Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Monday, March 17, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Bob Noble
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
R-103
MILNE PT UNIT R-103
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 03/17/2025
R-103
50-029-23799-00-00
224-114-0
W
SPT
3931
2241140 1500
142 143 142 142
111 364 328 299
INITAL P
Bob Noble
1/31/2025
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 R-103
Inspection Date:
Tubing
OA
Packer Depth
464 2212 2164 2145IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitRCN250202083344
BBL Pumped:6.6 BBL Returned:6.6
Monday, March 17, 2025 Page 1 of 1
9
9
9 9
9
9 9
999
9 9
99
9
9
James B. Regg Digitally signed by James B. Regg
Date: 2025.03.17 11:48:33 -08'00'
By James Brooks at 3:07 pm, Jan 02, 2025
Complete
10/26/2024
JSB
RBDMS JSB 010925
GDSR-4/7/25
ES Cementer at 9,115' MD according to Report #42. SFD
Base of 9-5/8" intermediate casing at 11,806' MD according to report #42
5129' FEL SFD
SFD 3/24/2025MGR03OCT2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.01.02 13:50:17 -
09'00'
Sean
McLaughlin
(4311)
Digitally signed by Scott
Pessetto (9864)
DN: cn=Scott Pessetto (9864)
Date: 2025.01.02 14:07:22 -
09'00'
Scott Pessetto
(9864)
_____________________________________________________________________________________
Edited By: JNL 11/1/2024
SCHEMATIC
Milne Point Unit
Well: MPU R-103
Last Completed: 10/26/2024
PTD: 224-114
TD =21,180’(MD) / TD =3,960’(TVD)
4
20”
Orig. KB Elev.: 63.55’ / GL Elev.: 16.8’
9-5/8”
5
8
13-3/8”
1
3
PB1: 3625’ -
11848’
Sacrificed Liner:
4166’ – 5694’
See
Slotted
Liner
Detail
PBTD =21,174’(MD) / PBTD = 3,960’(TVD)
Fish (Cut
Drillpipe, HWDP,
BHA w/ MWD /
GWD / GeoPilot):
5725’ – 6454’
7
5,6
3-1/2”
3
2
9-5/8” ‘ES’
Cementer @
~9,360’
4
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 125’ N/A
13-3/8” Surface 68 / L-80 / CDC 12.415” Surface 3,607’ 0.1497
9-5/8” Intermediate 40 / L-80 / BTC 8.835” Surface 11,797’ 0.0758
5-1/2” Slotted Liner 17 / L-80 / JFE Bear 4.892” 11,594’ 13,286’ 0.0232
4-1/2” Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 13,286’ 21,175’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3# / L-80 / TXP 2.992” Surface 11,614’ 0.0087
OPEN HOLE / CEMENT DETAIL
42” 17 yds Concrete
16" Lead – 1717 sx / Tail – 597 sx
12-1/4” Tail – 1511 sx
8-1/2” Uncemented Slotted Liner
WELL INCLINATION DETAIL
KOP @ 270’
90° Hole Angle = @ 12,127’, Max = 94°
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 13-5/8” 5K bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23799-00-00
Completion Date: 10/26/2024
5-1/2” x 4-1/2” Slotted LINER DETAIL
Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 11842’ 3965’ 13285’ 3942’
4-1/2” 13327’ 3941’ 21134’ 3960’
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 2,515’ X-Nipple, 2.813” 2.813”
2 11,138’ Sliding Sleeve 2.810”
3 11,191’ Zenith Gauge Mandrel 3.953”
4 11,248’ XN Nipple, 2.813” 2.813”
5 11,594’ Locater Sub, 3.5” x 8.25” No Go (bottom of locator spaced out 3.78’) 3.240”
6 11,606’ Bullet Seals – 7” H511 x Mule Shoe 6.160”
Lower Completion
7 11,594’ 9-5/8” SLZXP Liner Top Packer 6.180”
8 21,174’ Shoe
ES Cementer at
9,115' MD according
to report #42
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU R-103 Date:9/9/2024
Csg Size/Wt/Grade:13.375" 68# L-80 BTC/CDC Supervisor:Barber/ Amend
Csg Setting Depth:3,607 TMD 2,270 TVD - Open Hole
Mud Weight:8.95 ppg LOT / FIT Press =380 psi
LOT / FIT =12.17 ppg Hole Depth =3636 md
Fluid Pumped=1.8 Bbls Volume Back =1.8 bbls
Estimated Pump Output:0.0925 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->220 ->5 350
->420 ->10 585
->630 ->15 844
->840 ->20 1083
->10 60 ->25 1331
->12 120 ->30 1589
->14 180 ->35 1883
->16 250 ->40 2116
->18 320 ->45 2373
->20 380 ->50 2652
-> ->53 2808
-> ->
-> ->
-> ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 380 ->0 2808
->1 340 ->1 2806
->2 300 ->2 2804
->3 300 ->3 2802
->4 285 ->4 2802
->5 270 ->5 2802
->6 255 ->10 2801
->7 230 ->15 2801
->8 210 ->20 2800
->9 205 ->25 2799
->10 200 ->30 2799
->12 200 ->
-> ->
-> ->
246 8 10
12
14
16
18
205
10
15
20
25
30
35
40
45
50
53
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 102030405060
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Strokes (# of)
LOT / FIT DATA
380340300300285270255230210205200 200
280828062804280228022802 2801 2801 2800 2799 2799
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 5 10 15 20 25 30
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LOT / FIT DATA
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU R-103 Date:10/16/2024
Csg Size/Wt/Grade:9625" 40# L-80 BTC/CDC Supervisor:Barber/ Carter
Csg Setting Depth:11,797 TMD 3,962 TVD - Open Hole
Mud Weight:8.8 ppg LOT / FIT Press =778 psi
LOT / FIT =12.58 ppg Hole Depth =11826 md
Fluid Pumped=2.3 Bbls Volume Back =2.3 bbls
Estimated Pump Output:0.0925 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->2 117 ->6 240
->4 149 ->10 360
->6 194 ->16 540
->8 240 ->20 660
->10 303 ->26 830
->12 360 ->30 940
->14 425 ->40 1230
->16 481 ->50 1530
->18 545 ->60 1820
->20 602 ->70 2120
->22 674 ->80 2430
->24 747 ->90 2730
->25 778 ->100 3040
-> ->110 3360
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 778 ->0 3360
->1 750 ->1 3310
->2 747 ->2 3310
->3 736 ->3 3300
->4 733 ->4 3290
->5 732 ->5 3290
->6 730 ->10 3280
->7 729 ->15 3270
->8 726 ->20 3260
->9 724 ->25 3260
->10 720 ->30 3260
-> ->
-> ->
-> ->
2 4 6
8
10
12
14
16
18
20
22
2425
6
10
16
20
26
30
40
50
60
70
80
90
100
110
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
0 102030405060708090100110120
Pr
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(
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Strokes (# of)
LOT / FIT DATA
778750747736733732730729726724720
336033103310330032903290 3280 3270 3260 3260 3260
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 5 10 15 20 25 30
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LOT / FIT DATA
ACTIVITYDATE SUMMARY
10/26/2024
WELLHEAD: M/U hanger to string terminated 3/8 CCL into hanger. Landed hanger to
RKB 41.6 RILDS pulled landing joint and set 4" BPV. N/D BOP set CTS plug and N/U
tree, torqued adapter and test void 500 low 5000 high 5/10 mins/good test. PT tree
500 low 5000 high and pulled CTS plug and BPV, well sucured.
