECD = 11.41, Max Gas = 628u. PU
= 195K, SO = 0K ROT = 111K. MPD choke full open while drilling, trapping 120 psi on connections. Start building at 18500' for Wells final revert to OA-1. Hi-Vis
sweep at 18989', currently in hole. Last survey at 18893.16' MD/4108.10' TVD, 90.89 deg inc, 332.49 deg azm, 13.38' from plan, 13.11' high and 2.67' left. We
have drilled 110 concretions for a total thickness of 602' (6.0% of the lateral).
6/20/2023 Drill 8-1/2" lateral from 19,048' to 19520' (4114' TVD), 472' drilled, 78'/hr AROP. 550 GPM = 2870 PSI, 120 RPM = 20K ft-lbs Tq, 8K WOB. MW = 8.9 ppg, vis =
39, ECD = 11.2, Max Gas = 946u. PU = 208K, SO = 0K ROT = 121K. MPD choke full open while drilling, trapping 140 psi on connections. Hi-Vis sweep pumped at
18,989' back 650 stks late with 50% increase. Encountered fault #5 at 19400' throw 15' DTE placing the well bore in the OA-3. Drill 8-1/2" lateral from 19,520' to
20,000' (4131' TVD), 480' drilled, 80'/hr AROP. 550 GPM = 2760 PSI, 120 RPM = 20K ft-lbs Tq, 6-8K WOB. MW = 8.9 ppg, vis = 39, ECD = 11.32, Max Gas =
812u. PU = 210K, SO = 0K ROT = 124K. MPD choke full open while drilling, trapping 140 psi on connections. At 15:36 lost 250 psi stand pipe pressure due to
aired up mud. Added defoamer and screen clean. Drill 8-1/2" lateral from 20,000' to 20,052' (4130' TVD), 52' drilled, 52'/hr AROP. 525 GPM = 2620 PSI, 120 RPM
= 21K ft-lbs Tq, 5K WOB. MW = 9.0 ppg, vis = 41, ECD = 11.41, Max Gas = 693u. PU = 225K, SO = 0K ROT = 129K. Obtain final survey. Pump 30 bbls high vis
sweep, back 700 stks late with 0% increase. Circulate a total of 3 bottoms up, racking back a stand every bottoms up from 20052' to 19828' at 500 GPM = 2550 psi,
120 RPM = 20K ft-lbs Tq. Final survey at 19,995' MD / 4130' TVD, 87.19 deg INC, 335.19 deg AZM. Distance from WP11 = 22.86', 17.58' low & 10.57' left. We
have drilled 136 concretions for a total thickness of 722' (6.5% of the lateral). Wash/ream to bottom and continue circulating, 525 GPM, 2130 psi. Rot and
reciprocate 50', 60 RPM, 15k Tq. PU 206k, SO 0k, Rot 134k. PJSM for displacing. Pump 30 bbls high 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 1626 bbls of 8.45 ppg viscosified brine with 3%
lubes (1.5% 776 and 1.5% LoTorq). 6 BPM = 1200 psi (ICP), 40 RPM = 20K ft-lbs Tq & 6 BPM = 930 psi (FCP), 60 RPM = 19K ft-lbs Tq, reciprocating 50'
alternating stopping points. 100 bbl interface dumped. Shut down the pumps with clean 8.45 ppg viscosified brine to surface. no losses recorded. Perform PST, 3
sec, 3 sec and 3.1 sec.
6/21/2023 Parked at 20,038' monitor wellbore for pressure build with MPD choke 4 times 5 min each, 65 psi, 48 psi, 43 psi with the final building to 37 psi. EMW= 8.7 ppg.
Record new SPRs, wash and ream to TD. PU = 225K, SO = 0K, ROT =141K. Simops: Clean pit 3 and load 8.45 ppg 3% lube brine in pits 3 & 4. BROOH from
20,052' to 19,182' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Rack back 10 stands HWDP on DS. 450 GPM = 1880 psi, 120 RPM
= 20K ft-lbs TQ, max gas = 54 units. PU = 225K, SO = 0K & ROT = 135K. BROOH from 19,182' to 17,946' pulling 5-10 minutes/stand slowing as needed to clean
up slides/tight spots. Laying down DP in the mouse hole. 450-500 GPM = 1,730/2,000 psi, 120 RPM = 24 ft-lbs TQ, max gas = 157 units. PU = 200K, SO = 0K &
ROT = 135K. Loss rate = 30-33 BPH. BROOH from 17,946' to 15,468' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down
DP in the mouse hole. 500 GPM = 1,820 psi, 120 RPM = 20K ft-lbs TQ, max gas = 157 units. PU = 175K, SO = 0K & ROT = 120K. Loss rate = 15-27 BPH.
BROOH from 15,468' to 12,807' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 500 GPM = 1,680
psi, 120 RPM = 15K ft-lbs TQ, max gas = 72 units. PU = 160K, SO = 75K & ROT = 117K. Average loss rate = 16 BPH. Regained SO weight at 15,185'. BROOH
from 12,807' to 9,668' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 500 GPM = 1,570 psi, 120
RPM = 12K ft-lbs TQ, max gas = 106 units. PU = 163K, SO = 75K & ROT = 125K. Average loss rate = 17 BPH.
6/22/2023 BROOH from 9,668' to 9,260' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 500 GPM = 1,500
psi, 120 RPM = 12K ft-lbs TQ, max gas = 151 units. PU = 163K, SO = 75K & ROT = 117K. Average loss rate = 17 BPH. Pull the BHA into the shoe rotating 40
RPM = 6K ft-lbs TQ from 9,260' to 8,905' at 500 GPM = 1,450 psi, no issues. Lost total of 438 bbls BROOH. Pump 30 bbl hi-vis sweep at 500 GPM = 1460 psi, 60
RPM = 4.5K ft-lbs TQ reciprocating 90' and circulate the casing clean with 2 BU. Sweep back on time with no increase. increase. Monitor the wellbore pressure with
MPD choke 5 times 5 minutes each = 60, 46, 38, 31, & 28 psi. Current MW 8.7ppg. EMW = 8.9 ppg & KWF = 9.1 ppg. Weight up the surface system to 8.9 ppg.
Circulate 8.9 ppg while weighting up the returns on the fly to 8.9 ppg at 6 BPM = 490 psi, 60 RPM = 5-8K ft-lbs TQ reciprocating 90' until good 8.9 ppg in/out.
Monitor the wellbore pressure with MPD choke 4 times 5 minutes each = 37, 20, 12 & 3 psi. Current MW 8.9ppg. EMW = 8.9 ppg. Weight up the surface system to
9.1 ppg. Circulate 9.1 ppg while weighting up the returns on the fly to 9.1 ppg at 6 BPM = 650 psi, 60 RPM = 5-8K ft-lbs TQ reciprocating 90' until good 9.1 ppg
in/out. Shut down and BD TD, Monitor MPD for pressure build 5 minutes each, 22, 8 and final 0 psi, open 2'' valve at the RCD head and monitor the well, 1/4''
stream and going static in 10 minutes. PJSM. Remove the RCD and install the MPD riser. Fill riser and no leaks. POOH laying down 5" DP from 8,905' to 8,715'.
