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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, October 17, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Guy Cook
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
M-61
MILNE PT UNIT M-61
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 10/17/2023
M-61
50-029-23756-00-00
223-042-0
W
SPT
3906
2230420 2000
13 13 13 13
INITAL P
Guy Cook
9/19/2023
Initial MIT-IA test per PTD 223-042 to 2000 psi. Testing completed with a Little Red Services pump truck and calibrated gauges. Monobore
well.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT M-61
Inspection Date:
Tubing
OA
Packer Depth
67 2198 2103 2069IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitGDC230919142439
BBL Pumped:3.3 BBL Returned:3.3
Tuesday, October 17, 2023 Page 1 of 1
By Grace Christianson at 12:40 pm, Sep 22, 2023
N
Completed
8/12/2023
JSB
RBDMS JSB 101023
GDSR-10/10/23
Drilling Manager
09/18/23
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.09.18 15:15:13 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Revised By: JNL 8/14/2023
SCHEMATIC
Milne Point Unit
Well: MPU M-61
Last Completed: 8/12/2023
PTD: 223-042
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,253’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,253’ 5,490’ 0.0758
4-1/2” Liner solid/slotted 13.5 / L-80 / Hyd 625 3.920” 5,287’ 14,315’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surface 5,304’ 0.0087
OPEN HOLE / CEMENT DETAIL
42” ~270 ft3
12-1/4"Stg 1 –Lead 430 sx / Tail 400 sx
Stg 2 –Lead 562 sx / Tail 270 sx
8-1/2” Cementless Slotted Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API#: 50-029-23756-00-00
Completion Date: 8/12/2023
WELL INCLINATION DETAIL
KOP @ 332’
90° Hole Angle = @ 6,046’ MD / Max Angle =96°
TD =14,315’(MD) / TD =3,933’(TVD)
20”
Orig. KB Elev.: 58.1’ / GL Elev.: 24.1’
3-1/2”
6
2
9-5/8”
1
3
See
Slotted
Liner
Detail
7
PBTD =14,313’(MD) / PBTD = 3,933’(TVD)
9-5/8” ‘ES’
Cementer @
2,271’
4-1/2”
4/5
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 4,539’ Viking Sliding Sleeve 2.813” X profile, covered ports (opens down) 2.813”
2 4,957’ Baker Zenith Gauge Carrier 2.992”
3 4,656’ XN Nipple, 2.813”, 2.75” No-Go 2.750”
4 5,294’ 8.25” No Go Locater Sub (1.08’ off No-go) 6.210”
5 5,295’ Bullet Seals – TXP Top Box x Mule Shoe 6.210”
Lower Completion
6 5,287’ SLZXP Liner Top Packer w/ DG Slips 3.920”
7 14,313’ Shoe
PERFORATION DETAIL
Top (MD) Btm (MD) Top (TVD) Btm (TVD)
5,519’ 14,273’ 3,918’ 3,931’
0
1 2 3
4
5
6
7
8
9
10
11
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4
8
12
16
20
24
28
32
36
40
42
44
46
0
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600
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1000
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1300
1400
1500
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1700
1800
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3000
01020304050
Pr
e
s
s
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s
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Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
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(
p
s
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)
650
592565552542535530526522521519518516506504503503
2689 2678 2670 2664 2658 265426532652265126512650
0
100
200
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500
600
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1300
1400
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0 5 10 15 20 25 30 35
Pr
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(p
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Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
7/21/2023 Set mats around M-61 and for rig footprint. Build dance floor. Spot the rig over the well. Skid the rig floor into drilling position. RU and work on rig acceptance
checklist. Stage wellhead equipment, tree, surface annular with riser, knife valve and diverter tee. PJSM. Spot the rig and center over well M-61. Shim and level
the rig. PJSM. Skid the rig floor into drilling position. Work on rig acceptance checklist. RU service lines to the rig floor. Spot auxiliary shacks and pump house.
NU knife valve. NU surface annular with riser. Install first 3 joints of diverter line. Spot the slop tank, fuel trailer and rock washer. Continue RU diverter line. Load
HWDP and BHA on DS pipe shed. Install riser. Spot water uprights and cement silos.
7/22/2023 Finish RU diverter line. PU 5" HWDP and rack back 6 stands one with the jars. Inspect top drive save sub - good. Perform the diverter function test with 5"
HWDP. The test was witness waived by AOGCC inspector Guy Cook via email on 7/22/23 at 07:31 hours. Knife valve opened in 17 seconds and the annular
closed in 32 seconds. Test, gas alarms, PVT and flow sensors - good. Accumulator Test: System pressure = 2,950 psi. Pressure after closure = 1,850 psi. 200
psi attained in 35 seconds. Full pressure attained in 147 seconds. Nitrogen Bottles - 6 at 2,029 psi (average). Diverter length = 395'. Nearest ignition source =
100' (wellhouse). Finish welding in the mud pits. SimOps: Load 5" DP on ODS pipe shed. Perform Pre-Spud derrick inspection. Steam ice plug in 90' mouse
hole. SimOps: Fill pit 4 with water for drilling out. Continue rig acceptance check list. PJSM. MU conductor cleanout BHA #1. RIH and tag at 109'. Fluid pack
surface lines and flood conductor. Check for leaks - good. PT surface lines to 3,800 psi - good test. Bring spud mud on to the pits. Clean out conductor from 109'
to 114'. Spud well and drill 12-1/4" surface hole from 114' to 219'. 356 GPM = 640 PSI, 40 RPM = 1k ft-lbs TQ, WOB 8-10K. PU = 51K, SO = 52K, & ROT = 51K.
MW = 8.8 ppg, Vis = 209. POOH and lay down 12-1/4"VMD-3 tricone bit. Bit grade: 1-1-WT-A-E-I-NO-BHA. 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 211', shallow test
BHA and obtain first Gyro survey at 173'. Drill 12-1/4" surface hole from 219' to 370' (370' TVD). Drilled 151' = 75.5'/hr AROP. 400 GPM = 840 psi, 40 RPM = 2K
ft-lbs TQ, WOB = 10-12K. PU = 61K, SO = 63K & ROT = 62K. MW = 9.0 ppg, Vis = 300+, ECD = 9.6 ppg. Start 3 deg/100' build at 280'. Drill 12-1/4" surface
hole from 370' to 933' (919' TVD). Drilled 563' = 93.8'/hr AROP. 452 GPM = 1,150 psi, 40 RPM = 2K ft-lbs TQ, WOB = 10K. PU = 85K, SO = 86K & ROT = 84K.
MW = 9.2 ppg, Vis = 191, ECD = 9.6 ppg. Start 3.5 deg/100' build at 700'. Last survey at 704.51 MD / 701.17 TVD, 12.83 deg INC, 140.88 deg AZM. Distance
from WP09 = 3.55 (3.52 high & 0.47 left).
7/23/2023 Drill 12-1/4" surface hole from 933' to 1,598' (1,469' TVD). Drilled 665' = 110.8'/hr AROP. 456 GPM = 1,240 psi, 60 RPM = 5-6K ft-lbs TQ, WOB = 8K. PU =
98K, SO = 85K & ROT = 91K. MW = 9.1 ppg, Vis = 121, ECD = 10.4 ppg, max gas = 57 units. Begin tangent section at 1,560' holding 40.15 deg. Drill 12-1/4"
surface hole from 1,598' to 2,450' (2,130' TVD). Drilled 852' = 142'/hr AROP. 500 GPM = 1,460 psi, 80 RPM = 6-7K ft-lbs TQ, WOB = 9K. PU = 114K, SO = 91K
& ROT = 102K. MW = 9.4 ppg, Vis = 116, ECD = 10.43 ppg, max gas = 156 units. Rig on Highline power at 15:00 hours. Logged base of the permafrost at 2,120'
(1,878' TVD). Drill 12-1/4" surface hole from 2,450' to 3,121' (2,672' TVD). Drilled 671' = 111.8'/hr AROP. 500 GPM = 1,480 psi, 80 RPM = 5-7K ft-lbs TQ, WOB
= 4-6K. PU = 130K, SO = 101K & ROT = 115K. MW = 9.1+ ppg, Vis = 70, ECD = 9.99 ppg, max gas = 64 units. Pump 30 bbl hi-vis sweep at 2,550', back on
time with 0% increase. Begin 4.5 deg/100' drop and turn at 2,647'. Drill 12-1/4" surface hole from 3,121' to 3,694' (3,162' TVD). Drilled 573' = 95.5'/hr AROP. 507
GPM = 1,700 psi, 80 RPM = 9-11K ft-lbs TQ, WOB = 8K. PU = 152K, SO = 107K & ROT = 126K. MW = 9.1 ppg, Vis = 72, ECD = 9.2 ppg, max gas = 107 units.
Begin 4.5 deg/100' build and turn at 3,411'. Pump 30 bbl hi-vis sweep at 3,501', back on time with 60% increase. Distance from WP09 at survey depth of
3,463.23' = 23.11' (15.10' high & 17.49' right).
7/24/2023 Drill 12-1/4" surface hole from 3,694' to 4,191' (3,516' TVD). Drilled 497' = 90.4'/hr AROP. 498 GPM = 1,680 psi, 80 RPM = 11K ft-lbs TQ, WOB = 11K. PU =
160K, SO = 110K & ROT = 132K. MW = 9.2 ppg, Vis = 72, ECD = 9.2 ppg, max gas = 347 units. Distance from WP09 at survey depth of 4,128.98 = 9.05 (3.13
high & 8.49 right). Perform rig service while trouble shooting top drive. Top drive indicates fault code 25 - unable to rotate. Trouble shooting and repair top drive
while reciprocating 30' at 289 GPM = 680 psi. Loss rate = 2 BPH. Break out and lay down a single joint of DP. Trouble shooting and repair top drive while
reciprocating 60' alternating stopping points at 126 GPM = 270 psi. Loss rate = 2 BPH. Break out and lay down a single joint of DP. Trouble shooting and repair
top drive while reciprocating 90' alternating stopping points at 130 GPM = 280 psi. Loss rate = 2 BPH.