10/27/2024
T/I/O=0/0/100 Freeze Protect (New Drill) Pumped 90 bbls of 180* source water
down TBG, capped with 5 bbls 60/40. Final Whps=200/190/220
10/28/2024
T/I/O=0/420/100 Warm upTBG (Post Drill) Pumped 5 bbls 60/40 followed by 90 bbls
of 180* source water freeze protected with 5 bbls 60/40. Final Whps=50/625/240
10/29/2024
*** WELL SHUT-IN ON ARRIVAL.***
LRS PUMP 180bbls PRODUCED WATER DOWN TUBING (Assist slickline).
SHIFT VIKING-SS OPEN AT 11,138' MD W/ 3-1/2" 42BO (Pin untouched).
LRS PUMP 54bbls PRODUCD WATER TO ASSIST W/ OPENING SLEEVE.
LRS PUMP 20bbls 60/40 DOWN TUBING AFTER SLEEVE OPEN.
LRS PUMP 20bbls 60/40 , 60bbls PRODUCED WATER, 10bbls 60/40 DOWN IA.
*** CONTINUE WSRT ON 10-30-24.***
10/29/2024
T/I/O=56/400/100 Assist Slickline. Pumped 234 bbls of 120* produced water down
TBG to assist SL down hole to open sleeve. Freeze protected with 10 bbls 60/40.
Pumped 20 bbls 60/40 followed by 55 bbls produced water down IA, capped with 10
bbls 60/40. Final Whps=600/450/500
10/30/2024
*** CONTINUE WSR FROM 10-29-24.***
LRS ASSIST SLICKLINE W/ 290bbls PRODUCED WATER DOWN TUBING AT
2bpm.
ATTEMPT TO SET 3-1/2" JETPUMP IN VIKING-SS AT 11,138' MD (See log).
LRS ASSIST SLICKLINE W/ 500bbls PRODUCED WATER DOWN TUBING AT
2bpm.
ATTEMPT TO SET 3-1/2" JETPUMP IN VIKING-SS AT 11,138' MD (See log).
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.***
10/30/2024
T/I/O=0/0/32 Assist Slickline. Pumped 787 bbls of 130* produced water down TBG to
assist SL down hole. Freeze protected TBG with a total of 25 bbls 60/40. Pumped 20
bbls 60/40 down IA. Final Whps=400/380/480
10/31/2024
LRS CTU #1 - 1.50" Duracoil Job Objective: Set Jet Pump
MIRU. Spot equipment. Wait on well support to finish rig up/PT and tools to arrive.
Make up MHA and PT.
***Job Continued on 1-Nov-2024***
11/1/2024 Freeze Protect IA, Pumped 280 bbls criesel down IA
Daily Report of Well Operations
MPU R-103
Daily Report of Well Operations
MPU R-103
11/1/2024
LRS CTU #1 - 1.50" Dura coil. Job Objective: Set Jet pump
***Job continued from 31-Oct-2024***
Continue making up tools. NU and function test BOPs. Make up Baker tools w/ x-
line running tool and 12B jet pump. RIH and locate on Nipple @ 11138' MD. Stack
weight and pump diesel down coil taking return to OT to fire hipp-tripper. Beat down
for 20 mins and then jar down. Overpull 13k before shearing pin and then reconfirm
tag at 11138 with 8k down. Jet pump set in VCT sliding sleeve at 11138 MD. POOH
and Freeze protect tubing to 2500' TVD with 60/40 Methanol. X-line functioned as
expected, left one 1/4" pin nubbin in the hole. Rig down CTU.
***Job Complete***
11/2/2024
MPU Well Support set foundation and tied well into process as a sundried Producer.
2" hardline on PF and 3" to Test/Production. Serviced wellhead and PT'd all lines. No
issues
12/2/2024 Well Support Techs freeze protected hardline post S/D for the 30 day flowback.
12/3/2024
Freeze Protect Post Flowback, Pumped 290 bbls criesel and 35 bbls diesel down IA,
Pumped 44 bbls diesel down Tubing
12/6/2024
Well Support Techs R/D 30 day flow back piping, installed new injection pipng and
pressure tested piping to 3650 psi.
No issuses
12/31/2024
CTU#1 1.75" CT. Job Scope: Pull Jet Pump / Close Sld Slv
MIRU CTU. Function Test BOP's. Pressure Test PCE 250psi Low / 3500psi High.
RIH w/ 3" G-Spear Fishing BHA. Tag 12B rev circ jet pump @ 11,123' CTM /
11,138' MD.
***Continue on WSR 1/1/25***
12/31/2024 Fluid Support CTU 100 bbls 60/40 12/29 thru 12/31
1/1/2025
CTU#1 1.75" CT. Job Scope: Pull Jet Pump / Close Sld Slv
Latch 12B rev circ jet pump @ 11,138' MD. POOH. Recovered 12B rev jet pump.
BD BOT 3" GS Spear BHA. PT MHA. MU BOT HB-2 Shifting Tool BHA. RIH Pump
spear 60/40 down IA. Pump Corr Inhibitor Conqor 303A down IA 415 bbls. Diesel
down IA FP 324 bbls. Shift sliding sleeve. Pressure up IA to verify close. MIT-IA to
2132 psi - PASS (see data tab). Blow down Coil. RDMO. Unit to Maint & Pipe swap.