Pump 10.2 ppg dry job. Drop 2.45" drift with wire tail. Continue POOH laying down DP from 8,715' to 7,805'. TOOH standing back 5" DP from 7,805' to 342'. Lost
17.5 bbls while TOOH. LD HWDP, jars, float subs and NMDCs from 342' to 146'. Attempt to download ADR but battery appears to be dead. LD ADR with stabilizers
to 113'. PU to the StrataStar. Unable to download StrataSta. SO to BaseStar. Download BaseStar data. LD BHA from 113' to surface. Bit graded: 2-1-CT-C-X-I-LT-
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 BPH.
6/23/2023 PJSM with all parties involved. PU round nose float shoe on 4 1/2'' crossover joint (H625 box x BTC pin) to 42'. RIH with Cal IV 4-1/2", 13.5#, L-80, Hydril 625, 100-
micron screens from 40' to 8,358'. Torque to 9,600 ft-lbs with Doyon double stack tongs and verify MU mark. Loss rate = 2 BPH. Change handling equipment to 5-
1/2". MU 5-1/2" safety joint and changeout tong heads. MU 5-1/2" EZGO HT box x 4-1/2" H625 pin crossover. RIH with Delta 5-1/2", 20#, L-80, EZGO HT, 100-
micron screens per tally from 8,358' to 11,282'. Torque to EZGO HT to 8,850 ft-lbs & JFE Bear to 7,400 ft-lbs with Doyon double stack tongs. PU = 150K & SO =
94K. Lost 37.5 bbls while running liner. Break down safety joints. Change elevators to 5" DP. RD double stack tongs. RU singe stack tongs to MU the liner hanger.
MU Baker SLZXP liner top packer to 11,317' then RIH with one stand of DP to 11,410'. Pump 5 bbls at 3 BPM = 190 psi to ensure clear flow path through the
packer. Attempt to obtain rotational parameters. Only would rotate slowly at 7.4K ft-lbs TQ limit while moving pipe. Blow down the top drive. TIH with 4-1/2" x 5-1/2"
screen liner on 5" DP from 11,410' to 19,122'. TIH with 4-1/2" x 5-1/2" screen liner on 5" HWDP from 19,122' to tag at 20,052' (TD) with 10K down. PU = 235K &
SO = 65K. Lost 29.5 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 10
bbls at 3 BPM = 470 psi to ensure clear flow path. Drop 1.125" phenolic setting ball. RU 10' pup, FOSV, side entry sub, 10' pup joint & circulating equipment.
6/24/2023 PJSM. PT lines to 4,300 psi - good test. Place liner in tension at 20,052' set depth. Pump ball down with 30 bbl hi-vis sweep at 3 BPM = 480 psi. Ball on seat 112
strokes early at 1,348 strokes. Pressure up to 2,000 psi, observer set at 1,980 psi & hold for 5 minutes. SO to 60K to confirm set. Pressure up & observe release at
2,920 psi. Hold for 5 minutes. Continue to pressure up with rig pump and observe ball seat shear at 3,966 psi. PU & observe travel at 160K to confirm release. Top
of liner at 8,745.66'. Open kill line & purge air. Close the annular & PT the IA/LTP to 1,500 psi for 10 minutes charted - good test. Bleed off the pressure & open the
annular. Blow down & RD circulating equipment. Pump out of the LTP at 2 BPM = 300 psi. Once the liner running tool is out of the LTP bring pumps up to 500
GPM = 1,520 psi and circulate the sweep out of the hole. Sweep back on time with 10% increase. Flow Check well- static. Blow down top drive. Slip and cut 117'
(18 wraps) of drilling line. Check equalizer bar, brake band rollers adjusted, service top drive and weekly derrick inspection. PJSM. Pump dry job. POOH laying
down 5" HWDP from 8,667' to 7,865'. POOH laying down 5" DP from 7,865' to 31'. Lay down the liner running tool. Lost 24 bbls while POOH.
Activity Date Ops Summary
6/24/2023 MU stack washing tool, flush BOP stack and LD stack washing tool. Remove wear bushing. Mobilize & RU Doyon casing equipment. MU crossover on FOSV.
PJSM. Static loss rate = 1 BPH,PU 7" tieback seal assembly and RIH with 7", 26#, L-80, TXP-BTC casing from 18' to 1,967'. Torque to 14,750 ft-lbs with Doyon
double stack tongs.
6/25/2023 RIH with 7", 26#, L-80, TXP-BTC casing from 1,967' to no-go at 8,750' with 5K down. Set down 10K to confirm. Close annular and pressure up to 360 psi to ensure
seals stung into liner top. TQ = 14,750 ft-lbs. PU = 168K & SO =107K. Lost 23 bbls while RIH with 7" casing. LD 3 joints 223, 222,221. MU pup joints 14. 30', 9. 83'
& 7. 81'. MU joint #222. MU 7-5/8" mandrel casing hanger with 7" crossover pup and landing joint. Land the casing hanger 1. 65' off no-go. Change to DP
elevators. MU crossover, side entry sub and 10' DP pup joint. RU cement hose and circulating equipment. Flood lines. PT to 1,000 psi - good test. PU and expose
port. Break circulation confirming returns. Close the annular and reverse circulate confirming returns. PJSM. Reverse circulate 173 bbls of 9. 1 ppg corrosion
inhibited brine at 6 BPM = 1,400 psi (ICP) & 1,280 psi (FCP) followed by 68 bbls diesel at 5 BPM = 900 psi. Strip through the annular, closing the ports and land
the casing hanger with 67K on the hanger (1. 65' off no-go). Bleed off the pressure and drain the BOP stack. Blow down and RD the circulating lines and
equipment. Lay down the landing joint. MU 2 joints of 5" HWDP and pack-off running tool. Install 7-5/8" pack-off and RILDS. PT pack-off void to 500 psi for 5
minutes and 5,000 psi for 10 minutes - good test. LD HWDP and pack-off running tool. Rig up injection line and test equipment. Flood lines. PT 7" x 9-5/8" OA to
1,500 psi for 30 minutes charted - good test. Pumped 2. 6 bbls. Bleed off pressure. RD circulating and test equipment. Mobilize 4-1/2" handling equipment, double
stack, spooling unit with Tec wire, job box, cannon clamps, crossovers, pup joint and tubing hanger. MU crossover to 3-1/2" TIW. Static loss rate = 1 BPH. PJSM.
PU mule shoe joint and RIH on 4-1/2", 12. 6#, L-80, TXP-BTC tubing to 1,432'. Torque to 6,170 ft-lbs with Doyon double stack tongs. MU XN nipple, 1 joint, Baker
Premier Packer, 1 joint, X nipple, 1 joint and gauge carrier. MU Zenith gauge and Tec wire. MU 1 joint and sliding sleeve with covered ports for Tec wire bypass to
1,701',RIH on 4-1/2", 12. 6#, L-80, TXP-BTC tubing from 1,701' to 3,590' spooling TEC wire, installing cannon clamps per tally and checking electrical continuity of
the TEC wire every 1,000'. Torque to 6,170 ft-lbs with Doyon double stack tongs.