7/25/2023 Trouble shooting and repair top drive while reciprocating 60' alternating stopping points at 130 GPM = 270 psi. Loss rate = 2-5 BPH. Parked at 4162' disconnect
an inspect TD cables and meg TD motors, while circulating 130 GPM = 275 psi. Trouble shooting and repair top drive while reciprocating 60' alternating stopping
points at 126 GPM = 270 psi. Loss rate = 2-4 BPH. Break out and lay down a single joint of DP. Trouble shooting and repair top drive while reciprocating 60'
alternating stopping points at 126 GPM = 270 psi. Got the top drive operational after replacing multiple cards. Test run - good. Secure the VFD house. MU joints
that were laid down while troubleshooting. Wash and ream back to bottom at 4,191'. Drill 12-1/4" surface hole from 4,191' to 4,453' (3,672' TVD). Drilled 262' =
74.9'/hr AROP. 500 GPM = 1,820 psi, 80 RPM = 12-13K ft-lbs TQ, WOB = 17K. PU = 165K, SO = 103K & ROT = 129K. MW = 9.2 ppg, Vis = 7, ECD = 9.87
ppg, max gas = 81 units. Drill 12-1/4" surface hole from 4,453' to 5,027' (3,887' TVD). Drilled 574' = 95.7'/hr AROP. 553 GPM = 2,190 psi, 80 RPM = 13K ft-lbs
TQ, WOB = 15-20K. PU = 165K, SO = 98K & ROT = 125K. MW = 9.4 ppg, Vis = 74, ECD = 10.2 ppg, max gas = 355 units. Distance from WP09 at survey depth
of 4,796.08 = 19.36 (2.79 high & 19.16 right).
7/26/2023 Drill 12-1/4" surface hole from 5027' to TD at 5,491' (3,616' TVD). Drilled 464' = 71.4'/hr AROP. 550 GPM = 2,170 psi, 80 RPM = 12-13K ft-lbs TQ, WOB = 5-
15K. PU = 158K, SO = 92K & ROT = 118K. MW = 9.3+ ppg, Vis = 60, ECD = 10.3 ppg, max gas = 32 units. Geo called TD at 5,491', 2' TVD below top of
Schrader Bluff OA-sands. Obtain final MWD survey on bottom. Distance from WP09 at survey depth of 5,491' = 23.62' (7.6' high & 22.37' left). Pump 30 bbl hi-
vis sweep and circulate the hole clean at 550 GPM = 2,000 psi, 60 RPM = 11-13K ft-lbs TQ while reciprocating 90' alternating stopping point. Did not see sweep
at surface due to 300+ vis coming out prior to pumping the sweep. Continue to circulate and condition at 550 GPM = 2,000 psi, 60 RPM = 11-13K ft-lbs TQ.
Circulate 2 bottoms up. Rack back a stand with each BU. MW in/out = 9.2+/9.3+ ppg, Vis in/out = 57/152. TIH to TD. BROOH from 5,491' to 4,455' pulling 5-10
minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,890 psi, 60 RPM = 12-14K ft-bs TQ, ECD= 10.03 ppg, max gas = 59 units. PU =
169K, SO = 102K, ROT = 133K. BROOH from 4,455' to 2,362' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,520
psi, 60 RPM = 5-9K ft-bs TQ, ECD= 9.91 ppg, max gas = 27 units. PU = 119K, SO = 89K, ROT = 102K. BROOH from 2,362' to 746' pulling 5-10 minutes/stand
slowing as needed to clean up slides/tight spots. Circulate 2 BU on last stand of DP. 550 GPM = 1,420 psi, 60 RPM = 8K ft-bs TQ, ECD= 9.76 ppg, max gas =
183 units. PU = 103K, SO = 85K, ROT = 100K. Lost 117 bbls while BROOH. Monitor the well for flow - static. TOOH standing back HWDP and jars from 746' to
190'. POOH laying down 3 NMFC's from 190' to 97'. Plug in and download MWD data. Lay down remaining BHA from 97' to surface. 12-1/4" Kymera Dull Bit
Grade: PDC = 2-1-CT-S-X-I-WT-TD & Cones = 2-1-WT-A-F-I-LT-TD.
7/22/2023Spud Date:
Well Name:
Field:
County/State:
MP M-61
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23756-00-00API #:
7/27/2023 Clean and clear rig floor. Monitor well with trip tank and hole fill. Mobilize and RU 9-5/8" casing running equipment: Volant CRT, 350-ton spiders, tongs, bail
extensions and elevators. PJSM with rig crew and DDI Casing. PU 9-5/8", 40#, L80 shoe track and Baker-lok to blank joint. Attempt to MU to diamond - torqued
up. Unable to back out with tongs. RU larger 14" UHT tongs. Break out blank joint - threads galled. Lay down blank joint and shoe joint. Strap and back up shoe
track. PJSM for running casing. MU 9-5/8" 40# L80 BTC shoe track to the diamond. Baker-lok first 3 connections and add centralizers per tally. Check floats -
holding and install bypass baffle on top of float collar per HES cementer. RIH with 9-5/8", 40#, L80, BTC casing per tally from 169' to 788'. Top drive leaking
hydraulic fluid. Investigate and troubleshoot leak point. Determined the leak point was a bad solenoid. Rig went dark and on generators at 17:40 hours. Discussed
issue and timeframe to repair with drilling Engineer, decided to POOH laying down 9-5/8" casing to the shoe track. Clean the rig floor. Perform top drive
inspection to ensure not tools left overhead. PJSM. RD the Volant CRT, bail extensions and 350-ton spiders. RU backup tongs. POOH laying down 9-5/8" casing
from 788' to 207'. PU = 70K & SO =60K. Lost 17 bbls while POOH. Demobilize casing running equipment from the rig floor. Blow down the top drive. Clean the
top drive and drain the hydraulic reservoir.
7/28/2023 RU scaffolding around the top drive. Remove main hydraulic manifold block from the top drive. Install new manifold block. Reinstall solenoid valves and reconnect
all the lines. Function test - good. Inspect the top drive for tools. RD the scaffolding. Install the top drive front guard. Loss rate = 1 BPH. RU the Volant CRT, bail
extension and elevator. Mobilize and RU 350-ton spiders and casing tongs. RIH with 9-5/8", 40#, L80, BTC casing from 207' to 500' installing centralizers per
tally. TQ = 9K ft-lbs with Volant CRT. Galled box on joint #8 and new joint #76. Lay down joint #76 and get replacement joint # 74. Breakout the coupling on joint
#8 and MU a new coupling. RIH with 9-5/8", 40#, L80, BTC casing from 500' to 788' installing centralizers per tally. TQ = 9K ft-lbs with Volant CRT. Filling on the
fly and top off every 10 joints. RIH with 9-5/8", 40#, L80, BTC casing from 788' to 1,825' installing centralizers per tally. TQ = 9K ft-lbs with Volant CRT. Filling on
the fly, top off every 10 joints and breaking circulation pumping 15 bbls every 20 joints.
7/29/2023 RIH with 9-5/8", 40#, L80, BTC casing from 1,825' to 3,202' installing centralizers per tally. TQ = 9K ft-lbs with Volant CRT. Filling on the fly, top off every 10
joints and breaking circulation pumping 15 bbls every 20 joints. PU = 177K & SO =105K. MU the ES cementer to 3,241'. RIH with 9-5/8", 47#, L80, BTC casing
from 3,202' to tag at TD of 5,491' installing centralizers per tally. TQ = 9K ft-lbs with Volant CRT. Filling on the fly, top off every 10 joints and breaking circulation
pumping 15 bbls every 20 joints. PU = 298K & SO =130K. Remove the spiders, elevators and bail extensions. Stage the pumps up to 6 BPM = 250 psi (ICP).
Circulate and condition the mud while reciprocating 30'. FCP = 130 psi. MW = 9.4 ppg, Vis = 48 & YP = 14. PU = 263K & SO = 145K. SimOps. Cementer spotted
in and RU. Prep the mud pits for cement job. Shut down the pumps. Blow down the top drive. MU the space out pup joints. Redope the cup and reengage the
Volant CRT. RU the cement line to the Volant. PJSM with all parties involved while continuing to circulate. Continue to circulate. Mix Desco, SAPP and Bicarb in
the last 50 bbls pumped. Found cement for the last cement job in the cement line Demco valve. Open up the valve, clean, install new seat and put valve back
together. Shut down the pumps. HES flood line with fresh water and break circulation with 5 bbls. PT lines to 1,000/4,000 psi - good test. 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 4.4 BPM = 180 psi. Drop bypass plug. Mix and pump 180
bbls of 12.0 ppg lead cement (EconoCem, Type I/II, 2.347ft^3/sk yield, 430 sks total) at 4.7 BPM = 300 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 3.7 BPM = 450 psi. Drop shut off plug. HES pump 20 bbls water at 6.3 BPM = 370 psi. Displace
with 205 bbls of 9.4 ppg spud mud from the rig at 7 BPM = 200 psi. Pumped 72 bbls of 9.4 ppg tuned spacer from Halliburton at 4.2 BPM = 355 psi. Pumped 104
bbls 9.4 ppg mud from the rig at 6 BPM = 540 psi ICP & 810 psi FCP. Slowed rate to 3.4 BPM = 690 psi ICP & 710 psi FCP for the last 10 bbls. Bumped the
plugs on time at 1,030 strokes. CIP at 01:15 hours. Pressure up to 1,500 psi and hold for 3 minutest. Bleed pressure to 0 psi. Check floats - floats holding.
Pressure up to 2,780 psi shifting the ES cementer open. Reciprocated pipe until the last 20 bbls of the displacement. Set the shoe 1' off bottom at 5,490'.
Circulate through the ES cementer at 2,266' at 6 BPM = 320 psi ICP & 190 psi FCP. Got interface at 980 strokes, divert to the rock washer. Dump 48 bbls
cement, 60 bbls spacer, 40 bbls interface. Take returns to pits. Circulate total of 5 BU total. FCP= 200 psi. Shut down the pumps. Flush the stack and surface
equipment 3 times with blackwater. Breakout the Volant, clean, dope cup and reengage. Continue to circulate through the ES cementer at 6 BPM = 190 psi while
waiting for the cement to reach 500 psi compressive strength. Prepare for the 2nd stage cement job.
7/30/2023 Continue to circulate through the ES cementer at 6 BPM = 190 psi while waiting for the cement to reach 500 psi compressive strength. Prepare for the 2nd stage
cement job. Hold PJSM with rig crew and cementers. Shut down and break out Volant CRT. Re-dope cup and inspect dies. Re-make up Volant CRT. Blow air
down cement line back to cementers to verify clear. HES cementers push 5 bbls water ahead to fill lines. Shut down and PT surface lines to 1,000/4,000 psi for 5
minites - good.vBleed off pressure and line up valves to cementers. Batch up tuned spacer with dye and Pol-E-Flake. Pump 60 bbls 10 ppg tuned spacer with
Red dye and Pol-E-Flake in first 10 bbl at 4.2 BPM = 190 psi. Pump total of 288 bbls (562 sks) 10.7 ppg ArcticCem lead cement at 6 BPM = 430 psi. Spacer back
at 190 bbls into lead cement. Good 10.4 ppg cement back at 244 bbls into lead. Pump total of 56 bbls (270 sks) 15.8 ppg HalCem at 2.5 BPM = 175 psi. Shut
down and drop closing plug. Kick out with 20 bbls water from cementers at 5 BPM = 170 psi. Displace with 144.8 bbls 9.4 ppg mud from mud pumps at 7 BPM =
780 psi after catching pressure. Slow rate to 3 BPM = 630 psi, 10 bbld prior to plug bump. Final circulating pressure 635 psi. Bump plug on strokes and pressure
up to close ES cementer - closed at 1,650 psi. Pressure up to 2,150 psi and hold for 3 minutes. Bleed off pressure and check floats - holding. CIP at 16:14 hrs.