***Job Complete***
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/8 &'! !&6 -
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%- &!%!
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%.!&!8 .&66 -
-% & / ?@AB ?,0.3
%6/&8 8!&6 ! .&/- !
-!8& % 6
-!.&8. 8
/%8& !!
8/6&' %
!8
//&-' '!
'6'&66 .&8.
'.&-/ ?@AB ?,0.3
/6.& 8!&%. ! !& 6 !
-68&/. 6
-8!&8 8
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!8
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6%%&'% &66
6%&%' ?@AB ?,0.3
8 8&%% 8'&% ! .& ! !
-''&- '
.6&- 8
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8-.&!% %
!8
.%-&.' '!
6 .& % .&-
...&86 ?@AB ?,0.3
868& 8'&% ! .& ! !
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-!'&% !
8-6&% %
!8
.86&%/ '!
!//&! &
.'.& - )C1*1*
" D> " D
D
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/05/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241217
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF
BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT
BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF
BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF
BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF
HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT
KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF
KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting
KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf
KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL
MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF
MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL
MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement
MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf
PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL
PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM
PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM
PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN
PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM
PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN
PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN
PBU L3-22A 50029216630100 219051 10/9/2024 BAKER
PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF
PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF
SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF
Please include current contact information if different from above.
T39863
T39864
T39865
T39868
T39869
T39870
T39871
T39872
T39873
T39875
T39874
T39867
T39866
T39876
T39877
T39880
T39878
T39879
T39881
T39882
T39883
T39884
T39885
T39886
T39887
MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.12.18 08:35:44 -09'00'
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
Hilrmrp al;uka, LIX E-mail: david.douglas@hilcorp.com
Date: 11/08/2024
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
RECEIVED
DATA TRANSMITTAL NOV 0 8 2024
MPU R-103PB1 AOGCC
- PTD 224-114
- API 50-029-23799-70-00
Washed and Dried Well Samples (10/13/2024)
Sampling Frequency: 10', 30', 45' Intervals
6 Boxes Total
WELL
BOX
SAMPLE INTERVAL (FEET J MD)
MPU R-103PB1
BOX 1 OF 6
3616 - 5170' MD
MPU R-103PB1
BOX 2 OF 6
5170' - 6625' MD
MPU R-103PB1
BOX 3 OF 6
6625' - 8170' MD
MPU R-103PB1
BOX 4 OF 6
8170' - 9880' MD
MPU R-103PB1
BOX 5 OF 6
9880' - 11290' MD
MPU R-103PB1
I BOX 6 OF 6
11290' - 11848' MD
Please include current contact information if different from above.
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422
Received y: Date:
12- Y 1eBD&l_S
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
Date: 11/07/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: MPU R-103PB1
PTD: 224-114
API: 50-029-23799-70-00
MUDLOGS - EOW DRILLING REPORTS (09/09/2024 to 09/13/2023)
1. FINAL EOW REPORT
2. SHOW REPORTS
3. DIGITAL DATA (LAS)
4. SAMPLE PICTURES
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – EMF, CGM, TIFF AND PDF FORMATS)
Formation Evaluation Logs
Show Logs
Gas Ratio Logs
Drilling Evaluation Logs
SFTP Transfer - Main Folder Contents:
Please include current contact information if different from above.
224-114
T39753
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 11/07/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU R-103 + PB1
PTD: 224-114
API: 50-029-23799-00-00 (MPU R-103)
API: 50-029-23799-70-00 (MPU R-103PB1)
FINAL LWD FORMATION EVALUATION + GEOSTEERING (09/02/2024 to 10/20/2024)
ROP, BaseStar & ABG Gamma, ResiStar & StrataStar Resistivity, Horizontal Presentation
(2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
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.
T39751
T39752
t I rAe Po,
Regg, James B (OGQ
From: Brett Anderson - (C) <Brett.Anderson@hilcorp.com>
Sent: Saturday, October 26, 2024 9:17 AM
To: Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace,
Chris D (OGC)
Cc: Frank Roach; Nathan Sperry; Taylor Wellman; Oliver Amend - (C)
Subject: 10-426 for MPU R-103 MIT -IA 10/26/24
Attachments: MIT MPU R-103 10-26-24.xlsx
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.
Please see attached Form 10-426 for MPU R-103 MIT -IA. ✓
Brett Anderson
Hilcorp DSM, Parker 273
Office: 907-659-5673
Mobile: 907-240-6258
4rett and.erson@hi.lcgrp.,_cam
Alternate: Shane Barber
sbarber@h lcorp.com
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, k 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.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
Submit to: iim.reac0alaskagov; AOGCC.Inspectorstilialaska_pov. phoebe. bmokstaalaske.gov
OPERATOR:
Hilcom Alaska
FIELD / UNIT / PAD:
MPU R-103 ✓
DATE:
10/28R4
OPERATOR REP:
Brett Anderson
AOGCC REP:
3vi
Wall
R-103
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min,
PTD
2241140
Typelnj
W �
Tubing
0 —
0
0
0
Type Test
P
Packer TVD
3933 1
BBL Pump 1
9.4 -
IA
0
1 3585 /1
3547
3539
Interval
1
Test psi
3500
BBL Retum
93 '1
0
1 0 1
0
1 0
Result
P
Notes:
9-518- Casing x 3-12' Upper Completion with T' Seal Assembly at 11.594' MO 3933' TVD. OMIT to 3500psi as per PTD. Witness Waived by Kam Si 10-24-2417:02
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Typelnj
Tubing
Type Test
Packei
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min,
PTD
Typelnj
Tubing
Type Test
Packer WO
BEPump
IA
Interval
Test psi
BBL Return
OA
Result
N411s:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Tesl
Packer TVD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Typelnj
Tubing
Type Test
Packer TVO
BBL Pump
IA
Interval
Test psi
BBL Retuml
I OA
I
I
Result
Notes:
Wall
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Typelnj
Tubing
Type Test
Packer TVD
BBL Pump
IA
IInterval
Test psi
BBL Retu.1
I OA
I
I
I
IResult
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Typelnj
Tubing
Type Test
Packer TVD
BBL Pump
IA
Interval
Test psi
BBL Retuml
I OA
I
I
I
Result
Ni
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Typa lnl
Tubing
Type Test
Paper TVD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Ni
TYPE INJ Codes
TYPE TEST Lodes
INTERVALCoees
Result Ca4as
W•Water
P=Pressure TM
I=Initial Teal
P=Paw
G=Gas
0= 0ther(descriM in Noted
G=Four Year Cycle
F=Fail
5=51uny
V=RtyNrN by Variari
1=tnconclusive
t= Ind atel Wavawaier
o =Other (reserve In noes)
N= not nlei
Form 10426 (Revised 01Y4017)
MIT MPU R-10310-26-24
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT R-103
JBR 12/13/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
3-1/2" & 5" joints. HCR Kill-Fail. Replaced & passed non-witnessed R/T.