6/26/2023 RIH on 4-1/2", 12. 6#, L-80, TXP-BTC tubing from 3,590' to 8,728' spooling TEC wire, installing cannon clamps per tally and checking electrical continuity of the
TEC wire every 1,000'. Torque to 6,170 ft-lbs with Doyon double stack tongs. 11 bbls lost during trip. Change elevator to 5". MU tubing hanger with BPV installed
and 5" DP landing joint with TC-II crossover. Terminate the TEC wire and feed through the tubing hanger. Land tubing on hanger with mule shoe at 8,762. 27' with
32K on hanger. RLIDS. Lay down the landing joint. RD and demobilize completion running equipment. Clear and clean the floor. PJSM. Pull the MPD riser. ND the
BOP stack and rack back on the stump. Install CTS plug into the BPV. Mobilize the tree into the cellar. NU the tubing head adapter and tree. PT the tubing hanger
void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good tests. Obtain final Zenith gauge readings: Tubing = 1,668. 7 psi, 73. 9 deg F & 20. 5 volts. RU, fill
the tree with water and purge the air. PT the tree to 250/5,000 psi - good test. RD testing equipment. Drain the tree through the wing valve. Pull the CTS plug.
Check for pressure under the BPV- the well is on a slight vac. Pull the BPV with dry rod. RU the squeeze manifold to reverse circulate. Fill and PT lines to 4,000 psi -
good test. PJSM. Reverse circulate 163 bbls of 9. 1 ppg of corrosion inhibited brine down the 4-1/2" x 7" IA at 5 BPM = 1,410 psi. Close the master valve, bleed off
the pressure and drain the tree through the wing valve. Set the 1-1/2" ball & rod on top of the master valve. Install the lubricator extension. Open the master valve
dropping the ball & rod allowing it to gravitate to seat. Close the master valve and RD the lubricator extension.
6/27/2023 Pressure up on the tubing to 3,700 psi setting the Premier packer at 2,700 psi. PT the tubing to 3,700 psi for 30 minutes - good test. Bleed the tubing to 2,000 psi.
PT the 4-1/2" x 7" annulus to 3,700 psi for 30 minutes charted - good test. Bleed the IA and tubing to 0 psi. Secure the tree. Blow down and RD the squeeze
manifold and circulating lines. Clean the cellar box. Rig welder cut off the mouse hole extension and seal weld. Blow down and rig down rig floor service lines. Prep
for skidding the rig floor. Rig released at 06:00 hours.
50-029-23753-00-00API #:
Well Name:
Field:
County/State:
MP M-64
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
151
1
1
1
63
1
X Yes No X Yes No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? 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:
Casing (Or Liner) Detail
Shoe
Cut joint
10 3/4
564.2 14.6492.5
SE
C
O
N
D
S
T
A
G
E
Rig
0:05
Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 8941 FC @ Top of Liner8,859.96
Floats Held
532.3 971
367 604
Spud Mud
CASING RECORD
County State Alaska Supv.B. Anderson / J. Vanderpool
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP M-64 Date Run 9-Jun-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TXP Innovex 1.58 8,941.00 8,939.42
21.67 53.96 32.299 5/8 47.0 L-80 TXP
Csg Wt. On Hook:325,000 Type Float Collar:Innovex No. Hrs to Run:33.5
9.4 6
2200
10
10.7 440 4.5
97
660
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
650
3
9.4 6 195/192.3
668/662.1
1250
50
Rig
15.8 82
Bump press
Returns to Surface
Bump Plug?
Y
10:51 6/11/2023 2,622
2622.1
8,941.008,946.00
CEMENTING REPORT
Csg Wt. On Slips:110,000
Spud Mud
Tuned Spacer
870 2.85
Stage Collar @
60
Bump press
100
317
HES ES Cemente Closure OK
56
12 393
RKB to CHF
Type of Shoe:Innovex Round Nose Casing Crew:Doyon
No. Jts. Delivered No. Jts. Run
Length Measurements W/O
Threads
Ftg. Delivered Ftg. Run Ftg. Returned
Ftg. Cut Jt.19.51 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.6
ArcticCem Type I/II
Type
102 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 #146. One each on joints #149 to #154. One each with stop rings on pup joints above and
below ES cementer. One each on joints #155 to #160. One each on every third joint #163 to #214.
Casing 9 5/8 40.0 L-80 TXP Tenaris 79.46 8,939.42 8,859.96
Float Collar 10 3/4 TXP Innovex 1.31 8,859.96 8,858.65
Casing 9 5/8 40.0 L-80 TXP Tenaris 39.11 8,858.65 8,819.54
Baffle Adapter 10 3/4 TXP Halliburton 1.41 8,819.54 8,818.13
Casing 9 5/8 40.0 L-80 TXP Tenaris 6,175.10 8,818.13 2,643.03
Casing Pup Joint 9 5/8 40.0 L-80 TXP 18.08 2,643.03 2,624.95
ES Cementer 10 3/4 TXP Halliburton 2.85 2,624.95 2,622.10
Casing Pup Joint 9 5/8 47.0 L-80 TXP 17.59 2,622.10 2,604.51
Casing 9 5/8 47.0 L-80 TXP Tenaris 2,550.55 2,604.51 53.96
EconoCem Type I/II 1000 2.35
HalCem Type I/II 400 1.16
4.8
HalCem Type I/II 270 1.17
6/12/2023 Surface
Spud Mud
00
97
Returns to Surface
Returns to Surface
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU M-64 Date:6/14/2023
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Anderson / Vanderpool
Csg Setting Depth:8941 TMD 4084 TVD
Mud Weight:9.3 ppg LOT / FIT Press =574 psi
.
LOT / FIT =12.00 Hole Depth =8966 md
Fluid Pumped=1.40 Bbls Volume Back =1.40 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
->147 ->6290
->287 ->12 572
->3 121 ->18 805
->4 150 ->24 1012
->5 192 ->30 1231
->6 218 ->36 1485
->7 255 ->42 1737
->8 303 ->48 1995
->9 335 ->54 2264
->10 393 ->60 2523
->11 437 ->63 2637
->12 477 ->
->14 578 ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 578 ->0 2637
->1 549 ->5 2631
->2 546 ->10 2628
->3 541 ->15 2627
->4 536 ->20 2625
->5 532 ->25 2623
->6 526 ->26 2623
->7 522 ->27 2622
->8 518 ->28 2622
->9 513 ->29 2621
->10 509 ->30 2621
->11 505 ->
->12 501 ->
->13 499 ->
->14 498
->15 497
->16
0
1 2 3 4
5 6 7
8 9
10
1112
14
0
6
12
18
24
30
36
42
48
54
60
63
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 10203040506070
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
578549546541536532526522518513509505501499498497
2637 2631 2628 2627 2625 262326232622262226212621
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
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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: 08/02/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: MPU M-64
PTD: 223-034
API: 50-029-23753-00-00
Updated Definitive Directional Survey (GWD + MWD COMPOSITE - 28-July-2023)
Main Folder Contents:
Please include current contact information if different from above.