Lost 5 bbls during job. 60 bbls spacer, 50 bbls interface and 234 bbls cement back to surface. Blow down the lines. Disconnect the knife valve from the
accumulator. Drain the stack and flush with blackwater 3 times. RD the Volant CRT. RU the 9-5/8" elevators. Vacuum out the mud from the casing. ND the knife
valve. BOLDS on the speed head. Let the air out of the air boots on the riser. Lift the surface annular. SimOps: ND diverter line. Install the casing slips with 100K
on the slips. SimOps: ND diverter line. Cut the 9-5/8" casing and lay down. Cut joint = 28.22'. SimOps: ND diverter line. Pull the riser. ND the bell nipple. ND the
surface annular and remove the cellar. Remove bell nipple from the cellar. Pull the mouse hole. Remove 4" conductor valves and install caps. ND diverter tee.
SimOps: Demobilize casing equipment from the rig floor. Mobilize the wellhead into the cellar. Install slip-loc wellhead. PT the void to 500 psi for 5 minutes and
3,800 psi for 10 minutes - good test. NU adapter spool, spacer spool and BOP stack.
7/31/2023 Continue to NU the BOP stack. Install turn buckles and trip nipple. Obtain RKB's. Install test plug and change upper rams to 2-7/8" x 5" VBR's. Rig up to test
BOPE. Break in VBR's per recommendation. Flood stack with water. Shell test the BOP stack to 250/3,000 psi (passed). Conduct initial BOPE test to 250/3,000
psi: UPR & LPR (2-7/8 x 5 VBRs) with 3-1/2 & 5 test joints, annular with 3-1/2 & 5 test joints, accumulator drawdown test and test gas alarms. All tests performed
with fresh water against test plug. The test was witnessed by AOGCC inspector Adam Earl. Tests:. 1.Annular with 3-1/2 test joint, 3 Demco kill, 3-1/2 FOSV,
choke valves 1, 12, 13 & 14 (passed). 2.UPR with 3-1/2 test joint, 3-1/2 dart valve, HCR kill, choke valves 9 & 11 (passed). 3.Manual kill, 5 TIW, choke valves
5, 8 & 10 (passed). 4.5 dart valve, choke valves 4, 6 & 7 (passed. 5.Upper IBOP, Choke valve 2 (passed). 6.Lower IBOP, HCR choke (passed). 7.LPR with
3-1/2 test joint (passed). 8.UPR with 5 test joint, manual choke (passed). 9.LPR with 5 test joint (passed). 10.Blind rams, choke valve 3 (passed).
11.Manual adjustable choke (passed). 12.Hydraulic super choke (passed). Accumulator Test:. System pressure = 3,000 psi. Pressure after closure = 1,600
psi. 200 psi attained in 36 seconds. Full pressure attained in 187 seconds. Nitrogen Bottles - 6 at 1,945 psi. Control System Response Time:. Annular = 15
seconds. UPR, Blind Rams & LPR = 7 seconds. HCR Choke & Kill = 2 seconds. Pull the test plug and install the wear ring (ID = 9"). Blow down and RD testing
equipment. Mobilize BHA components to the rig floor. PJSM. MU 8-1/2" Cleanout BHA: 8-1/2" tricone bit, 6-3/4" mud motor with non-ported float installed in top
and ABH set at 1.5 deg to 32'. TIH with 6 stands 5" HWDP including jar stand to 588'. TIH with cleanout BHA from 588' to 2,204'. PU = 11K & SO = 80K. Fill the
DP. Wash and ream from 2,204' to tag on cement at 2,268'. Drill cement, plug and ES cementer from 2,268' to 2,273' at 380 GPM = 610 psi, 40 RPM = 3-6K ft-
lbs TQ, WOB = 5-10K. Wash and ream through the ES cementer 2 times and drift through without pump/rotary. Wash and ream from 2,273' to 2,487' at 380 psi =
610 psi chasing debris. TIH from 2,487' to 5,343'. PU = 210K & SO = 80K. Wash and ream down from 5,343' to tag at 5,355' at 380 GPM = 800 psi, 20 RPM =
12K ft-lbs TQ. Circulate 2 BU at 380 GPM = 780 psi, 20 RPM = 14K ft-lbs TQ reciprocating 90'. Lay down a single to 5,343'. RU testing equipment and purge air
from the system. Close the UPR. PT the 9-5/8", 40#x47#, L-80 casing to 2,500 psi for 30 minutes charted - good test.
8/1/2023 Drill cement and float equipment from 5,355' to 5,490'. Drill rathole and 20' of new formation to 5,511' at 390 GPM = 750 psi, 40 RPM = 14K ft-lbs TQ, WOB = 4-
10K. PU = 193K, SO = 130K & ROT = 119K. Circulate and condition mud prior to performing FIT at 500 GPM = 1180 psi, 40 RPM = 12K ft-lbs TQ, reciprocating
string from 5,491' to 5,440'. RU testing equipment and purge air from the system Close the UPR. Perform FIT to 12.0 ppg with 9.3 ppg MW at 3,916' TVD and
applying 575 psi at surface. Pumped 1.1 bbls bled back 1 bbl. Blow down and rig down test equipment. Pump dry job for trip out. TOOH from 5,438' to 2,014'.
Service top drive, drawworks and wash pipe. Add 1 gallon oil to top drive. Repair hydraulic hose on ST-80 iron ruffneck. Continue to TOOH from 2,014' to 588'.
Lost 7.5 bbls while TOOH. Monitor the well for flow - static. Lay down 15 joints of HWDP and rack back jar stand. Lay down cleanout BHA. Bit grade: 1-1-WT-A-E-
1-NO-BHA. Clear and clean the rig floor. Mobilize BHA component to the rig floor. Pull the master bushings and install the split bushings. PJSM. PU and MU 8-
1/2" lateral BHA to 314'. TIH from 314' to 2,214'. Fill DP. Shallow pulse test MWD, test geo-span downlink and break in the geo-pilot seals. TIH from 2,214' to
5,259'. Single in the hole with 5" DP from the pipe shed from 5,259' to 5,450'. PU = 195K & SO = 74K. PJSM. Drain the riser. Pull the MPD riser and install the
MPD RCD bearing. Install the RCD head skirt for the drip pan. Fill the DP and break circulation. Check for leaks - none. PJSM. Pump pit #4 empty. Pump 30 bbl
spacer pill. Displace the well from 9.3 ppg spud mud to 8.8 ppg FloPro NT at 6 BPM = 580 psi (ICP), 30 RPM = 13K ft-lbs TQ. Wash to TD with mud at the bit
then pull into the casing. Reciprocate 80'. Good mud to surface at 7 BPM = 480 psi (FCP), 30 RPM = 5K ft-lbs TQ, PU = 150K & SO = 103K. Dump spacer & 49
bbls of interface. PJSM. Slip and cut 51' (8 wraps) of drilling line. Service the top drive. Inspect the saver sub. Changeout the saver sub.
8/2/2023 Drill 8-1/2" lateral from 5511' to 6021' (3930' TVD), 510' drilled, 85'/hr AROP. 550 GPM = 1540 PSI, 120 RPM = 8K ft-lbs Tq, 5-10K WOB. MW = 9.0 ppg, vis =
40, ECD = 10.14, Max Gas = 1665u. PU = 135K, SO = 90K ROT = 112K. Geo-steer to clean OA-1 sand, then maintain formation dip @ 89.5 deg. MPD choke full
open while drilling, trapping 150 psi on connections. Drill 8-1/2" lateral from 6021' to 6632' (3948' TVD), 611' drilled, 101.8'/hr AROP. 550 GPM = 1680 PSI, 120
RPM = 7-8K ft-lbs Tq, 7-10K WOB. MW = 8.95 ppg, vis = 41, ECD = 10.19, Max Gas = 1913u. PU = 140K, SO = 87K ROT = 109K. MPD choke full open while
drilling, trapping 150 psi on connections. Start dropping trajectory @ 6300 for planned undulation down to OA-3. Pump 30 bbl hi-vis sweep at 6499', back 200
stks late with 100% increase. Drill 8-1/2" lateral from 6632' to 7259' (3982' TVD), 627' drilled, 104.5'/hr AROP. 550 GPM = 1750 PSI, 100-120 RPM = 6-8K ft-lbs
Tq, 10-12K WOB. MW = 9.05 ppg, vis = 39, ECD = 10.23, Max Gas = 1201u. PU = 139K, SO = 92K ROT = 115K. MPD choke full open while drilling, trapping
150 psi on connections. Encounter Fault #1 @ 7060' with a 4' DTE throw moving wellbore from the upper OA-3 to the lower OA-3. Drilled out the bottom of OA-3
at 7170. Drill 8-1/2" lateral from 7259' to 7882' (3955' TVD), 623' drilled, 103.8'/hr AROP. 550 GPM = 1840 PSI, 120 RPM = 7K ft-lbs Tq, 10-12K WOB. MW =
9.1 ppg, vis = 38, ECD = 10.36, Max Gas = 1267u. PU = 137K, SO = 86K ROT = 112K. MPD choke full open while drilling, trapping 150 psi on connections.
Pump 30 bbl hi-vis sweep at 7450', back on time with 50% increase. Build at 93 deg and re-enter the OA-3 at 7555. Continue drilling up section to target the OA-
1. Rig Tripped off High Line power at 00:05, On Gen Power at 00:12. We have drilled 14 concretions for a total thickness of 147 (6.4% of the lateral). Last survey
at 7770.86 MD / 3962.37' TVD, 93.54 deg inc, 335.06 deg azm, 7.53 from plan, 4.26' high and 6.20 left.