Test Results
TEST DATA
Rig Rep:Davis/EnfieldOperator:Hilcorp Alaska, LLC Operator Rep:Barber/Carter
Rig Owner/Rig No.:Parker 273 PTD#:2241140 DATE:10/12/2024
Type Operation:DRILL Annular:
250/3000Type Test:BIWKLY
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSAM241013183006
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7.5
MASP:
1334
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 1 P
FSV Misc 0 NA
15 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"x5"P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"F
Kill Line Valves 2 2-1/16"&3-1/P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P2000
200 PSI Attained P17
Full Pressure Attained P56
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P14@2500
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P22
#1 Rams P6
#2 Rams P6
#3 Rams P6
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9999
9
9
9
9
HCR Kill-Fail.
F
BOPE Test – Parker 273
Non-Witnessed Retest – HCR Valve
MPU R-103; PTD 2241140
AOGCC Insp# bopSAM241013183006
10/12/2024
Non-Witnessed Retest –HCR Valve
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/04/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241004
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BRU 214-13 50283201870000 222117 9/26/2024 AK E-LINE Perf
END 2-72 50029237810000 224016 8/26/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON RBT
MPI 2-16 50029218850000 188134 9/9/2024 AK E-LINE Perf
MPI 2-16 50029218850000 188134 9/20/2024 AK E-LINE Perf
MPU B-16 50029213840000 185149 9/28/2024 READ CaliperSurvey
MPU B-24 50029226420000 196009 8/20/2024 HALLIBURTON PERF
MPU B-28 50029235660000 216027 9/28/2024 HALLIBURTON TUBINGCUT
MPU I-01 50029220650000 190090 8/17/2024 HALLIBURTON PERF
MPU R-103 50029237990000 224114 9/20/2024 AK E-LINE Hoist
MRU M-02 50733203890000 187061 9/23/2024 AK E-LINE Perf
PBU 02-21B 50029207810200 211033 9/30/2024 HALLIBURTON RBT
PBU L2-10 50029217460000 187085 8/23/2024 HALLIBURTON RBT
PBU L-212 50029232520000 205030 9/24/2024 HALLIBURTON IPROF
PBU L-254 50029237520000 223030 9/20/2024 HALLIBURTON IPROF
PBU P1-17 50029223580000 193051 9/7/2024 HALLIBURTON RBT
PBU S-09A 50029207710100 214097 8/21/2024 HALLIBURTON RBT
PBU Z-235 50029237600000 223055 9/19/2024 HALLIBURTON IPROF
Please include current contact information if different from above.
T39619
T39620
T39620
T39620
T39621
T39621
T39622
T39623
T39624
T39625
T39626
T39627
T39628
T39629
T39630
T39631
T39632
T39633
T39634
MPU R-103 50029237990000 224114 9/20/2024 AK E-LINE Hoist
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.10.04 15:10:24 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 9/27/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240927
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF
BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF
BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf
BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL
BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL
END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey
KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF
MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey
MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey
MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut
MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut
MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug
NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL
NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF
NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog
PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch
PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL
PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF
PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL
PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL
PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF
Please include current contact information if different from above.
T39593
T39594
T39595
T39596
T39597
T39598
T39599
T39600
T39601
T39602
T39603
T39603
T39604
T39605
T39605
T39605
T39605
T39606
T39606
T39607
T39608
T39609
T39609
T39610
T39611
MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut
MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.27 14:47:28 -08'00'
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU R-103
Hilcorp Alaska, LLC
Permit to Drill Number: 224-114
Surface Location: 5129' FSL, 4240' FEL, Sec 07, T13N, R10E, UM, AK
Bottomhole Location: 485' FNL, 87' FWL, Sec 34, T14N, R09E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
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. Spacing
Exception granted in CO477A.003 Amended.
All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample
intervals from below the permafrost or from where samples are first caught and 10-foot sample
intervals through target zones. Collect samples from intermediate hole section.
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: mud log (for intermediate hole section).
Mudlogging intervals: for sections of high-drill rate, collect samples as closely as practical
(adhering to safety practices at all times to ensure the well-being of the mud logging crew)
decreasing to 50-foot samples when the drill rate makes that interval safe and practical,
decreasing again to 30-foot intervals when safe and practical, and then 10-foot samples through
the uppermost OA. See attached emails for details.
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,
Jessie L. Chmielowski
Commissioner
DATED this 29th day of August 2024.
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2024.08.29
09:52:32 -08'00'
Drilling Manager
08/16/24
Monty M
Myers
By Grace Christianson at 2:38 pm, Aug 16, 2024
* BOPE test to 3000 psi. Annular to 2500 psi.
* CMIT TxIA to 3500 psi. 24 hour notice to AOGCC for opportunity to witness.
* Variance to 20 AAC 25.412 (d) approved . CBL will not be required with evidence
of good cement returns during cementing of 9-5/8" casing.
* Approved for 30 days of preproduction with jet pump.
Mudlog and cuttings samples required for intermediate hole section.
A.Dewhurst 26AUG24
50-029-23799-00-00
DSR-8/21/24
224-114
* MIT-IA to 2000 psi after 5 days of stabilized injection post 30 day pre-production. 24 hour notice of state to witness.