Revised Data
PTD: 223-034
T37849
Kayla Junke
Digitally signed by
Kayla Junke
Date: 2023.08.02
16:24:26 -08'00'
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: 07/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU M-64
PTD: 223-034
API: 50-029-23753-00-00
FINAL LWD FORMATION EVALUATION LOGS (06/03/2023 to 06/20/2023)
x EWR-M5, AGR, ABG, BaseStar, StrataStar, 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: 223-034
T37849
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.17
09:14:45 -08'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT M-64
JBR 07/27/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
tested with 4 1/5", 5" and 7" test joints. Test #1 leaking test equipment, tighten up and retest. Test #2 test pump block valves
leaking back to test pump, Change out and retest. Test #3 Lower rams leaking. Test around and C/O at end of testing. Did not
stay on location for retest of lower rams. Operator sent a passing chart of lower rams on 4 1/2" and 5" test joints @ 0730
Test Results
TEST DATA
Rig Rep:JC CharleeOperator:Hilcorp Alaska, LLC Operator Rep:J. Vanderpool
Rig Owner/Rig No.:Doyon 14 PTD#:2230340 DATE:6/13/2023
Type Operation:DRILL Annular:
250/2500Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSTS230612154000
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 10
MASP:
1387
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 2 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8 P
#1 Rams 1 4 1/5 x 7 vari P
#2 Rams 1 blinds P
#3 Rams 1 2 7/8 x 5 vari F
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8 P
HCR Valves 2 3 1/8 P
Kill Line Valves 2 3 1/8 P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P1700
200 PSI Attained P44
Full Pressure Attained P205
Blind Switch Covers:Pall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@1858
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P17
#1 Rams P7
#2 Rams P7
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9999
9
9
9
9
/RZHU9%5UHWHVWFKDUWDWWDFKHG
Lower rams leaking.
F
%23(7HVW'R\RQ
/RZHU9%55HWHVW
0380 37'
,QVS5SWERS676
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty Myers
Drilling Manager
Hilcorp Alaska LLC
3800 Centerpoint Dr, Suite 1400
Anchorage, AK, 99503
Re: Milne Point, Schrader Bluff, MPU M-64
Hilcorp Alaska LLC
Permit to Drill Number: 223-034
Surface Location: 5038' FSL, 471' FEL, Sec. 14, T13N, R09E, UM, AK
Bottomhole Location: 2535' FNL, 87' 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 May, 2023. 26
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.05.26 14:09:18
-08'00'
1a.
Contact Name:Nathan Sperry
Contact Email:nathan.sperry@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8450
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
5
21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated
from without prior written approval.
Drill
Type of Work:
Redrill
Lateral
1b.Proposed Well Class:Exploratory - Gas
5
Service - WAG
5
1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple Zone Exploratory - Oil
Gas Hydrates
Geothermal
Hilcorp Alaska, LLC Bond No. 22224484
11.Well Name and Number:
MPU M-64
TVD:20070'4109'
12. Field/Pool(s):
MD:
ADL 025514, 355023, 388235 & 355018
16-004 May 29, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
5038' FSL, 471' FEL, Sec. 14, T13N, R09E, UM, AK
1893' FNL, 419' FEL, Sec. 12, T13N, R09E, UM, AK
Kickoff Depth:250 feet
Maximum Hole Angle: 96 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:1795 1387
17.Deviated wells:16.
Surface: x-y- Zone -533694 6027890 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
59.1'
25.4'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
1949'
Surface
19.PRESENT WELL CONDITION SUMMARY
Production
Surface
Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements
Shallow Hazard Analysis
55
Commission Use Only
See cover letter for other
requirements:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No
H2S measures Yes No
Spacing exception req'd: Yes No
Mud log req'd: Yes No
Directional svy req'd: Yes No
Inclination-only svy req'd: Yes No
Other:
Date:
Address:
Location of Well (State Base Plane Coordinates - NAD 27):
129.5#
50-029-23753-00-00
Intermediate
Conductor/Structural
Single Zone
Service - Disp
No YesPost initial injection MIT req'd:
No Yes 5
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
2535' FNL, 87' FEL, Sec. 35, T14N, R09E, UM, AK
Time v. Depth Plot555 5Drilling Program
4689'
Stg 2 L - 673 sx / T - 268 sx
(To be completed for Redrill and Re-Entry Operations)
8-1/2"
7"
L-8020#/13.5#
9-5/8"
4069'
12-1/4"
8850'Uncemented Tieback
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stratigraphic Test
Development - Gas Service - Supply
Coalbed Gas
Shale Gas
2.Operator Name:5.Bond Blanket 5 Single Well
3.
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
6. Proposed Depth:
7. Property Designation (Lease Number):
8. DNR Approval Number:13.Approximate spud date:
9.Acres in Property: 14. Distance to Nearest Property:
Location of Well (Governmental Section):
4b.
12818
400'
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
12-1/4"
Tieback
9-5/8" 47#
40#
26#
L-80
L-80
L-80 TXP
TXP
TXP
2500'
6500'
8850'
Surface
2500'
Surface
2500'
9000'
1949'
4082'
Stg 1 L - 953 sx / T - 395 sx
Uncemented Screen Liner
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured):
Casing Length Size MD
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
124'124'~270 ft342"20"X-56 109'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
MILNE POINT FIELD/
SCHRADER BLUFF OIL POOL
5-1/2"x4-1/2"
REVISED - New
Wellplan
223-034 (REVISED)
JFE BEAR/Hyd 625 11220'8850'4069' 22070' 4109'
REVISED - New
Wellplan
5.22.2023
By Grace Christianson at 8:51 am, May 23, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.05.22 16:16:24 -08'00'
Monty M
Myers
MGR24MAY23 DSR-5/24/23
20070
SFD 5/25/2023
1387
* Casing test of 9-5/8" surface casing and FIT digital
data to AOGCC immediately upon completion of
FIT.
* BOPE pressure test to 3000 psi. Annular to 2500 psi.
GCW 05/26/23JLC 5/26/2023
05/26/23
05/26/23
Brett W. Huber, Sr.Digitally signed by Brett W. Huber,
Sr.