8/3/2023 Drill 8-1/2" lateral from 7882' to 8497' (3957' TVD), 615' drilled, 102.5'/hr AROP. 545 GPM = 1780 PSI, 120 RPM = 8K ft-lbs Tq, 5-10K WOB. MW = 9.1 ppg, vis
= 38, ECD = 10.44, Max Gas = 660u. PU = 145K, SO = 82K ROT = 109K. MPD choke full open while drilling, trapping 150 psi on connections. Pump 30 bbl hi-
vis sweep at 8599', back 200 stks late with 50% increase. Drill 8-1/2" lateral from 8497' to 8973' (3984' TVD), 476' drilled, 79.3'/hr AROP. 550 GPM = 1810 PSI,
120 RPM = 10K ft-lbs Tq, 11K WOB. MW = 9.1 ppg, vis = 40, ECD = 10.62, Max Gas = 574u. PU = 147K, SO = 76K ROT = 107K. MPD choke full open while
drilling, trapping 150 psi on connections. Drill 8-1/2" lateral from 8973' to 9449' (3980' TVD), 526' drilled, 87.7'/hr AROP. 550 GPM = 2000 PSI, 120 RPM = 11K
ft-lbs Tq, 9K WOB. MW = 9.1 ppg, vis = 41, ECD = 10.64, Max Gas = 500u. PU = 147K, SO = 72K ROT = 110K. MPD choke full open while drilling, trapping
150 psi on connections. Put Rig on Highline power @ 19:00. Drill 8-1/2" lateral from 9449' to 10032' (3936' TVD), 583' drilled, 97.2'/hr AROP. 550 GPM = 2100
PSI, 120 RPM = 11K ft-lbs Tq, 15K WOB. MW = 9.1 ppg, vis = 41, ECD = 10.90, Max Gas = 364u. PU = 140K, SO = 67K ROT = 105K. MPD choke full open
while drilling, trapping 150 psi on connections. Pump 30 bbl hi-vis sweep at 9544', back 200 stks late with 100% increase. Encountered fault #2 at 9730' (throw
TBD) moving the wellbore from the lower OA-1 to below the OA package. We have drilled 34 concretions for a total thickness of 391' (8.8% of the lateral). Last
survey at 9959.90' MD / 3944.32' TVD, 96.27 deg inc, 335.39 deg azm, 3.37' from plan, 3.10' high and 1.32 right.
8/4/2023 Drill 8-1/2" lateral from 10032' to 10675' (3899' TVD), 643' drilled, 107.2'/hr AROP. 550 GPM = 2100 PSI, 120 RPM = 10K ft-lbs Tq, 4-12K WOB. MW = 9.1 ppg,
vis = 45, ECD = 11.3, Max Gas = 1464u. PU = 145K, SO = 61K ROT = 104K. MPD choke full open while drilling, trapping 150 psi on connections. Re-entered
the OA-sand at 10,460 after crossing fault #2 (~80 DTE throw). Pump 30 bbl hi-vis sweep at 10595', back 300 stks late with 100% increase. Drill 8-1/2" lateral
from 10675' to 10926' (3902' TVD), 251' drilled, 50.2'/hr AROP. 550 GPM = 1930 PSI, 120 RPM = 10K ft-lbs Tq, 8K WOB. MW = 9.0 ppg, vis = 40, ECD =
10.70, Max Gas = 490u. PU = 155K, ROT = 109K. MPD choke full open while drilling, trapping 150 psi on connections. Performed a 290 bbl dump and dilute
with fresh mud at 10,686 to help with ECD management. ECDs dropped from 11.8 ppg to 10.8 ppg after dilution. Unable to record slack-off weights after 10,780'.
MP#1 tripped off due to a sprocket slip fault. Pull off bottom and Service Rig. SimOps: Reset sprocket slip fault on MP#1. Drill 8-1/2" lateral from 10926' to 11543'
(3899' TVD), 617' drilled, 88.1'/hr AROP. 550 GPM = 2160 PSI, 120 RPM = 11K ft-lbs Tq, 7K WOB. MW = 9.0 ppg, vis = 41, ECD = 11.05, Max Gas = 485u. PU
= 150K, ROT = 108K. MPD choke full open while drilling, trapping 150 psi on connections. Pump 30 bbl hi-vis sweep at 11543', back 300 stks late with 50%
increase. Drill 8-1/2" lateral from 11543' to 12336' (3910' TVD), 793' drilled, 132.2'/hr AROP. 550 GPM = 2220 PSI, 120 RPM = 14K ft-lbs Tq, 3-5K WOB. MW =
9.1 ppg, vis = 42, ECD = 11.26, Max Gas = 762u. PU = 161K, ROT = 103K. MPD choke full open while drilling, trapping 150 psi on connections. We have drilled
48 concretions for a total thickness of 505' (7.4% of the lateral). Last survey at 12244.72' MD / 3906.54' TVD, 87.20 deg inc, 332.84 deg azm, 17.65' from plan,
12.96' high and 11.98' left.
8/5/2023 Drill 8-1/2" lateral from 12336' to 12765' (3927' TVD), 429' drilled, 71.5'/hr AROP. 550 GPM = 2140 PSI, 120 RPM = 14K ft-lbs Tq, 5-10K WOB. MW = 9.1 ppg,
vis = 39, ECD = 11.23, Max Gas = 605u. PU = 160K, ROT = 104K. MPD choke full open while drilling, trapping 150 psi on connections. Pump 30 bbl hi-vis
sweep at 12685', back 500 stks late with 30% increase. Rig off highline power at 11:00. Drill 8-1/2" lateral from 12765' to 12970' (3925' TVD), 205' drilled,
34.2'/hr AROP. 550 GPM = 2100 PSI, 120 RPM = 12-13K ft-lbs Tq, 10K WOB. MW = 8.9 ppg, vis = 39, ECD = 10.81, Max Gas = 474u. PU = 168K, ROT =
118K. MPD choke full open while drilling, trapping 150 psi on connections. Perform 290 bbl dump and dilute at 12,795' for ECD management. Drill 8-1/2" lateral
from 12970' to 13093' (3924' TVD), 123' drilled, 20.5'/hr AROP. 450-550 GPM = 1840 PSI, 60-120 RPM = 12-14K ft-lbs Tq, 10-25K WOB. MW = 8.9 ppg, vis =
39, ECD = 10.57, Max Gas = 474u. PU = 165K, ROT = 110K. Slow drilling through high number of concretions. Vary parameters to find optimal ROP. No positive
drilling performance results observed. MPD choke full open while drilling, trapping 150 psi on connections. Drill 8-1/2" lateral from 13093' to 13255' (3929' TVD),
162' drilled, 27'/hr AROP. 450-550 GPM = 1840 PSI, 60-120 RPM = 12-14K ft-lbs Tq, 10-25K WOB. MW = 8.9 ppg, vis = 39, ECD = 10.57, Max Gas = 474u.
PU = 165K, ROT = 110K. MPD choke full open while drilling, trapping 150 psi on connections. Pump 30 bbl hi-vis sweep at 13150', back 600 stks late with no
increase. Pump 30 bbl lube pill (3% lube 776) at 13168'. No positive drilling performance results observed. We have drilled 70 concretions for a total thickness of
733' (9.5% of the lateral). Last survey at 13194.99' MD / 3927.02' TVD, 88.32 deg inc, 335.31 deg azm, 20.19' from plan, 3.39' high and 19.90' left.
8/6/2023 Drill 8-1/2" lateral from 13255' to 13800' (3919' TVD), 545' drilled, 90.8'/hr AROP. 550 GPM = 2040 PSI, 120 RPM = 12-14K ft-lbs Tq, 5-10K WOB. MW = 8.9
ppg, vis = 39, ECD = 10.83, Max Gas = 67u. PU = 160K, ROT = 103K. MPD choke full open while drilling, trapping 150 psi on connections. Crossed Fault #3 at
13485' (8' DTW). Drill 8-1/2" lateral from 13800' to 14176' (3926' TVD), 376' drilled, 62.7'/hr AROP. 500 GPM = 1870 PSI, 120 RPM = 11-12K ft-lbs Tq, 10-15K
WOB. MW = 9.0 ppg, vis = 43, ECD = 11.05, Max Gas = 708u. PU = 170K, ROT = 107K. MPD choke full open while drilling, trapping 150 psi on connections.
Drill 8-1/2" lateral from 14176' to 14315' (3933' TVD), drilled 139' = 39.7'/hr AROP. 500 GPM = 1990 PSI, 120 RPM = 15-16K ft/lbs TQ, WOB = 7-15K. PU =
175K, ROT = 110K. MW = 9.0 ppg, Vis = 41, ECD = 11.12, max gas = 544 units. MPD choke full open while drilling, trapping 150 psi on connections. Obtain
final survey. SPRs. Pump 30 bbls high vis sweep, back 700 strokes late with no increase. Circulate 3x bottoms up, reciprocating pipe and racking back a stand
every bottoms to 14150'. 400-500 GPM = 1500-2040 PSI, 120 RPM = 16K TQ. MW = 9.1, Vis = 42, ECD = 10.8, max gas = 574 units. Trip back to BTM on
elevators f/ 14150' t/ 14315' and continue circulating, 500 GPM, 2040 psi. Rot and reciprocate 90', 120 RPM, 16k Tq. Finish prep mud pits & build spacer pill.
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 955 bbls of 8.45 ppg viscosified brine with 3% lubes (1.5% 776 and 1.5% LoTorq). 90 concretions
drilled, for a total thickness of 908 (10.3% of the lateral). Final Survey = 14243.24 MD / 3928.79' TVD, 86.32 deg inc, 332.82 deg azm, 10.88 from plan, 2.46'
high and 10.60 left.
8/7/2023 Shut down the pumps with clean 8.45 ppg viscosified brine to surface. Obtain new SPR's. PU = 205K, SO = 50K & ROT = 125K. Monitor the wellbore pressure
with MPD choke 3 times 5 minutes each = 62, 69 & 60 psi. EMW = 8.8 ppg. SimOps: Clean pit #3 and load 8.45 ppg 3% lube brine in pits #3 & 4. BROOH from
14315' to 12590', 5-10 min/std slowing as needed for tight spots. L/D DP via 90' mouse hole. 350 GPM = 910 psi, 120 RPM = 16 ft-lbs TQ, max gas = 403 units.
PU = 192K, SO = 104 & ROT = 124K. Initial loss rate exceeding 150 BPH dynamic, slowing to 20-30 BPH after pulling above Fault #3. BROOH from 12590' to
10115', 5-10 min/std slowing as needed for tight spots. L/D DP via 90' mouse hole. 350 GPM = 840 psi, 120 RPM = 16 ft-lbs TQ, max gas = 258 units. PU =
160K, SO = 60 & ROT = 120K. Loss rate = 10-20 BPH. BROOH from 10115' to 7450', 5-10 min/std slowing as needed for tight spots. L/D DP via 90' mouse hole.