MGR28AUG2024*&:
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.08.29 09:53:05 -08'00'08/29/24
RBDMS JSB 083024
Purple cylinderrepresents areawithin ¼ mile radiusof proposed R-103injectorPrognosed TopSchrader (R-103)OP 05-06 (TopSchrader)Proposed TD(within Sec 34)As drilled R-101Top OA (heel)Future producersand injectorsdrilled downdip(approx. 400’spacing)
PTD API WELL STATUS
Top of SB
OA (MD)
Top of SB
OA
(TVDss)
Top of
Cement
(MD)
Top of
Cement
(TVDss)
Schrader OA
status Zonal Isolation
224-078 50-029-23793-00-00 MPU R-101 Active Injector- Schrader 12242 -3823 9840 -3340 Open TOC confirmed with CBL on 7/16/2024
223-040 50-029-23755-00-00 MPU M-60 Active Producer- Schrader 5916 -3871 Surface Surface Open
Stg 1 cement on 7/3/2023. 41 bbls cement circulated above stage tool @ 2,416' MD
(2,000' TVD).
Stg 2 cement on 7/3/2023. 247 bbls cement returned to surface.
Squeezed 60 bbls across stage tool on 7/6/2023
Installed expandable patch over stage tool on 7/17-18/2023
224-096 50-029-23796-00-00 R-102 In Progress Producer - Schrader 12201 -3863 TBD TBD TD 12-1/4" drilling interval on 8/13/24. Cleaning out for casing run as of 8/16/24.
TBD TBD Future R-104
TBD TBD Future R-105
TBD TBD Future R-106
Area of Review MPU R-103 SB OA
Milne Point Unit
(MPU) R-103
Drilling Program
Version 0
8/9/2024
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 16” Hole Section ............................................................................................................. 14
12.0 Run 13-3/8” Surface Casing ................................................................................................... 17
13.0 Cement 13-3/8” Surface Casing .............................................................................................. 20
14.0 N/U BOP and Test................................................................................................................... 23
15.0 Drill 12-1/4” Hole Section ....................................................................................................... 24
16.0 Run 9-5/8” Intermediate Casing ............................................................................................. 28
17.0 Cement 9-5/8” Intermediate Casing ....................................................................................... 33
18.0 Drill 8-1/2” Hole Section ......................................................................................................... 37
19.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ..................................................... 42
20.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................ 47
21.0 RDMO ..................................................................................................................................... 48
22.0 Post-Rig Work ........................................................................................................................ 49
23.0 Parker 273 Diverter Schematic .............................................................................................. 50
24.0 Parker 273 BOP Schematic .................................................................................................... 51
25.0 Wellhead Schematic ................................................................................................................ 52
26.0 Days vs Depth .......................................................................................................................... 53
27.0 Formation Tops & Information.............................................................................................. 54
28.0 Anticipated Drilling Hazards ................................................................................................. 57
29.0 Parker 273 Layout .................................................................................................................. 62
30.0 FIT Procedure ......................................................................................................................... 63
31.0 Parker 273 Choke Manifold Schematic.................................................................................. 64
32.0 Casing Design .......................................................................................................................... 65
33.0 12-1/4” Hole Section MASP .................................................................................................... 66
34.0 8-1/2” Hole Section MASP ...................................................................................................... 67
35.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 68
36.0 Surface Plat (As-Built) (NAD 27) ........................................................................................... 69
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1.0 Well Summary
Well MPU R-103
Pad Milne Point “R” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Oa Sand
Planned Well TD, MD / TVD 21,142’ MD / 3,974’ TVD
PBTD, MD / TVD 21,142’ MD / 3,974’ TVD
Surface Location (Governmental) 5,129' FSL, 4,240' FEL, Sec. 07, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 540,339.26 Y=6,033,293.28
Top of Productive Horizon
(Governmental)455' FNL, 2,637' FEL, Sec 2, T13N, R9E, UM, AK
TPH Location (NAD 27) X= 531,473.00 Y= 6,038,225.00
BHL (Governmental) 485' FNL, 87' FWL, Sec 34, T14N, R9E, UM, AK
BHL (NAD 27) X= 523,610.00 Y= 6,043,445.00
AFE Drilling Days 30 days
AFE Completion Days 5 days
Maximum Anticipated Pressure
(Surface) 1334 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1726 psig
Work String 5” 19.5# S-135 XT-50
KB Elevation above MSL: 46.95 ft + 16.8 ft = 63.75 ft
GL Elevation above MSL: 16.8 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
16” 13-3/8” 12.415” 12.259” 14.375” 68 L-80 CDC 5,020 2,260 1,556
12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 BTC 5,750 3,090 916
8-1/2” 5-1/2” 4.892” 4.767” 6.050” 17 L-80 JFE Bear 7,740 6,290 397
8-1/2” 4-1/2” 3.960”3.795” 4.714” 13.5 L-80
H625 9020 8540 279
Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.500” 6.500” 19.5 S-135 XT50 44,000 52,800 712klb
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.com,
frank.roach@hilcorp.com,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 mmyers@hilcorp.com,frank.roach@hilcorp.com,
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,
frank.roach@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 Frank Roach 907.777.8413 Frank.roach@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Taylor Wellman 907.777.8449 twellman@hilcorp.com
Geologist Graham Emerson 907.564.5242 graham.emerson@hilcorp.com
Reservoir Engineer Alan Abel 907.564.4621 alan.abel@hilcorp.com
Drilling Env. Coordinator Adrian Kersten 907.564.4820 adrian.kersten@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 R-103 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. R-103 is part of a
multi well development program targeting the Schrader Bluff sand on R-pad. Hilcorp requests to pre-
produce R-103 for up to 30 days.
The directional plan is a horizontal well with 16” surface hole with 13-3/8” surface casing set in the SV1. A
12-1/4” intermediate hole with 9-5/8” intermediate casing set into the top of the Schrader Bluff sand. An 8-
1/2” lateral section will be drilled. An injection liner will be run in the open hole section.
The Parker 273 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately September 6th, 2024, pending rig schedule.
Surface casing will be run to ~4,116’ MD / 2,278’ TVD and cemented to surface. 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 Parker 273 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 16” surface hole to TD of surface hole section. Run and cement 13-3/8” surface casing
4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 12-1/4” hole to TD of intermediate hole section. Run and cement 9-5/8” surface casing
6. Drill 8-1/2” lateral to well TD.
7. Run 5-1/2” x 4-1/2” injection liner.
8. Run 3-1/2” tubing.
9. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface Hole: No mud logging. On Site geologist. LWD: GR + Res
2. Intermediate Hole: No mud logging. On Site geologist. LWD: GR + Res
3. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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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 R-103.