Date: 2023.05.26 14:09:33 -08'00'
Milne Point Unit
(MPU) M-64
Application for Permit to Drill
Version 2
5/22/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 5-1/2” x 4-1/2” Screened Liner ........................................................................................ 33
17.0 Run 7” Tieback ........................................................................................................................ 38
18.0 Run Upper Completion – Jet Pump ........................................................................................ 41
19.0 Doyon 14 Diverter Schematic .................................................................................................. 43
20.0 Doyon 14 BOP Schematic ........................................................................................................ 44
21.0 Wellhead Schematic ................................................................................................................. 45
22.0 Days Vs Depth .......................................................................................................................... 46
23.0 Formation Tops & Information............................................................................................... 47
24.0 Anticipated Drilling Hazards .................................................................................................. 49
25.0 Doyon 14 Rig Layout ............................................................................................................... 51
26.0 FIT Procedure .......................................................................................................................... 53
27.0 Doyon 14 Rig Choke Manifold Schematic ............................................................................... 54
28.0 Casing Design ........................................................................................................................... 55
29.0 8-1/2” Hole Section MASP ....................................................................................................... 56
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 58
Page 2
Milne Point Unit
M-64 SB Producer
PTD Application
1.0 Well Summary
Well MPU M-64
Pad Milne Point “M” Pad
Planned Completion Type Jet Pump
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 20,070’ MD / 4,109’ TVD
PBTD, MD / TVD 20,070’ MD / 4,109’ TVD
Surface Location (Governmental) 241’ FNL, 471’ FEL, Sec. 14, T13N, R9E, UM, AK
Surface Location (NAD 27) X= 533694, Y=6027890
Top of Productive Horizon
(Governmental)1893’ FNL, 419’ FEL, Sec. 12, T13N, R9E, UM, AK
TPH Location (NAD 27) X= 539006, Y=6031543
BHL (Governmental) 2535' FNL, 87' FEL, Sec 35, T14N, R9E, UM, AK
BHL (NAD 27) X= 534006, Y=6041437
AFE Drilling Days 22
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1387 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1795 psig
Work String 5” 19.5# S-135 NC 50
Doyon 14 KB Elevation above MSL: 33.7 ft + 25.4 ft = 59.1 ft
GL Elevation above MSL: 25.4 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
M-64 SB Producer
PTD Application
2.0 Management of Change Information
Page 4
Milne Point Unit
M-64 SB Producer
PTD Application
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604
8-1/2”
5-1/2”
Screens 4.780” 4.653” 6.000” 20.0 L-80
EZGO HT 9,190 8,830 466
4-1/2”
Screens 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279
Tubing 4-1/2" 3.958”3.833”4.729”12.6 L-80 TXP 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
M-64 SB Producer
PTD Application
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com,and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer 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
_____________________________________________________________________________________
Edited By: JNL 4/3/2023
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU M-64
Last Completed: TBD
PTD: TBD
TD =20,070’(MD) / TD =4,109’(TVD)
4
20”
Orig. KB Elev.: 59.1’ / GL Elev.: 25.4’
7”
6
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =20,070’(MD) / PBTD =4,109’(TVD)
9-5/8” ‘ES’
Cementer @
2,500’
5
7
9
12
8
4-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 124’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface ~2,500’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 ~2,500’ 9,000’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface ~8,850’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / JFE Bear 4.780 ~8,850’ ~11,500’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 ~11,500’ 20,070’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface ~8,850’ 0.0152
OPEN HOLE / CEMENT DETAIL
42” ±270 ft3
12-1/4"Stg 1 Lead – 953 sx / Tail – 395 sx
Stg 2 Lead – 673 sx / Tail 268 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 10,662’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 ~7,650’ Haliburton X-Line Sliding Sleeve (opens down) 3.813”
3 ~7,600’ Baker Gauge Carrier 3.865”
4 ~7,650’ Baker Retrievable Packer 3.880”
5 ~7,700’ XN Nipple, 3.813”, 3.725” No Go 3.725”
6 ~8,710’ WLEG/Mule Shoe 3.958”
7 ~8,750’ SLZXP Liner Top Packer 6.180”
8 ~8,775’ 7” H563 x 4.5” TSH 625 XO 4.810”
9 ~20,070’ Shoe 3.970”
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Jts Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
Page 7
Milne Point Unit
M-64 SB Producer
PTD Application
7.0 Drilling / Completion Summary
MPU M-64 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. M-64 is part of a
multi-well program targeting the Schrader Bluff sand on M-pad
The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the top of the Schrader Bluff
OA sand. An 8-1/2” lateral section will be drilled and completed with a 4-1/2” liner. The well will be
produced with a jet pump.
Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately May 29th, 2023, pending rig schedule.
Surface casing will be run to 9,000’ MD / 4,082’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run 4-1/2” production liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
Page 8
Milne Point Unit
M-64 SB Producer
PTD Application
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-64. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
x None
Page 9
Milne Point Unit
M-64 SB Producer
PTD Application
Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 10
Milne Point Unit
M-64 SB Producer
PTD Application
9.0 R/U and Preparatory Work
9.1 M-64 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).
Page 11
Milne Point Unit
M-64 SB Producer
PTD Application
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
Page 12
Milne Point Unit
M-64 SB Producer
PTD Application
10.4 Rig & Diverter Orientation:
x May change on location
Page 13
Milne Point Unit
M-64 SB Producer
PTD Application
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x GWD will be the primary gyro tool. Take gyro surveys until MWD cleans up.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled.
x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100-
2,400’ TVD (just below permafrost). Be prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
Page 14
Milne Point Unit
M-64 SB Producer
PTD Application
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Surface Hole AC:
x There are no wells with a clearance factor of <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+ (For Hydrates if need based on offset wells)
MW can be cut once ~500’ below hydrate zone
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: M-I gel 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 UL should be used for filtrate control. Background
LCM (10 ppb total) nut plug fine & medium, M-I-X II fine & medium 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 SCREENKLEEN 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 TANNATHIN / CF DESCO II as required for
running casing as allowed (do not jeopardize hole conditions). Run casing carefully to
minimize surge and swab pressures. Reduce the system rheology once the casing is
landed to a YP < 20 (check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated M-I gel / freshwater spud mud
Page 15
Milne Point Unit
M-64 SB Producer
PTD Application
Properties:
Section Density Viscosity
Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –
9.8
75-175 20 - 40 25-45 <10 8.5 –
9.0
70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
M-I GEL
caustic soda
SCREENKLEEN
MI WATE
PAC-UL /DEXTRID LT
ALDACIDE G
0.967 bbl
0.125 ppb
35 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
Page 16
Milne Point Unit
M-64 SB Producer
PTD Application
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.5” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
Page 17
Milne Point Unit
M-64 SB Producer
PTD Application
12.5 Float equipment and Stage tool equipment drawings:
Page 18
Milne Point Unit
M-64 SB Producer
PTD Application
12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
Page 19
Milne Point Unit
M-64 SB Producer
PTD Application
Page 20
Milne Point Unit
M-64 SB Producer
PTD Application
12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface
x Ensure drifted to 8.525”
Page 21
Milne Point Unit
M-64 SB Producer
PTD Application
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
Page 22
Milne Point Unit
M-64 SB Producer
PTD Application
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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Cement Slurry Design (1st Stage Cement Job):
13.9 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.
13.10 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.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation is in step 13.8 above.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES
cementer is tuned spacer to minimize the risk of flash setting cement
13.13 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.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
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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to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. 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):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.27 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.28 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test 4-1/2” x 7” rams with 4-1/2” and 7” test joints
x Test 2-7/8” x 5” rams with the 4-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 8.9 ppg FLOPRO NT fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
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 9.5ppg MW, 8.46ppg PP (swab kick at 9.5ppg BHP)
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
Email casing test and FIT digital data to AOGCC upon completion. email: melvin.rixse@alaska.gov
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to a minimum. 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
System Formulation:
Product- production ppb or (% liquids)
Water 0.916 bbls/bbl
Soda Ash 0.17 ppb
FLO-VIS PLUS 0.5 –0.75 ppb
FLO-TROL 6.0 ppb
Potassium Chloride (KCl)10.7 ppb
SCREENKLEEN 0.5% v/v
SAFE-CARB 20 10 ppb
SAFE-CARB 40 10 ppb
SALT As needed
Onyxide 200 2.1 gals/100 bbls
Sodium Metabisulfite 0.25 ppb
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15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Include GWD in the BHA
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 surveys every stand, can be taken more frequently if deemed necessary, ex: concretion
deflection
x Monitor torque and drag with pumps on every stand (confirm frequency with co-man)
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OA sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OA Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x F-96 has a clearance factor of 1.017 at 15,575’ MD. F-96 is a subnormally pressured
Kuparuk ESP producer. The 1.0 CF line is a hardline and shall not be crossed.
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.
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x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (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%
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.
15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
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x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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16.0 Run 5-1/2” x 4-1/2” Screened Liner
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them
slick.