350 GPM = 810 psi, 120 RPM = 13 ft-lbs TQ, max gas = 255 units. PU = 145K, SO = 85 & ROT = 113K. Loss rate = 10-12 BPH. BROOH from 7450' to 5450', 5-
10 min/std slowing as needed for tight spots. L/D DP via 90' mouse hole. 350 GPM = 780 psi, 120 RPM = 10 ft-lbs TQ, max gas = 107 units. Loss rate 10-12
BPH. Lost total of 225 bbls while BROOH. Pump 30 bbl hi-vis sweep at 410 GPM = 890 psi, 100 RPM = 4K ft-lbs TQ reciprocating 90' and circulate the casing
clean with 2 BU. Sweep back on time with 0% increase. MW in/out = 8.8 ppg. 5 bbls loss while circulating. Monitor the wellbore pressure with MPD choke 2 times
5 minutes each = 79 psi, 68 psi, 62 psi, 55 psi. EMW = 9.1. SimOps: Start weighting up surface volume to 9.0 ppg.
8/8/2023 Weighting up system in 0.2 ppg increments from 8.8 ppg to 9.2 ppg. 450 GPM, 990 PSI, 80 RPM, 3-4K ft-lbs Tq. Reciprocating string 90' while circulating.
Monitor well for flow - no flow. PJSM with MPD and rig crew. Remove RCD and install trip nipple. Trip out of the hole F/ 5450' T/ 5259'. Drop 2.45" drift for
upcoming liner run. PU 136K, SO 106K. Pump dry job and blow down top drive. Trip out of the hole, racking back 5" DP in derrick F/5259' T/ 314' - top of BHA.
Lost 16 bbls on trip out. Rig on Hi-Line Power @ 14:30. L/D HWDP, recover drift on wire, L/D jars, float subs and NMDCs from 314'. Download ADR, StrataStar &
BaseStar data. Break bit and lay down Geo-Pilot. Bit graded: 1-3-BT-T-X-I-CT-TD. Normal wear on the BHA from drilling and BROOH. Loss rate 2 BPH. Clear
and clean the rig floor. Flush & B/D Geo-skid. Mobilize 4-1/2" handling equipment to Rig Floor. Flush flowline & Service TD. R/U 4-1/2" double stack tongs and
elevators. M/U crossover to FOSV. Static loss rate = 2 BPH. PJSM. P/U, M/U & RIH round nose float shoe with crossover joint on 4-1/2", 13.5#, L-80, H625
slotted liner per tally installing a centralizer on every joint to 1558'. Optimum TQ = 9,600 ft-lbs. PU = 55K & SO = 55K. Loss rate = 1.5 BPH. Continue to RIH with
4-1/2", 13.5#, L-80, H625 slotted liner per tally installing a centralizer on every joint from 1558' to 8059'. Optimum TQ = 9,600 ft-lbs. PU = 105K & SO = 70K. At
the shoe PU = 90K & SO = 77K. Loss rate = 1.5 BPH. Rig off Hi-Line and on Gen power at 05:30.
8/9/2023 Continue to RIH with 4-1/2", 13.5#, L-80, H625 slotted liner per tally installing a centralizer on every joint from 8059' to 8976'. Optimum TQ = 9,600 ft-lbs. PU =
111K & SO = 69K. Losses RIH with liner= 36.5 bbls. Verify pipe count. C/O elevators to 5" DP. P/U Baker 7" x 9-5/8" SLZXP liner top packer and RIH one stand
DP to 9104'. Pump 5 bbls @ 4 BPM, 350 PSI to ensure clear flow path. Obtain Rot parameters 20 RPM, 9k Tq / 30 RPM, 7k Tq. 115K PU, 70K SO, 85K ROT.
RIH w/ 4.5 liner on 5 drill pipe from 9104 to 14315', Tag bottom on depth with 10k. 180K PU / 85K SO. Proper displacement recorded on TIH. LD 1 joint DP. Drop
1.125" phenolic setting ball. Place liner in tension at 14315' set depth. Pump ball down with 30 bbl hi-vis sweep at 3 BPM = 290 psi slowing at 600 stks to 1.5
BPM = 195 psi. Ball on seat 201 strokes early (allowed to free fall) at 777 strokes. Pressure up to 2000 psi, hold for 5 min. S/O and see string travel. P/U to
tension and pressure up to 2200 psi, hold for 5 min. S/O taking 50K wt. confirm set. Pressure up & observe neutralize at 2900 psi, shear at 4000 psi. P/U and
observe travel at 130K confirming release. Top of liner at 5287.46'. Close upper pipe rams and attempt to pressure test 5" x 9-5/8" annulus. Observe flow from
drill string at 500 psi. Shut down and verify surface equipment. Attempt again with same results. Bleed pressures and open pipe rams. P/U to expose dog sub,
rotate 20 RPM - 6k Tq , 115k hookload, set down 70k. Attempt to pressure test 5" x 9-5/8" annulus. Observe flow from drill string at 1000 psi. Discuss options with
drilling engineer. Make another attempt - P/U to neutral, rotate 20 RPM and set down 75k wt. Attempt to pressure test 5" x 9-5/8" annulus. Observe flow from drill
string at 1000 psi. Decision made to POOH. P/U and pull running tool out of liner tie-back to 5262'. Circulate the 9-5/8" casing clean 8 BPM, 670 psi while
reciprocating pipe. Sweep return on time with no increase. 130K PU / 110K SO. 4 bbl losses. Observe well - static. Pump dry job. POOH from 5262' to surface,
racking stands in Derrick. L/D liner running tool & inspect same. Observe damage to seals and recover a 1x1 triangular piece of aluminum from HRD-E. 5 bbl total
losses. Clear and clean rig floor and perform general housekeeping while waiting on new seal assembly w/ dog sub being mobilized to Rig. Remove MPD drip
pan from BOP Stack. 1 BPH static loss rate. M/U new seal assembly and trip in hole with stands 5" DP t/ 3725'. Single in the hole with 5" HWDP f/ 3725' to 5260'.
Make up a double of 5" DP to tag with. 161K PU, 141K SO, 150K ROT. 2 bbl total losses. Slack off and tag up w/ 5k at 5294'. P/U to neutral and engage rotary at
20 RPM 7k Tq. S/O and set 80k down. P/U to neutral and rig up to test IA. Test IA to 1600 psi on Chart for 10 min. Good Test. Pump out of SBR at 2 BPM 180
psi , increase rate to 9 BPM 425 psi once above LTP and circulate a bottoms up. 3 bbl losses. Blow down Top Drive, choke & kill lines. Monitor Well - Static.
POOH laying down HWDP to 5045'. Pump dry job.
Activity Date Ops Summary
8/10/2023 POOH laying down 5" HWDP to the pipe shed from 5045' to 3753'. POOH laying down 5" DP from 3753' to surface. Inspect and lay down seal assembly. No
damage or wear observed on seals or dog sub. Lost 16 bbls while POOH. Clear and clean rig floor. Pull split bushings and install master bushings. Remove wear
bushing. M/U stack washing tool & flush BOP stack. Mobilize Centrilift & 3-1/2 handling equipment to the rig floor. R/U Doyon casing equipment. M/U XO to FOSV.
Static loss rate = 1.5 BPH,PJSM. P/U 7" bullet seal assembly and RIH to 22'. RIH with 3-1/2", 9.3#, L-80, EUE 8rd tubing from 22' to 637'. Optimum TQ = 3,130 ft-
lbs. MU XN assembly, tubing joint, Baker Zenith gauge assembly, tubing joint and Viking sliding sleeve assembly to 775. Optimum TQ = 3,130 ft-lbs. Loss rate =
1.5 BPH,RIH with 3-1/2", 9.3#, L-80 EUE 8rd tubing spooling TEC wire and installing cannon clamps per tally from 775' to 3711'. SO = 60K. Optimum TQ = 3,130
ft-lbs. Check TEC wire continuity every 1,000'. Loss rate = 1.5 BPH,RIH with 3-1/2", 9.3#, L-80 EUE 8rd tubing spooling TEC wire and installing cannon clamps per
tally from 3711' to no-go at 5305.27' (bottom of mule shoe) with 10K down. Liner top at 5295.70' (8.24' deeper than liner tally). Optimum TQ = 3,130 ft-lbs. Check
TEC wire continuity every 1,000'. PU = 75K & SO = 65K. Lost 18 bbls while running tubing. Close annular and pressure up on IA to 400 psi. Confirm seals in SBR.
Space out - Lay down joints #170, 169, 168 & 167. M/U 2.15, 6.09, 8.19 & 10.17 pup joints and joint #167. P/U landing joint w/ 3-1/2" UEU x 3-1/2" TC-II crossover
and tubing hanger. Terminate the TEC and feed through the tubing hanger. Land tubing on hanger at 5304.25' with locator sub 1.03' of no-go. Centrilift readings:
Tubing = 1825.08 psi, 74 deg F & 18.6 volts. Wellhead Rep verify hanger landed. R/U circulating equipment to reverse circulate. Apply 500 psi to IA, P/U to expose
the circulating ports. Hold PJSM.
8/11/2023 Flood lines and PT to 3,900 psi - good test. Reverse circulate 329 bbls of 8.4 ppg corrosion inhibited source water at 6 BPM = 1,130 psi ICP / 1,360 psi FCP,Strip
through the annular closing the circulating ports leaving the tubing hanger 2' from landing. Drain the stack, blow down lines and rinse the stack.. Land the tubing
hanger with 25k set on hanger and 1.03' off the NOGO,. RILDS. RU testing equipment. PT the IA to 3,700 psi for 30 minutes charted - good test. 5.2 bbls pumped,
5.2 bbls bled back. Blow down and RD lines, LD pup joint, FOSV and landing joint, WHR install BPV,Clean and clear the rig floor. Load out 3 1/2'' completion
running tools, spooler, job box, vac out stack and clean out rig floor drip pan. Finish cleaning the drip pan, PJSM, Remove RCD head from the stack, MU masher
and jt DP, break annular cap. Simops: Remove the hi line box from back of rig. Flush suction and gun lines with fresh water, clean in mud pits. Remove pipe and
blind rams from BOPs, N/D BOPs, hoist and set stack on pedestal. Remove accumulator hoses from stack. Continue cleaning mud pits. Mobilize tree into the cellar.
Install CTS plug into BPV. N/U tree and adapter to the tubing spool. PT tubing hanger void to 500 psi for 5 min and 5,000 psi for 10 minutes - good test. RU and fill
tree with diesel. PT the tree to 250/5,000 psi - good test.