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 a variance to 20 AAC 25.412 (d): “The operator shall provide a cement quality log or
other well data approved by the commission to demonstrate isolation of the injected fluids to the approved
interval.” Hilcorp is requesting approval to use cement circulated to surface as “other well data” to show
isolation.
x The 9-5/8” intermediate casing will have a stage tool placed at least 250’ TVD above the top of the
Schrader Pool to satisfy 20 AAC 25.030. (d)(6).
x The cement job is planned for TOC at 500’ above the stage tool depth.
x After cement is placed and plugs bumped, the stage tool will be opened and circulation to surface will
begin.
x Cement returns to surface during this circulation will indicate cement to the stage tool.
2) Hilcorp is requesting approval for a test period of pre-producing R-103 for up to 30 days via a forward
circulating jet pump completion. This will allow us to measure skin and evaluate the benefits of pre-
producing our injectors in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is
online and producing. Section 19 details the steps required to make this happen. Note also that the MIT-IA
has been changed from 2,000 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
12-1/4”
x 13-5/8” x 5M Annular BOP
x 13-5/8” x Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3-1/8” x 5M side outlets
x 13-5/8” x Single ram
x 3” x 5M Choke Line
x 2” x 5M Kill line
x 3” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Annular: 250/2500
Subsequent Tests:
250/3000
Annular 250/2500
8-1/2”
x 13-5/8” x 5M Annular BOP
x 13-5/8” x Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3-1/8” x 5M side outlets
x 13-5/8” x Single ram
x 3” x 5M Choke Line
x 2” x 5M Kill line
x 3” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Annular: 250/2500
Subsequent Tests:
250/3000
Annular 250/2500
Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven
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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Drilling Procedure
9.0 R/U and Preparatory Work
9.1 R-103 will utilize a newly set 20” conductor on R-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 Parker 273. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL BE USED on the intermediate hole section.
9.9 Mix spud mud for 16” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 5-3/4” liners in mud pumps.
x NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96%
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 20” riser to BOP Deck
x N/U 20”, 5M diverter “T”.
x NU 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
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 16” Hole Section
11.1 P/U 16” 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 1,500’ or MWD surveys clean up, whichever is deeper.
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 16” hole section to section TD, in the SV1. Confirm this setting depth with the Geologist
and Drilling Engineer while drilling the well.
x Efforts should be made to minimize dog legs in the surface hole. Do not exceed 6 deg / 100.
If a DLS > 6 deg / 100 is measured, immediately backream stand to knock down severity.
x Do not exceed 80° inclination in interval. If survey shows inc > 80°, immediately backream
stand to knock down inclination.
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 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. Mud rheology is
the primary method of transporting cuttings.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm, staying between 400 and 450 gpm through the permafrost. Monitor
shakers closely to ensure shaker screens and return lines can handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increases 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).
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x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up or after 1,500’ (whichever is deeper).
x Gas hydrates have not been seen on pads adjacent to R-Pad (F-Pad and L-Pad). However, be
prepared for them. In MPU they have been encountered typically around 2100’-2400’ TVD
(just below permafrost). Be prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
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: All wells have a clearance factor greater than 1.0 in the surface interval.
16” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional barite
or spike fluid will be on location to weight up the active system (1) ppg above highest
anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with
9.2+ ppg.
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate zone
x PVT System: MD Totco PVT will be used throughout the drilling and completion phase.
Remote monitoring stations will be available at the driller’s console, Co Man office,
Toolpusher office, and mud loggers office.
x Rheology: MI-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: PolyPac Supreme UL should be used for filtrate control. Background LCM (10
ppb total) can be used in the system while drilling the surface interval to prevent losses and
strengthen the wellbore.
x Wellbore and mud stability:Additions of SKREENKLEEN 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 BUSAN 1060 MUST be made to
control bacterial action.
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Drilling Procedure
x Casing Running:Reduce system YP with DESCO and SAPP as required for running casing
as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check
with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated MI-Gel/freshwater spud mud
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –9.8 75-300 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation:Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.5 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.6 TOOH and LD BHA
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Drilling Procedure
12.0 Run 13-3/8” Surface Casing
16.1 R/U Parker Wellbore 13-3/8” casing running equipment (CRT & Tongs)
x Ensure 13-3/8” CDC x XT50 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 12-1/4” on the location prior to running.
x Note that 68# drift is 12.259”
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.
16.2 P/U shoe joint, visually verify no debris inside joint.
16.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
13-3/8” Float Shoe
1 joint – 13-3/8” CDC, 2 Centralizers 10’ from each end w/ stop rings
1 joint –13-3/8” CDC, 1 Centralizer mid joint w/ stop ring
1 joint – 13-3/8” CDC, 1 Centralizer mid joint w/ stop ring
13-3/8” Float Collar
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
16.4 Continue running 13-3/8” 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 ~ 2500’ MD from shoe
x 1 centralizer every other joint to ~200’ below surface
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.
13-3/8” 68# L-80 CDC Make-Up Torques:
Casing OD Minimum Maximum Yield
13-3/8” 17,000 ft-lbs 21,000 ft-lbs 73,900 ft-lbs
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16.5 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
16.6 Slow in and out of slips.
16.7 P/U landing joint/hanger assembly 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.
16.8 Lower casing and land hanger on landing ring to confirm depth. Confirm measurements.
16.9 Have emergency slips staged in cellar along with all necessary equipment for the contingency
operation.
16.10 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 13-3/8” Surface Casing
17.1 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.
17.2 Document efficiency of all possible displacement pumps prior to cement job.
17.3 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.
17.4 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.
17.5 Fill surface cement lines with water and pressure test.
17.6 Drop first bottom plug – HEC rep to witness. Pump spacer.
17.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below
calculations, confirm actual cement volumes with cementer after TD is reached.
17.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations,
confirm actual cement volumes with cementer after TD is reached.
x Cement volume based on annular volume + open hole excess (300% for lead above base
permafrost and 40% for all cement below base permafrost). Job will consist of lead & tail, TOC
brought to surface.
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Estimated Total Cement Volume:
Cement Slurry Design:
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 – HEC rep to witness, 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.
13.11 Displacement calculation is in the Stage 1 Table in step 13.7.
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.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 11.0 lb/gal 15.8 lb/gal
Yield 2.54 ft3/sk 1.16 ft3/sk
Mix Water 12.22 gal/sk 4.95 gal/sk
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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.
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 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 diverter stack that may have come in
contact with the cement.
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 frank.roach@hilcorp.com,
nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com This will be included with the EOW
documentation that goes to the AOGCC.