16.1 Well control preparedness: In the event of an influx of formation fluids while running the
screened liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 5-1/2” crossover installed on bottom, TIW valve in open
position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 5-1/2” screened liner.
x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” screened liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U liner running equipment.
x Ensure 5-1/2” 20# EZGO-HT x NC50 and 4-1/2” 13.5# Hydril 625 x NC50 crossovers are on
rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run screened production liner
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Fill liner with PST passed mud (to keep from plugging screens with solids)
x Install screen joints as per the Running Order (From Operations Engineer post TD).
o Do not place tongs or slips on screen joints
o Screen placement ±40’
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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5-1/2” 20# L-80 EZGO HT MU Torque
OD Minimum Maximum
5-1/2 6,997 ft-lbs 10,728 ft-lbs
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4-1/2” 13.5# L-80 Hydril 625 Torque
OD Minimum Optimum Maximum
4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure
hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
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16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool) down the
workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to
slam into ball seat.
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, TXP
=Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs
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17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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18.0 Run Upper Completion – Jet Pump
18.1 RU to run 4-1/2”, 12.6#, L-80 TXP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, TXP x XT-39 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RH with the following 4-1/2” JP completion (confirm tally with Operations
Engineer):
x WLEG/Mule shoe
x Joints, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” XN profile (3.750” no-go), 4-1/2”, TXPM (RHC plug body installed,Set
Below 70 degrees)
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover Pup, 4-1/2” TC-II Box x 4-1/2” TXP Pin
x Retrievable Packer, Baker, 4-1/2”, 12.6#, L-80, TC-II (NOTE: Set Below 70 degrees)
x Crossover Pup, 4-1/2”, TXP Box x 4-1/2”, TC-II Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” X profile 4-1/2”, TXPM
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin
x Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x Sliding Sleeve, 4-1/2”, 12.6#, L-80 TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x XXX joints, 4-1/2”, 12.6#, L-80, TXP
Page 42
Milne Point Unit
M-64 SB Producer
PTD Application
18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unused
control line ports are dummied off.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect
to 2,500’ MD.
18.11 Drop the ball & rod.
18.12 Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30
minutes.
18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,650 psi for 30 minutes (charted). Bleed
both the IA and tubing to 0 psi.
18.14 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.15 RDMO
Page 43
Milne Point Unit
M-64 SB Producer
PTD Application
19.0 Doyon 14 Diverter Schematic
Page 44
Milne Point Unit
M-64 SB Producer
PTD Application
20.0 Doyon 14 BOP Schematic
Page 45
Milne Point Unit
M-64 SB Producer
PTD Application
21.0 Wellhead Schematic
Page 46
Milne Point Unit
M-64 SB Producer
PTD Application
22.0 Days Vs Depth
Page 47
Milne Point Unit
M-64 SB Producer
PTD Application
23.0 Formation Tops & Information
TOP
NAME
TVDSS
(FT)
TVD
(FT)
MD
(FT)
Formation
Pressure
(psi)
EMW
(ppg)
Base
Permafrost 1834 1893 2343 833 8.46
SV1 1879 1938 2469 853 8.46
UG4 2106 2165 3108 952 8.46
UG_MB 3538 3597 7115 1582 8.46
SB NB 3863 3922 8071 1725 8.46
SB OA 4021 4080 8978 1795 8.46
Page 48
Milne Point Unit
M-64 SB Producer
PTD Application
L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad)
Page 49
Milne Point Unit
M-64 SB Producer
PTD Application
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hydrates are generally not seen on M-pad. Remember that hydrate gas behaves differently from a
gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the
breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill
through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation
time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing
which can increase the amount of hydrates released into the wellbore. Keep the mud circulation
temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale.
The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to
remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
Page 50
Milne Point Unit
M-64 SB Producer
PTD Application
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.
Page 51
Milne Point Unit
M-64 SB Producer
PTD Application
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maint. circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There are three (possibly four) planned fault crossings for M-64. The maximum expected throw for a
fault is 50’ on the fault crossed mid-lateral.
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. 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 F-96 has a clearance factor of 1.017 at 15,575’ MD. F-96 is a subnormally pressured Kuparuk
ESP producer. The 1.0 CF line is a hardline and shall not be crossed.
Page 52
Milne Point Unit
M-64 SB Producer
PTD Application
25.0 Doyon 14 Rig Layout
Page 53
Milne Point Unit
M-64 SB Producer
PTD Application
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 54Milne Point UnitM-64 SB ProducerPTD Application27.0 Doyon 14 Rig Choke Manifold Schematic
Page 55
Milne Point Unit
M-64 SB Producer
PTD Application
28.0 Casing Design
Page 56
Milne Point Unit
M-64 SB Producer
PTD Application
29.0 8-1/2” Hole Section MASP
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L-03
L-15
F-25
F-13F-01
F-05
F-09
L-33
L-40
L-28
L-28A
F-80
F-84
F-84A
F-84B
F-81
F-83
F-82
F-82A
F-86
F-87
F-87A
F-91
F-99
F-96
L-08
L-13
F-46
F-14
F-06
F-02
F-58
F-84APB1
F-82PB1
F-99PB1
M-04 M-12PB1M-06
F-05L1
F-05L1-01
F-05L1PB1
KUPARUK
RIVER UNIT
MILNE
POINT UNIT
ADL025515
ADL025514
ADL025509
ADL388235
ADL355023
ADL355018
Sec. 35
Sec. 1
Sec. 36
Sec. 11