8/12/2023 Pull the CTS plug and BPV with dry rod. Shut in and secure well. Final well pressures: tubing = 0 psi & IA = 0 psi. Final Zenith gauge readings: Tubing = 1719.9 psi
& 73.9 deg, & 20.5 volts. *No BPV installed*,Clean the cellar box. Rig welder cut off the mouse hole extension and seal weld. SimOps: Prep the rig floor for skidding.
Continue cleaning mud pits. Rig down support buildings around rig. PJSM. Skid the rig floor into moving position. Move fuel trailer, Rockwasher & Beyond shack.
Secure landings and Rig for move. PJSM, Jack up Rig in prep to move off M-61. Rig released @ 06:00.
50-029-23756-00-00API #:
Well Name:
Field:
County/State:
MP M-61
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
ACTIVITYDATE SUMMARY
8/12/2023
WELLHEAD: BOP stack pulled, clean hgr void, straighten tech line, install RX54
gastet and SBMS seal. Install CTS plug. PU tree/adapter and run tech line through
adapter term sleave and land. Torque adapter to spec, swedge tech line at terrn.
sleave and test hgr void 500/5000 5 and 10 min.(PASS). RIG test tree (PASS),
250/5000psi. Pull CTS plug and Bpv with T bar. All valves closed, manifolds installed
IA and tree cap.
8/12/2023
***WELL S/I ON ARRIVAL***
STBY ON MPM-61
***CONTINUE 8/13/23***
8/13/2023 ***CONTINUE FROM 8/12/23***
8/13/2023
***WELL SHUT IN ON ARRIVAL***
OPEN SSD @ 4,539' MD
SET 3'' JET PUMP (sn# HC-00020, Ratio: 14C) @ 4,539' MD
***WELL S/I ON DEPARTURE***
8/13/2023
MPU Well Support tied Grassroots well into process. Rolled check at wing and
choke,to flow to Production as per sundry. PT'd Test,Production and PowerFluid lines
to #3650. Serviced Wellhead
No issues
9/13/2023
*** WELL SHUT-IN ON ARRIVAL.***
PULL 3" JETPUMP (ratio: 14C) FROM XD-SS AT 4,539' MD.
LRS LOADED IA W/ 175bbls INHIBITED WATER, 135bbls DIESEL FOR FREEZE
PROTECT.
SHIFT VIKING-SS CLOSED AT 4,539' MD.
LRS PUMPED 42bbls TO PRESSURE UP TO 2000psi (Holding). SEE LOG.
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.***
9/13/2023
T/I/O= 375/0 Load and Test IA. Flushed prod line with 5 bbls 100* diesel and test line
with 5 bbls 100* diesel. Pumped 180 bbls of inhibited 1% KCL down IA followed by
135 bbls diesel to freeze protect. Slickline closed sleeve. Pressured up IA to 2025 psi
with 42 bbls diesel. IA lost 24 psi in 10 min. Sleeve closed, bled IA to 200 psi and
recovered 3 bbls. Final Whps=420/200
9/14/2023
MPU Well Support converted well from 30-day State approved Producer,to an
Injector. Hung root valve on water injection header,tied into process and PT'd surface
line to 3650#. Orifice PLate Holder in wellhouse has 1.22" orifice installled. Job
handed over to I&E Group. Wellhead and all valves(root/lateral) serviced.
No issues
9/14/2023
T/I/O=470/0 MIT-IA Passed to 2084 psi. (Pre POI) Pressured up IA to 2205 psi with
3.8 bbls diesel. 1st 15 min IA lost 92 psi. 2nd 15 min IA lost 29 psi for a total loss of
121 psi in 30 min. Bled IA to 200 psi and recoered ~3 bbls. Final Whp's=470/200
9/16/2023
T/I/O=10/0 Pre AOGCC MIT-IA Passed to 1573 psi. Pressured up IA to 1683 psi with
4.4 bbls diesel. 1st 15 min IA lost 79 psi. 2nd 15 min IA lost 31 psi for a total loss of
110 psi in 30 min. Bled back 2.2 bbls. Final Whps=10/100
Daily Report of Well Operations
PBU MPM-61
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
92
1
1
1
58
1
Yes X No X Yes No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe
Cut Joint
10 3/4
383.43 -5.43299.72
SE
C
O
N
D
S
T
A
G
E
Rig
16:14
Cement at surface
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 5490 FC @ Top of Liner5,403.22
Floats Held
340.29 606
282 324
Spud Mud
CASING RECORD
County State Alaska Supv.Anderson / Toomey
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP M-61 Date Run 29-Jul-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Innovex 1.77 5,490.00 5,488.23
7.33 40.21 32.889 5/8 47.0 L-80 BTC
Csg Wt. On Hook:263,000 Type Float Collar:Innovex No. Hrs to Run:15
9.4 6
1850
10
10.7 288 6
97
810
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
635
2.5
9.4 7 164.8/164.8
401/401
1500
48
Rig
15.8 82
Bump press
Cement at surface
Bump Plug?
Y
1:15 7/30/2023 2,270
2270.58
5,490.005,491.00 5,360.97
CEMENTING REPORT
Csg Wt. On Slips:100,000
Spud Mud
Tunned Spacer
562 2.88
Stage Collar @
60
Bump press
99
234
ES Closure OK
56
12 180
34.00 RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
No. Jts. Delivered No. Jts. Run
Length Measurements W/O Threads
Ftg. Delivered Ftg. Run Ftg. Returned
Ftg. Cut Jt. Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.7
ArcticCem
Type
74 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 #71. One each on joints #73 to #77. One each with stop rings on pup joints above and below ES
cementer. One each on joints #78 to #82 the every third joint #85 to #133.
Casing 9 5/8 40.0 L-80 BTC Tenaris 83.71 5,488.23 5,404.52
Float Collar 10 3/4 BTC Innovex 1.30 5,404.52 5,403.22
Casing 9 5/8 40.0 L-80 BTC Tenaris 40.85 5,403.22 5,362.37
Baffle Adapter 10 3/4 BTC Halliburton 1.40 5,362.37 5,360.97
Casing 9 5/8 40.0 L-80 BTC Tenaris 3,069.47 5,360.97 2,291.50
Casing Pup Joint 9 5/8 40.0 L-80 BTC 18.05 2,291.50 2,273.45
ES Cementer 10 3/4 BTC Halliburton 2.87 2,273.45 2,270.58
Casing Pup Joint 9 5/8 40.0 L-80 BTC 18.02 2,270.58 2,252.56
Casing 9 5/8 47.0 L-80 BTC Tenaris 2,212.35 2,252.56 40.21
EconoCem 430 2.35
HalCem 400 1.16
4.7
HalCem 270 1.16
7/30/2023 Surface
Spud Mud
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: 08/24/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU M-61
PTD: 223-042
API: 50-029-23756-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (07/22/2023 to 08/06/2023)
x EWR-M5, AGR, ABG, BaseStar GR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL Geosteering Subfolders:
Please include current contact information if different from above.
PTD: 223-042
T37954
8/28/2023
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.08.28
12:39:14 -08'00'
1
Regg, James B (OGC)
From:Doug Yessak - (C) <dyessak@hilcorp.com>
Sent:Friday, August 11, 2023 10:24 AM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:Todd Sidoti; Nathan Sperry; Jeremiah Vanderpool - (C)
Subject:Doyon 14 MIT 8-11-23
Attachments:MIT MPU M-61 8-11-23.xlsx
Doug Yessak
Hilcorp DSM
Doyon 14
907‐670‐3090
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Milne Point Unit M-61PTD 2230420
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-042 Type Inj N Tubing 0 0 0 0 Type Test P
Packer TVD 3907 BBL Pump 5.2 IA 0 3700 3695 3695 Interval O
Test psi 3600 BBL Return 5.2 OA Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp Alaska LLC
Milne Point , MPU, M Pad
Douglas Yessak
08/11/23
Notes:Pre-Injection MIT-IA on rig. Witness waived by Guy Cook on 8/9/23 at 09:31 am. Monobore, No OA. Test to 3600 psi as per PTD.
Notes:
Notes:
Notes:
M-61
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Form 10-426 (Revised 01/2017)2023-0811_MIT_MPU_M-61
J. Regg; 10/12/2023
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT M-61
JBR 09/20/2023
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:0
good test / no failures
Test Results
TEST DATA
Rig Rep:Hanson/CharlieOperator:Hilcorp Alaska, LLC Operator Rep:Anderson/Toomey
Rig Owner/Rig No.:Doyon 14 PTD#:2230420 DATE:7/31/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopAGE230806085222
Inspector Adam Earl
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 6.5
MASP:
1323
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 2 7/8 x 5 P
#2 Rams 1 Blinds P
#3 Rams 1 2 7/8 x 5 P
#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 P3000
Pressure After Closure P1600
200 PSI Attained P36
Full Pressure Attained P187
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@1945
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P15
#1 Rams P7
#2 Rams P7
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Schrader Bluff Oil, MPU M-61
Hilcorp Alaska, LLC
Permit to Drill Number: 223-042
Surface Location: 4913’ FSL, 231’ FEL, Sec 14, T13N, R09E, UM, AK
Bottomhole Location: 1937’ FNL, 2378' FWL, Sec 02, T13N, 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 July 2023.
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.07.12 08:15:05
-05'00'
12
5.25.2023
By Grace Christianson at 2:48 pm, May 25, 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: 2023.05.25 14:04:38 -08'00'
Monty M
Myers
223-042
* BOPE test to 3000 psi. Annular to 2500 psi.
DSR-5/25/23
*
* Spacing exception required for extended pre-production to clean welbore.
Conservation Order in progress. SFD 7/10/2023
029-23756-00-00
* Casing test of 9-5/8" surface casing and FIT digital data to AOGCC
immediately upon performing the FIT.
* MIT-IA to 3600 psi. 24 hour notice to AOGCC for opportunity to witness.
* MIT-IA to 2000 psi within 10 days after stabilized injection .
24 hour notice to AOGCC.
* Approved to pre-produce for 30 days with reverse circulation jet pump. 24/7 manned monitoring on M pad if no surface safety valve while on IA power fluid injection when on 30 day pre-production.
SFD 7/10/2023MGR01JUNE2023GCW 07/11/2023
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.07.12 08:15:05 -05'00'7/12/23
7/12/23
TD of M-61planned InjectorM-61 Planned SchraderBluff Oa intersection pointM-61 AOR Map•All Wells Labelled at top Oa intersection point•Greenlines representthe footage inwellsthat are withinSchrader Bluff inside the ¼ mile radius of proposedinjector, M-61•Red triangles indicatewells that have not beendrilledyetM-12 & M-12PB1
PTD API WELL STATUS
Top of SB
OA (MD)
Top of SB
OA (TVD)
Top of
Cement
(MD)
Top of
Cement
(TVD) Schrader OA status Zonal Isolation
222-049 50-029-23716-00-00 MPU M-27 Oa Producer 6162 3933 Surface Surface Open Cement returns observed at surface.