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14.0 N/U BOP and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 13-5/8” 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 or 5” solid body rams 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 HCR outside of the manual
valve
14.3 Install 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 LSND fluid for production hole. Ensure LSND mud weight matches the weight at TD of
surface 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 5-3/4” liners in mud pumps.
14.11 Rig up Halliburton mud logging unit. Unit will be used during the 12-1/4” intermediate hole
section.
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15.0 Drill 12-1/4” Hole Section
15.1 M/U 12-1/4” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 12-1/4” cleanout BHA to float equipment. Note depth TOC tagged on AM report.
15.3 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 = 5020 / 2 = ~2510 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.
15.4 Drill out shoe track and 20’ of new formation.
15.5 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.6 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as the casing
test. Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 10.6 ppg FIT is the minimum
required to drill ahead
x 10.6 ppg provides >25 bbls based on 9.2 ppg MW, 8.46 ppg PP (swabbed kick at 9.2 ppg
BHP)
15.7 POOH & LD Cleanout BHA
15.8 P/U 12-1/4” 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 Ensure GWD is included in the BHA
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135 XT50.
x Run a non-ported float in the production hole section.
Email casing test and FIT digital data to AOGCC upon completion of FIT.
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15.9 12-1/4” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite will be on location to weight up the active system (1) ppg above highest anticipated
MW.
x Solids Concentration: 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 reasonably low. Utilize sweeps (weighted, high
vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 12 (~hole diameter)
for sufficient hole cleaning
x Run the centrifuge as needed while drilling the intermediate 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 LSND drilling fluid
Properties:
Interval Density PV YP API FL Total Solids MBT Hardness
Intermediate 8.9-9.5 5-20 - ALAP 15 - 30 <8 <10% <8 <200
System Formulation:
Product- intermediate Size Pkg ppb or (% liquids)
Soda Ash 50 lb sx 0.17
PowerVIS 25 lb sx 1.5 –2.0
M-I Pac UL 50 lb sx 3.0
Hydrahib/Kla-Stop 55 gal dm 1.0 –1.5
KCl 50 lb sx 10.7
SCREENKLEEN 55 gal dm 0.25
M-I Wate 50 lb sx 56 (as needed for wt)
Busan 1060 55 gal dm 2.1
15.10 TIH with 12-1/4” directional assembly to bottom
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15.11 Displace wellbore to 8.9 ppg LSND drilling fluid
15.12 Begin drilling 12-1/4” 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 12-1/4” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 700-900 gpm, target min. AV’s 148 ft/min, 750 gpm
x RPM: 120+
x Utilize GWD surveys for entire 12-1/4” hole section
x Efforts should be made to minimize dog legs in the intermediate hole.
x Keep any directional work to DLS < 3 deg / 100. Any doglegs over 3 deg / 100 need to be
addressed before drilling ahead.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Mud rheology is
the primary method of transporting cuttings.
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 sands for any extended period of time.
x Limit maximum instantaneous ROP to < 250 fph. The formations will drill faster than this,
but when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
x A/C: All wells have a clearance factor greater than 1.0 in the intermediate interval.
15.15 At TD, CBU (minimum 5-7X, more if needed) at max rate 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
15.16 BROOH with the drilling assembly to the 13-3/8” casing shoe.
x Circulate at full drill rate unless losses are seen.
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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 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.
15.17 CBU minimum two times at 13-3/8” shoe and clean casing with high vis sweeps.
15.18 Monitor well for flow.
15.19 POOH and LD BHA
15.20 Change upper rams from 2-7/8” x 5” VBRs to 9-5/8” casing rams and test to 250 psi low, 3,000
psi high for 5/5 minutes with 9-5/8” test joint.
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16.0 Run 9-5/8” Intermediate Casing
16.1 R/U Parker Wellbore 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” BTC x XT50 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 40# drift is 8.679”
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.
16.2 P/U shoe joint, visually verify no debris inside joint.
16.3 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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16.4 Float equipment and Stage tool equipment drawings:
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16.5 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 ES Cementer
x 1 centralizer every joint from ES Cementer to 1,000’ above ES Cementer
x 1 centralizer every 2 joints from 1,000’ above ES Cementer to 13-3/8” shoe
x Verify depth of pool 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.
16.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 345’ TVD above
the SB_Na.
x Stage tool needs to be a minimum of 250’ TVD above top of pool to confirm cement
isolation for an injector. 345’ TVD covers top of pool from the SB_Na, plus >250’ TVD.
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 BTC Make-Up Torques - Make up to Mark 10 jts Take Average:
Casing OD Optimum
9-5/8” To Mark
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16.7 Continue running 9-5/8” surface casing
x Centralizers:
o 1 centralizer every joint to 1,000’ above ES Cementer
o 1 centralizer every 2 joints from 1,000’ above ES Cementer to 13-3/8” shoe
o Ensure 13-3/8” shoe is free of centralizers
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.
16.8 CBU at 13-3/8” shoe, prior to entering open hole.
16.9 Continue to RIH with 9-5/8” intermediate casing to TD. Break circulation every 5 joints and
wash down. Take special care when staging pumps up and down to avoid surging and breaking
down the formation.
16.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
16.11 Slow in and out of slips.
16.12 P/U landing joint/hanger assembly 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.
16.13 Lower casing and land hanger to confirm depth. Confirm measurements.
16.14 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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17.0 Cement 9-5/8” Intermediate Casing
17.1 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.
17.2 Document efficiency of all possible displacement pumps prior to cement job.
17.3 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.
17.4 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.
17.5 Fill surface cement lines with water and pressure test.
17.6 Pump remaining spacer.
17.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations, confirm actual cement volumes with cementer after TD is reached.
x Cement volume based on annular volume + 65% open hole excess. Job will consist of tail
cement, TOC brought to ~500’ MD above stage tool.
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Estimated Total Cement Volume:
Cement Slurry Design:
17.8 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, land hanger
on profile, and continue with the cement job.
17.9 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting spacer 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.
17.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
17.11 Displacement calculation is in the Stage 1 Table in step 17.7.
At least 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
17.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job.
17.13 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.
17.14 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
Tail Slurry
System HalCem
Density 15.8 lb/gal
Yield 1.16 ft3/sk
Mix Water 4.98 gal/sk
0.0758
928.5 - mgr
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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.