Sec. 13
Sec. 2
Sec. 14
Sec. 12
Sec. 6
(625)
Sec. 31
(622)
Sec. 7
(628)
Sec. 18
(630)
U013N009E U013N010E
U014N010E
U014N009E
MPU F
MPU
MOOSE PAD
MPU M-64_SHL
MPU
M-64_TPH
MPU M-64_BHL
Map Date: 5/22/2023
Milne Point Unit
MPU M-64 Well
wp09
E0 1,000 2,000
Feet
Legend
$)MPU M-64_BHL
!MPU M-64_SHL
D MPU M-64_TPH
!Other Surface Holes (SHL)
$)Other Bottom Holes (BHL)
Other Well Paths
Coastline (USGS 1:63k)
Oil and Gas Unit Boundary
Pad Footprint
Document Path: O:\AWS\GIS\Products\Alaska\NS\Wells\TRS_Distance\mxds\2023\NorthSlope_MPM_64_wp09.mxdAlaska State Plane Zone 4 NAD 1927
Page 58
Milne Point Unit
M-64 SB Producer
PTD Application
31.0 Surface Plat (As Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
0D\
3ODQ 0380ZS
+LOFRUS$ODVND//&
0LOQH3RLQW
03W0RRVH3DG
3ODQ 0380
0380
07501500225030003750True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 333.00° (1500 usft/in)MPU M-64 wp05 tgt01 Oa1MPU M-64 wp05 tgt02 Oa1MPU M-64 wp05 tgt03 Oa1MPU M-64 wp05 tgt04 Oa3MPU M-64 wp05 tgt05 Oa3MPU M-64 wp05 tgt06 Oa1MPU M-64 wp05 tgt07 Oa1MPU M-64 wp05 tgt08 Oa3MPU M-64 wp05 tgt10 Oa1MPU M-64 wp05 tgt13 Oa3MPU M-64 wp05 tgt14 Oa1MPU M-64 wp05 tgt15 Oa1MPU M-64 wp05 tgt16 Oa3MPU M-64 wp05 tgt17 Oa3MPU M-64 wp05 tgt18 Oa1MPU M-64 wp05 tgt19 Oa1MPU M-64 wp05 tgt20 Oa3MPU M-64 wp05 tgt21 Oa3MPU M-64 wp08 tgt 8aMPU M-64 wp08 tgt 12aMPU M-64 wp08 tgt 10a9 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008000850090009500100001050011000
11500120001250013000135001400014500150001550016000165001700017500180001850019000195002000020070MPU M-64 wp09Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 3.47º/100' : 850' MD, 840.18'TVDStart Dir 4.1º/100' : 1600' MD, 1477.55'TVDEnd Dir : 2374.28' MD, 1904.51' TVDStart Dir 4.2º/100' : 6568.31' MD, 3394.05'TVDEnd Dir : 8866.52' MD, 4070.38' TVDStart Dir 2.5º/100' : 8966.52' MD, 4079.1'TVDBegin GeosteeringEnd Dir : 9110.58' MD, 4087.14' TVDTotal Depth : 20070.03' MD, 4109.1' 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-6425.40+N/-S+E/-WNorthingEastingLatitudeLongitude0.000.006027889.58533693.7570° 29' 14.0079 N149° 43' 28.5790 WSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1500.00 MPU M-64 wp09 (MPU M-64) GYD_Quest GWD1500.00 9000.00 MPU M-64 wp09 (MPU M-64) 3_MWD+IFR2+MS+Sag9000.00 20070.03 MPU M-64 wp09 (MPU M-64) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation840.10 781.00 849.92 SV61893.10 1834.00 2342.93 Base Permafrost1938.10 1879.00 2468.85 SV12165.10 2106.00 3108.01 UG43597.10 3538.00 7115.47 UG_MB3922.10 3863.00 8071.09 SB_NB4080.10 4021.00 8978.34 SB_OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-64, True NorthVertical (TVD) Reference:MPU M-64 as built rkb @ 59.10usftMeasured Depth Reference:MPU M-64 as built rkb @ 59.10usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Moose PadWell:Plan: MPU M-64Wellbore:MPU M-64Design:MPU M-64 wp09CASING DETAILSTVD TVDSS MD SizeName4081.77 4022.67 9000.00 9-5/8 9 5/8" x 12 1/4"4109.10 4050.00 20070.03 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 850.00 18.00 49.40 840.18 60.83 70.97 3.00 49.40 21.98 Start Dir 3.47º/100' : 850' MD, 840.18'TVD4 1600.00 44.00 49.40 1477.55 310.06 361.75 3.47 0.00 112.03 Start Dir 4.1º/100' : 1600' MD, 1477.55'TVD5 2374.28 69.20 73.03 1904.51 598.10 926.62 4.10 45.41 112.23 End Dir : 2374.28' MD, 1904.51' TVD6 6568.31 69.20 73.03 3394.05 1742.30 4676.55 0.00 0.00 -570.71 Start Dir 4.2º/100' : 6568.31' MD, 3394.05'TVD7 8866.52 85.00 334.10 4070.38 3529.74 5378.36 4.20 -97.89 703.30 End Dir : 8866.52' MD, 4070.38' TVD8 8966.52 85.00 334.10 4079.10 3619.36 5334.85 0.00 0.00 802.90 MPU M-64 wp05 tgt01 Oa1 Start Dir 2.5º/100' : 8966.52' MD, 4079.1'TVD9 9110.58 88.60 334.28 4087.14 3748.82 5272.24 2.50 2.91 946.68 End Dir : 9110.58' MD, 4087.14' TVD10 9372.34 88.60 334.28 4093.55 3984.59 5158.68 0.00 0.00 1208.3011 9414.43 89.30 333.50 4094.33 4022.37 5140.17 2.50 -48.07 1250.3712 10214.43 89.30 333.50 4104.10 4738.27 4783.24 0.00 0.00 2050.28 MPU M-64 wp05 tgt03 Oa113 10357.48 85.73 333.40 4110.31 4866.10 4719.36 2.50 -178.35 2193.1814 10483.46 85.73 333.40 4119.70 4978.42 4663.10 0.00 0.00 2318.8015 10662.63 90.20 333.20 4126.07 5138.35 4582.67 2.50 -2.52 2497.8116 11512.63 90.20 333.20 4123.10 5897.04 4199.42 0.00 0.00 3347.80 MPU M-64 wp05 tgt05 Oa317 11652.70 93.69 333.52 4118.35 6022.14 4136.66 2.50 5.24 3487.7618 11781.14 93.69 333.52 4110.09 6136.87 4079.51 0.00 0.00 3615.9319 11920.70 90.20 333.40 4105.36 6261.64 4017.20 2.50 -178.03 3755.3920 13140.70 90.20 333.40 4101.10 7352.50 3470.94 0.00 0.00 4975.35 MPU M-64 wp05 tgt07 Oa121 13233.89 87.64 333.22 4102.85 7435.73 3429.09 2.75 -176.01 5068.5122 13559.59 87.64 333.22 4116.24 7726.26 3282.48 0.00 0.00 5393.9323 13649.82 90.00 334.00 4118.10 7807.07 3242.38 2.75 18.28 5484.1424 13899.82 90.00 334.00 4118.10 8031.77 3132.79 0.00 0.00 5734.10 MPU M-64 wp08 tgt 8a25 14112.74 95.57 335.98 4107.75 8224.40 3042.92 2.78 19.55 5946.5426 14147.12 95.57 335.98 4104.42 8255.66 3028.99 0.00 0.00 5980.7127 14346.52 90.40 334.00 4094.03 8436.05 2944.84 2.78 -158.97 6179.6528 14766.52 90.40 334.00 4091.10 8813.53 2760.73 0.00 0.00 6599.57 MPU M-64 wp05 tgt10 Oa129 14895.88 87.81 336.44 4093.12 8930.95 2706.53 2.75 136.63 6728.8030 14952.02 87.81 336.44 4095.26 8982.372684.11 0.00 0.00 6784.7931 15106.44 90.30 333.00 4097.80 9121.95 2618.19 2.75 -54.22 6939.0832 15456.44 90.30 333.00 4095.97 9433.80 2459.30 0.00 0.00 7289.08 MPU M-64 wp08 tgt 10a33 15581.38 90.51 329.88 4095.08 9543.53 2399.58 2.50 -86.13 7413.9634 15817.34 90.51 329.88 4092.98 9747.62 2281.19 0.00 0.00 7649.5635 15970.63 88.28 333.00 4094.60 9882.23 2207.92 2.50 125.60 7802.7536 16120.63 88.28 333.00 4099.10 10015.82 2139.86 0.00 0.00 7952.68 MPU M-64 wp05 tgt13 Oa337 16323.07 93.09 334.57 4096.68 10197.37 2050.47 2.50 18.10 8155.0338 16388.08 93.09 334.57 4093.17 10256.00 2022.59 0.00 0.00 8219.9239 16533.96 89.80 333.00 4089.49 10386.81 1958.19 2.50 -154.44 8365.7240 16993.96 89.80 333.00 4091.10 10796.67 1749.35 0.00 0.00 8825.72 MPU M-64 wp05 tgt15 Oa141 17116.59 86.76 333.39 4094.78 10906.06 1694.09 2.50 172.69 8948.2742 17306.69 86.76 333.39 4105.53 11075.75 1609.07 0.00 0.00 9138.0643 17428.39 89.80 333.50 4109.18 11184.55 1554.70 2.50 2.07 9259.6944 17978.39 89.80 333.50 4111.10 11676.76 1309.29 0.00 0.00 9809.67 MPU M-64 wp05 tgt17 Oa345 18081.34 92.34 333.10 4109.18 11768.71 1263.04 2.50 -9.04 9912.5946 18255.06 92.34 333.10 4102.08 11923.50 1184.49 0.00 0.00 10086.1747 18361.97 89.70 333.50 4100.17 12018.98 1136.47 2.50 171.29 10193.0448 19111.97 89.70 333.50 4104.10 12690.17 801.83 0.00 0.00 10943.00 MPU M-64 wp05 tgt19 Oa149 19130.12 89.26 333.38 4104.26 12706.41 793.71 2.50 -165.28 10961.1550 19490.12 89.26 333.38 4108.91 13028.23 632.44 0.00 0.00 11321.1251 19520.03 90.00 333.50 4109.10 13054.99 619.07 2.50 8.87 11351.0352 20070.03 90.00 333.50 4109.10 13547.20 373.66 0.00 0.00 11901.01 MPU M-64 wp05 tgt21 Oa3 Total Depth : 20070.03' MD, 4109.1' TVD