222-053 50-029-23717-00-00 MPU M-28 Oa Injector 6547 3947 Surface Surface Open Cement returns observed at surface.
TBD TBD MPU M-60 Oa Producer N/A N/A N/A N/A N/A Not Drilled
219-083 50-029-23636-00-00 MPM-20 SB Producer 5,126' 3,875' Surface Surface Open Cement returns observed at surface.
218-176 50-029-23619-00-00 MPU M-12 OA Producer 4523 3891 Surface Surface Open Cement returns observed at surface.
218-176 50-029-23619-70-00 MPU M-12PB1 Plugback 4523 3891 Surface Surface Open Cement returns observed at surface.
Area of Review MPU M-61 SB OA
Milne Point Unit
(MPU) M-61
Application for Permit to Drill
Version 2
5/25/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 BOP N/U and Test.................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 38
18.0 RDMO ...................................................................................................................................... 39
19.0 Post-Rig Work ......................................................................................................................... 40
20.0 Doyon 14 Diverter Schematic .................................................................................................. 41
21.0 Doyon 14 BOP Schematic ........................................................................................................ 42
22.0 Wellhead Schematic ................................................................................................................. 43
23.0 Days vs Depth ........................................................................................................................... 44
24.0 Formation Tops & Information............................................................................................... 45
25.0 Anticipated Drilling Hazards .................................................................................................. 47
26.0 Doyon 14 Layout ...................................................................................................................... 50
27.0 FIT Procedure .......................................................................................................................... 51
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 52
29.0 Casing Design ........................................................................................................................... 53
30.0 8-1/2” Hole Section MASP ....................................................................................................... 54
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 55
32.0 Surface Plat (NAD 27) ............................................................................................................. 56
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1.0 Well Summary
Well MPU M-61
Pad Milne Point “M” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Oa Sand
Planned Well TD, MD / TVD 14,287’ MD / 3,898’ TVD
PBTD, MD / TVD 14,287’ MD / 3,898’ TVD
Surface Location (Governmental) 366' FNL, 231' FEL, Sec. 14, T13N, R9E, UM, AK
Surface Location (NAD 27) X= 533934 Y= 6027766
Top of Productive Horizon
(Governmental)578' FSL, 1082' FWL, Sec 12, T13N, R9E, UM, AK
TPH Location (NAD 27) X= 535242 Y= 6028716
BHL (Governmental) 1937' FNL, 2378' FWL, Sec 2, T13N, R9E, UM, AK
BHL (NAD 27) X= 531216 Y=6036742
AFE Drilling Days 17 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1323 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1713 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 24.6 ft = 58.3 ft
GL Elevation above MSL: 24.6 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2” 4-1/2” 3.96” 3.795”4.714”13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Todd Sidoti 907.777.8443 Todd.Sidoti@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 reedwards@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
MPU M-61 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-61 is part of a
multi well development program targeting the Schrader Bluff sand on M-pad. M-61 will be pre-produced for
up to 30 days pending AOGCC approval of the spacing exception.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff OA sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in the
open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately July 15th, 2023, pending rig schedule.
Surface casing will be run to 5,400’ MD / 3,899’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 4-1/2” injection liner.
7. Run 3-1/2” tubing.
8. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
p
M-61 will be pre-produced forppg gg
up to 30 days pending AOGCC approval of the spacing exception.
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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-61. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for a test period of pre-producing M-61 for up to 30 days via a reverse
circulating jet pump completion. This will allow us to clean up the well to improve future injectivity. During
flow back, Hilcorp will have a 24/7 man watch while the well is online and producing. Section 19 details the
steps required to make this happen. Note also that the MIT-IA has been changed from 2,500 psi to 3,500 psi.
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 M-61 will utilize a newly set 20” conductor on M-pad. Ensure to review attached surface plat
and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Use GWD until MWD surveys clean up.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoff’s, increase in pump pressure, or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
x Gas hydrates have not been seen on M-pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be
prepared for hydrates:
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x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x AC:
x There are no wells with clearance factors < 1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.2+ (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).
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System Type:8.8 – 9.2 ppg Pre-Hydrated M-I gel / freshwater spud mud
Properties:
Section Density Viscosity
Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –
9.8
75-175 20 - 40 25-45 <10 8.5 –
9.0
70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
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
x No OH logging program planned.
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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.4 Float equipment and Stage tool equipment drawings:
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12.5 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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Drilling Procedure
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12.7 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Ensure the permafrost is covered with 9-5/8” 47#. Estimated XO depth is 2500’.
x Ensure drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.11 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool if the plugs are not bumped.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.15 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.17 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.19 Fill surface lines with water and pressure test.
13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.21 Mix and pump cmt per below recipe for the 2
nd stage.
13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.25 Displacement is in the Stage 2 table in step 13.22.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.27 Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.28 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x N/U bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg FloPro NT fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swabbed kick at 9.2ppg
BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is R/U and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 DS50 & NC50.
x Run a ported float in the production hole section.
Email casing test and FIT digital data to AOGCC promptly upon completion of FIT. -mgr
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Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to 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
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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
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid
15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x 8-1/2” Lateral A/C:
x There are no wells with a clearance factor <1.0.
x Schrader Bluff OA Concretions: 4-6% Historically
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
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Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 Confirm PST requirements with operations engineer. Monitor the returned fluids carefully
while conditioning the mud. After 1 (or more if needed) BU, Perform production screen test
(PST). The mud has been properly conditioned when the mud will pass the production screen
test (x3 350ml samples passing through the screen in the same amount of time which will
indicate no plugging of the screen). Reference PST Test Procedure
x 100 Coupons
x Circulate and condition mud as much as needed to pass the production screen test
x If not passing after first test, call Completion Engineer
15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 4-1/2” Injection Liner (Lower Completion)
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and
run them slick.
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner with slotted liner, the following well control response procedure will be
followed:
x With a slotted joint across the BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover
installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW).
This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
x With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid joint to MU the
TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve.
16.2. Confirm VBR’s have been tested to cover 4-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 4-1/2” injection liner.
x Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt
outside of the surface shoe. This is to mitigate sticking risk while running inner string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
4-1/2” 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump
sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD (Contact OE for set depth)
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
Page 39
Milne Point Unit
M-61 SB Injector
Drilling Procedure
17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i. Note this test must be witnessed by the AOGCC representative.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Pull BPV. Set TWC. Test tree to 5000 psi.
17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
3600 psi or maximum power fluid header pressure. - mgr
Page 40
Milne Point Unit
M-61 SB Injector
Drilling Procedure
19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 12B jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
24/7 manned monitoring on MPU M pad if no surface safety valve while on IA power fluid injection. - mgr
Page 41
Milne Point Unit
M-61 SB Injector
Drilling Procedure
20.0 Doyon 14 Diverter Schematic
Page 42
Milne Point Unit
M-61 SB Injector
Drilling Procedure
21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
Page 43
Milne Point Unit
M-61 SB Injector
Drilling Procedure
22.0 Wellhead Schematic
Page 44
Milne Point Unit
M-61 SB Injector
Drilling Procedure
23.0 Days vs Depth
Page 45
Milne Point Unit
M-61 SB Injector
Drilling Procedure
24.0 Formation Tops & Information
TOP
NAME
TVD
(FT)
TVDss
(FT)
MD
(FT)
Formation
Pressure
(psi)
EMW
(ppg)
Base
Permafrost 1881 1824 2131 827 8.46
SV1 1911 1854 2171 841 8.46
UG4 2163 2106 2506 952 8.46
UG_MB 3443 3386 4070 1515 8.46
SB NB 3745 3688 4610 1648 8.46
SB OA 3894 3837 5302 1713 8.46
Page 46
Milne Point Unit
M-61 SB Injector
Drilling Procedure
L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad)
Page 47
Milne Point Unit
M-61 SB Injector
Drilling Procedure
25.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate
gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates,
but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come
out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching.
Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate
formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud
circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized
mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump
contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x There are no wells with a CF < 1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
Page 48
Milne Point Unit
M-61 SB Injector
Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 49
Milne Point Unit
M-61 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (1) fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
x There are no wells with a clearance factor less than 1.0.
Page 50
Milne Point Unit
M-61 SB Injector
Drilling Procedure
26.0 Doyon 14 Layout
Page 51
Milne Point Unit
M-61 SB Injector
Drilling Procedure
27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 52Milne Point Unit M-61 SB InjectorDrilling Procedure28.0 Doyon 14 Choke Manifold Schematic
Page 53
Milne Point Unit
M-61 SB Injector
Drilling Procedure
29.0 Casing Design
Page 54
Milne Point Unit
M-61 SB Injector
Drilling Procedure
30.0 8-1/2” Hole Section MASP
Page 55
Milne Point Unit
M-61 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 56
Milne Point Unit
M-61 SB Injector
Drilling Procedure
32.0 Surface Plat (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
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07501500225030003750True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750Vertical Section at 333.00° (1500 usft/in)M-61 wp03 tgt2M-61 wp03 tgt4M-61 wp03 tgt6M-61 wp03 tgt8M-61 wp03 tgt10M-61 wp03 tgt11M-61 wp03 tgt13M-61 wp03 tgt15M-61 wp03 tgt179 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006000650070007500800085009000950010000105001100011500120001250013000135001400014287MPU M-61 wp05Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 3.5º/100' : 500' MD, 499.63'TVDStart Dir 4º/100' : 1000' MD, 981.55'TVDStart Dir 4º/100' : 1000' MD, 981.55'TVDEnd Dir : 1535.1' MD, 1433.47' TVDStart Dir 4.25º/100' : 2462.31' MD, 2130.06'TVDEnd Dir : 5209.51' MD, 3889.55' TVDStart Dir 2.5º/100' : 5359.51' MD, 3897.4'TVDBegin GeosteeringEnd Dir : 5455.47' MD, 3900.6' 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-6124.20+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.006027765.65533933.82 70° 29' 12.7783 N 149° 43' 21.5318 WSURVEY PROGRAMDate: 2023-02-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1000.00 MPU M-61 wp05 (MPU M-61) GYD_Quest GWD1000.00 5400.00 MPU M-61 wp05 (MPU M-61) 3_MWD+IFR2+MS+Sag5400.00 14286.32 MPU M-61 wp05 (MPU M-61) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation840.40 782.50 849.04 SV61881.40 1823.50 2131.33 Base Permafrost1911.40 1853.50 2171.26 SV12163.40 2105.50 2506.28 UG43443.40 3385.50 4070.34 UG_MB3745.40 3687.50 4609.95 SB_NB3894.40 3836.50 5302.19 SB_OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-61, True NorthVertical (TVD) Reference:MPU M-61 as staked rkb @ 57.90usftMeasured Depth Reference:MPU M-61 as staked rkb @ 57.90usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Moose PadWell:Plan: MPU M-61Wellbore:MPU M-61Design:MPU M-61 wp05CASING DETAILSTVD TVDSS MD SizeName3899.20 3841.30 5400.00 9-5/8 9 5/8" x 12 1/4"3897.90 3840.00 14286.32 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 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 500.00 6.00 150.00 499.63 -9.06 5.23 3.00 150.00 -10.45 Start Dir 3.5º/100' : 500' MD, 499.63'TVD4 1000.00 23.35 138.67 981.55 -106.85 84.33 3.50 -15.00 -133.49 Start Dir 4º/100' : 1000' MD, 981.55'TVD5 1535.10 41.30 115.96 1433.47 -265.63 315.80 4.00 -44.28 -380.05 End Dir : 1535.1' MD, 1433.47' TVD6 2462.31 41.30 115.96 2130.06 -533.53 865.99 0.00 0.00 -868.53 Start Dir 4.25º/100' : 2462.31' MD, 2130.06'TVD7 5209.51 87.00 338.00 3889.55 861.11 1346.11 4.25 -131.51 156.13 End Dir : 5209.51' MD, 3889.55' TVD8 5359.51 87.00 338.00 3897.40 1000.00 1290.00 0.00 0.00 305.36 Start Dir 2.5º/100' : 5359.51' MD, 3897.4'TVD9 5455.47 89.17 339.02 3900.60 1089.23 1254.87 2.50 25.06 400.81 End Dir : 5455.47' MD, 3900.6' TVD10 5500.01 89.17 339.02 3901.25 1130.82 1238.92 0.00 0.00 445.1111 5785.21 88.60 333.34 3906.79 1391.56 1123.80 2.00 -95.82 729.6912 6035.21 88.60 333.34 3912.90 1614.91 1011.66 0.00 0.00 979.61 M-61 wp03 tgt213 6134.72 86.17 333.89 3917.44 1703.96 967.48 2.50 167.17 1079.0114 6486.44 86.17 333.89 3940.90 2019.10 813.06 0.00 0.00 1429.9115 6640.32 89.25 334.00 3947.05 2157.21 745.53 2.00 1.98 1583.6216 7240.32 89.25 334.00 3954.90 2696.44 482.53 0.00 0.00 2183.48 M-61 wp03 tgt417 7420.56 93.67 334.88 3950.31 2858.95 404.82 2.50 11.28 2363.5518 7500.32 93.67 334.88 3945.21 2931.02 371.03 0.00 0.00 2443.1119 7662.56 89.87 333.46 3940.20 3076.95 300.39 2.50 -159.45 2605.2120 8412.56 89.87 333.46 3941.90 3747.92 -34.72 0.00 0.00 3355.18 M-61 wp03 tgt621 8474.45 88.69 332.46 3942.68 3803.03 -62.85 2.50 -139.77 3417.0622 8958.27 88.69 332.46 3953.75 4231.92 -286.50 0.00 0.00 3900.7323 9016.77 90.09 332.88 3954.37 4283.88 -313.35 2.50 16.67 3959.2324 9316.77 90.09 332.88 3953.90 4550.90 -450.11 0.00 0.00 4259.23 M-61 wp03 tgt825 9535.68 95.53 333.48 3943.17 4745.96 -548.72 2.50 6.28 4477.7926 9903.13 95.53 333.48 3907.76 5073.21 -712.03 0.00 0.00 4843.5227 10063.19 91.53 333.37 3897.91 5216.06 -783.48 2.50 -178.42 5003.2328 10363.19 91.53 333.37 3889.90 5484.14 -917.90 0.00 0.00 5303.12 M-61 wp03 tgt1029 10430.11 89.86 333.37 3889.09 5543.95 -947.89 2.50 179.90 5370.0330 11154.85 89.86 333.37 3890.90 6191.83 -1272.71 0.00 0.00 6094.76 M-61 wp03 tgt1131 11269.85 92.73333.31 3888.30 6294.56 -1324.28 2.50 -1.19 6209.7132 11454.59 92.73333.31 3879.50 6459.44 -1407.16 0.00 0.00 6394.2433 11593.46 89.26 333.37 3877.09 6583.51 -1469.45 2.50 179.06 6533.0634 12043.46 89.26 333.37 3882.90 6985.74 -1671.13 0.00 0.00 6983.01 M-61 wp03 tgt1335 12171.84 86.05 333.25 3888.15 7100.33 -1728.74 2.50 -177.79 7111.2736 12318.23 86.05 333.25 3898.23 7230.74 -1794.49 0.00 0.00 7257.3137 12462.23 89.65 333.39 3903.62 7359.29 -1859.09 2.50 2.29 7401.1938 13162.23 89.65 333.39 3907.90 7985.13 -2172.63 0.00 0.00 8101.16 M-61 wp03 tgt1539 13301.81 93.13 333.19 3904.51 8109.76 -2235.34 2.50 -3.35 8240.6740 13445.82 93.13 333.19 3896.64 8238.09 -2300.20 0.00 0.00 8384.4641 13586.57 89.62 333.38 3893.26 8363.76 -2363.46 2.50 176.83 8525.1542 14286.57 89.62 333.38 3897.90 8989.54 -2677.10 0.00 0.00 9225.12 M-61 wp03 tgt17 Total Depth : 14286.57' MD, 3897.9' TVD
-2250
-1500
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
South(-)/North(+) (1500 usft/in)-6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500
West(-)/East(+) (1500 usft/in)
M-61 wp03 tgt17
M-61 wp03 tgt15
M-61 wp03 tgt13
M-61 wp03 tgt11
M-61 wp03 tgt10
M-61 wp03 tgt8
M-61 wp03 tgt6
M-61 wp03 tgt4
M-61 wp03 tgt2
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
5 0 0
12501750225027503250
3500
3 7 5 0
3 8 9 8
M P U M -6 1 w p 0 5
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 3.5º/100' : 500' MD, 499.63'TVD
Start Dir 4º/100' : 1000' MD, 981.55'TVD
End Dir : 1535.1' MD, 1433.47' TVD
Start Dir 4.25º/100' : 2462.31' MD, 2130.06'TVD
End Dir : 5209.51' MD, 3889.55' TVD
Start Dir 2.5º/100' : 5359.51' MD, 3897.4'TVD
Begin Geosteering
End Dir : 5455.47' MD, 3900.6' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3899.20 3841.30 5400.00 9-5/8 9 5/8" x 12 1/4"
3897.90 3840.00 14286.32 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt Moose Pad
Well: Plan: MPU M-61
Wellbore: MPU M-61
Plan: MPU M-61 wp05
WELL DETAILS: Plan: MPU M-61
24.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6027765.65 533933.82 70° 29' 12.7783 N 149° 43' 21.5318 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU M-61, True North
Vertical (TVD) Reference:MPU M-61 as staked rkb @ 57.90usft
Measured Depth Reference:MPU M-61 as staked rkb @ 57.90usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)MPU M-60 wp05MPU M-12MPU M-14M-07WSW wp02No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU M-61 NAD 1927 (NADCON CONUS)Alaska Zone 0424.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027765.65533933.82 70° 29' 12.7783 N 149° 43' 21.5318 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-61, True NorthVertical (TVD) Reference:MPU M-61 as staked rkb @ 57.90usftMeasured Depth Reference:MPU M-61 as staked rkb @ 57.90usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2023-02-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1000.00 MPU M-61 wp05 (MPU M-61) GYD_Quest GWD1000.00 5400.00 MPU M-61 wp05 (MPU M-61) 3_MWD+IFR2+MS+Sag5400.00 14286.32 MPU M-61 wp05 (MPU M-61) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)MPU M-60 wp05MPU M-28MPU M-12MPU M-35iMPU M-15iMPU M-14MPU M-13MPU M-27M-07WSW wp02GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference33.70 To 14286.57Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-61Wellbore: MPU M-61Plan: MPU M-61 wp05Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3899.20 3841.30 5400.00 9-5/8 9 5/8" x 12 1/4"3897.90 3840.00 14286.32 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500Measured Depth (1000 usft/in)MPU M-60 wp05MPU M-27No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU M-61 NAD 1927 (NADCON CONUS)Alaska Zone 0424.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027765.65 533933.82 70° 29' 12.7783 N 149° 43' 21.5318 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-61, True NorthVertical (TVD) Reference:MPU M-61 as staked rkb @ 57.90usftMeasured Depth Reference:MPU M-61 as staked rkb @ 57.90usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2023-02-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1000.00 MPU M-61 wp05 (MPU M-61) GYD_Quest GWD1000.00 5400.00 MPU M-61 wp05 (MPU M-61) 3_MWD+IFR2+MS+Sag5400.00 14286.32 MPU M-61 wp05 (MPU M-61) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500Measured Depth (1000 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference33.70 To 14286.57Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-61Wellbore: MPU M-61Plan: MPU M-61 wp05Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3899.20 3841.30 5400.00 9-5/8 9 5/8" x 12 1/4"3897.90 3840.00 14286.32 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.
pre-produce
223-042
Milne Point
SCHRADER BLUFF OIL
X
MPU M-61
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT M-61Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230420MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes Surface Location lies within ADL0025514; Top Prod Int & TD lie within ADL0388235.2 Lease number appropriateYes3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by 477, 477.0054 Well located in a defined poolNo Injection well: spacing exception required for pre-production clean up of wellbore. CO in progress.5 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 includedNo9 Operator only affected partyYes10 Operator has appropriate bond in forceNo11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes M-12, M-12PB1, M-20, M-27, M-28, M-6015 All wells within 1/4 mile area of review identified (For service well only)Yes16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 114'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgNo 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsNo 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 has adequate tankage and good trucking support.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches that violate collision scan rules.26 Adequate wellbore separation proposedYes 16" Diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure is 0.44 psi/ft (8.5 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA with MPD appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/10/2023ApprMGRDate7/10/2023ApprSFDDate7/10/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateFaulting: high risk; one crossing expected; see p. 53. Lost Circulation: moderate risk; see p. 50, 53. Wellbore Breathing: some risk; see p. 37.GCW 07/11/2023