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
12750
13500
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-64 wp08 tgt 10a
MPU M-64 wp08 tgt 12a
MPU M-64 wp08 tgt 8a
MPU M-64 wp05 tgt21 Oa3
MPU M-64 wp05 tgt20 Oa3
MPU M-64 wp05 tgt19 Oa1
MPU M-64 wp05 tgt18 Oa1
MPU M-64 wp05 tgt17 Oa3
MPU M-64 wp05 tgt16 Oa3
MPU M-64 wp05 tgt15 Oa1
MPU M-64 wp05 tgt14 Oa1
MPU M-64 wp05 tgt13 Oa3
MPU M-64 wp05 tgt10 Oa1
MPU M-64 wp05 tgt08 Oa3
MPU M-64 wp05 tgt07 Oa1
MPU M-64 wp05 tgt06 Oa1
MPU M-64 wp05 tgt05 Oa3
MPU M-64 wp05 tgt04 Oa3
MPU M-64 wp05 tgt03 Oa1
MPU M-64 wp05 tgt02 Oa1
MPU M-64 wp05 tgt01 Oa1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
1
0
0
0
1
5
0
01750 20002250250027503000325035003750
4 0 0 0
4 1 0 9MPU M -6 4 w p 0 9
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 3.47º/100' : 850' MD, 840.18'TVD
Start Dir 4.1º/100' : 1600' MD, 1477.55'TVD
Start Dir 4.2º/100' : 6568.31' MD, 3394.05'TVD
End Dir : 8866.52' MD, 4070.38' TVD
Start Dir 2.5º/100' : 8966.52' MD, 4079.1'TVD
Begin Geosteering
End Dir : 9110.58' MD, 4087.14' TVD
Total Depth : 20070.03' MD, 4109.1' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4081.77 4022.67 9000.00 9-5/8 9 5/8" x 12 1/4"
4109.10 4050.00 20070.03 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt Moose Pad
Well: Plan: MPU M-64
Wellbore: MPU M-64
Plan: MPU M-64 wp09
WELL DETAILS: Plan: MPU M-64
25.40
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6027889.58 533693.75
70° 29' 14.0079 N 149° 43' 28.5790 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU M-64, True North
Vertical (TVD) Reference: MPU M-64 as built rkb @ 59.10usft
Measured Depth Reference:MPU M-64 as built rkb @ 59.10usft
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)MPF-81MPU F-110MPU M-20MPU M-21iMPU M-43MPU M-44iMPU M-45MPU M-62Kup N1 from Slot 34MPU M-63No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU M-64 NAD 1927 (NADCON CONUS)Alaska Zone 0425.40+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027889.58533693.7570° 29' 14.0079 N149° 43' 28.5790 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-64, True NorthVertical (TVD) Reference:MPU M-64 as built rkb @ 59.10usftMeasured Depth Reference:MPU M-64 as built rkb @ 59.10usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU M-64 wp09 (MPU M-64) GYD_Quest GWD1500.00 9000.00 MPU M-64 wp09 (MPU M-64) 3_MWD+IFR2+MS+Sag9000.00 20070.03 MPU M-64 wp09 (MPU M-64) 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-20MPU M-22MPU M-23MPU M-44iMPU M-45MPU M-62MPU M-48 wp01MPU M-49 wp02Kup N1 from Slot 34NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 20070.03Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-64Wellbore: MPU M-64Plan: MPU M-64 wp09Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4081.77 4022.67 9000.00 9-5/8 9 5/8" x 12 1/4"4109.10 4050.00 20070.03 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250 21000 21750 22500 23250Measured Depth (1500 usft/in)MPF-96MPF-80MPF-81MPU M-62MPU M-63MPU M-63 wp10No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU M-64 NAD 1927 (NADCON CONUS)Alaska Zone 0425.40+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027889.58533693.7570° 29' 14.0079 N149° 43' 28.5790 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-64, True NorthVertical (TVD) Reference:MPU M-64 as built rkb @ 59.10usftMeasured Depth Reference:MPU M-64 as built rkb @ 59.10usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU M-64 wp09 (MPU M-64) GYD_Quest GWD1500.00 9000.00 MPU M-64 wp09 (MPU M-64) 3_MWD+IFR2+MS+Sag9000.00 20070.03 MPU M-64 wp09 (MPU M-64) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250 21000 21750 22500 23250Measured Depth (1500 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 20070.03Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-64Wellbore: MPU M-64Plan: MPU M-64 wp09Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4081.77 4022.67 9000.00 9-5/8 9 5/8" x 12 1/4"4109.10 4050.00 20070.03 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.
223-034
MILNE POINT
MPU M-64
SCHRADER BLFF OIL
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT M-64Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230340MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes Surface Location lies within ADL0025514; Top Productive Interval lies in ADL0388325;2 Lease number appropriateYes Portion of Well Passes Thru ADL0355023; TD lies in ADL0355018.3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - governed by CO 477, 477.0054 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-56 set and cemented to 124'18 Conductor string providedYes 9-5/8" L-80 set from surface to reservoir19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes Surface casing fully cemented from surface to the reservoir22 CMT will cover all known productive horizonsYes 9-5/8" L-80 47# from surface to BOPF, 40# 9-5/8 L-80 from BOPF to the reservoir23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan passes all offset wells.26 Adequate wellbore separation proposedYes Doyon 14 has 16" diverter27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 13-5/8" 1 annular, 3 ram, 1 flow cross29 BOPEs, do they meet regulationYes 5000 psi 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 No H2S events on MPU M pad33 Is presence of H2S gas probableNA This well is a producer.34 Mechanical condition of wells within AOR verified (For service well only)Yes Measures not required: H2S: low risk; rig has sensors and alarms; see p. 53.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected reservoir pressure is normal at 8.46 ppg EMW; MPD will be used with 8.4 ppg mud36 Data presented on potential overpressure zonesNA to mitigate any abnormal pressure encountered and to maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/7/2023ApprMGRDate5/7/2023ApprSFDDate5/7/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 05/26/23JLC 5/26/2023