17.15 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU 2-3x and record any spacer or cement
returns to surface and volume pumped to see the returns. NOTE: Cement returns are needed to
confirm TOC is to the stage tool. This is to show isolation of injection interval.
17.16 Be prepared for cement returns to surface. Dump cement returns through 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 come in contact with cement returns.
17.17 After circulating out cement, drop ES Cementer closing plug and displace with mud out of mud
pits.
17.18 Monitor returns closely while displacing closing plug. Adjust pump rate if necessary. Have
black water available to retard setting of any trailing cement stringers.
17.19 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.
17.20 Back off and LD landing joint. Install packoff and test per wellhead tech.
17.21 Freeze protect 13-3/8” x 9-5/8” casing annulus to ~2,500’ MD with dead crude or diesel after
cement tests indicate cement has reached 500 psi compressive strength.
x Freeze protect with ~150 bbls of dead crude/diesel
x Establish breakdown pressure and inject 5 bbls past breakdown to confirm annulus is clear
x Ensure total injection volume injected down the annulus (including mud used to keep
annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume.
17.22 Change upper rams from 9-5/8” casing rams to 2-7/8” x 5” VBRs and test to 250 psi low, 3,000
psi high with 3-1/2” and 5” test joints.
17.23 Rig down Halliburton mud logging unit.
17.24 NOTE:If cement returns were not observed in the circulation on step 17.15, a cement evaluation
log will be required to meet State regulations for an injector. A tractor will likely be needed to
run the logging tools to PBTD due to the sail angle of the hole section.
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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 frank.roach@hilcorp.com,
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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18.0 Drill 8-1/2” Hole Section
18.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
18.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
18.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
18.4 R/U and test casing to 3000 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. 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.
18.5 Drill out shoe track and 20’ of new formation.
18.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
18.7 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 10.1 ppg FIT is the minimum
required to drill ahead
x 10.1 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swabbed kick at 9.2ppg
BHP)
18.8 POOH & LD Cleanout BHA
18.9 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 Ensure GWD is included in the BHA
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 XT50.
x Run a non-ported float in the production hole section.
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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
18.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
18.11 TIH with 8-1/2” directional assembly to bottom
18.12 Install MPD RCD
18.13 Displace wellbore to 8.9 ppg FloPro drilling fluid
18.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
18.15 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
x RPM: 120+
x Utilize GWD surveys for entire 8-1/2” hole section
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.
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x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole (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 Schrader Bluff OA Concretions: 4-6% Historically
x AC: All wells have a clearance factor greater than 1.0 in the surface interval.
18.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to 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.
18.17 At TD, CBU (minimum 5-7X, 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
18.18 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
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.
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18.19 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
18.20 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
18.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
18.22 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
18.23 Pull RCD Bearing and install trip nipple.
18.24 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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19.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion)
19.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner with slotted liner, the following well control response procedure will be followed:
x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” crossover
installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW).
This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner.
19.2 Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
19.3 R/U 4-1/2” liner running equipment.
x Ensure 5-1/2” JFE Bear and 4-1/2” Hydril 625 x XT-50 crossovers are on rig floor and M/U
to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
19.4 Run 5-1/2” x 4-1/2” injection liner.
x Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
x Uppermost 1,000’ will be 5-1/2”.
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the slots.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt
outside of the surface shoe. This is to mitigate sticking risk while running inner string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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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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5-1/2” 17# L-80 JFE Bear
Casing OD Minimum Optimum Maximum
Operating Torque
5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs
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19.5 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.
19.6 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.
19.7 M/U Baker SLZXP liner top packer to 4-1/2” liner.
19.8 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.
19.9 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.
19.10 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.
19.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
19.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
19.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
19.14 Rig up to pump down the work string with the rig pumps.
19.15 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
19.16 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.
19.17 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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19.18 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.
19.19 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.
19.20 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
19.21 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.
19.22 PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump
sweeps as needed.
19.23 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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20.0 Run 3-1/2” Tubing (Upper Completion)
20.1 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).
20.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD (Set below 70 degrees)
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” Sliding Sleeve at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “X” nipple at ~2,500’ (below base permafrost)
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
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20.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
20.4 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.
20.5 MU tubing hanger and landing joint.
20.6 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.
20.7 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
i. Contact Wellsite Supervisor or Wells Foreman to confirm if freeze protect is needed.
20.8 Land hanger. RILDS and test hanger.
20.9 Continue pressuring up and test the annulus to 3,500 psi and test for 30 charted minutes.
i. Note this test must be witnessed by the AOGCC representative.
ii. Complete form 10-426 and submit to the required recipients. Copy
frank.roach@hilcorp.com,nathan.sperry@hilcorp.com, and twellman@hilcorp.com
on the e-mail.
20.10 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
20.11 Pull BPV. Set TWC. Test tree to 5000 psi.
20.12 Pull TWC. Set BPV. Bullhead tubing freeze protect.
20.13 Secure the tree and cellar.
21.0 RDMO
21.1 RDMO Parker 273
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22.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
22.1 MU surface lines from power fluid header to the tubing.
x Pressure test lines at existing power fluid header pressure (3,500 psi)
22.2 Rig up hardline to the production header and test header. Pressure test to 3,500 psi.
22.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
i. Contingency (if SL is unable to reach depth via pump down): Use RU coil tubing and
pressure test to 250psi low / 3,000psi high. Use coil tubing to perform same runs as
outlined below.
22.4 Shift Sliding sleeve open
22.5 Set 12B jet pump
22.6 RDMO
SL/FB- After 30 days of production
22.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
22.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2,000’ on IA
i. Contingency (if SL was unsuccessful in reaching depth): Use RU coil tubing and pressure
test to 250psi low / 3,000psi high. Use coil tubing to perform same runs as outlined
below.
22.9 Pull Jet Pump
22.10 Shift sliding sleeve closed
22.11 MIT-IA test to 2,000 psi
22.12 POI
22.13 After 5 days of stabilized injection MIT-IA to 2,000 psi (Charted and state witnessed)
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23.0 Parker 273 Diverter Schematic
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24.0 Parker 273 BOP Schematic
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25.0 Wellhead Schematic
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26.0 Days vs Depth
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27.0 Formation Tops & Information
TOP NAME TVD
(FT)
TVDSS
(FT)
MD
(FT)
Formation Pressure
(psi)
EMW
(ppg)
SV5 1,392 1,328 1,463 612 8.46
Base Permafrost 1,874 1,810 2,318 824 8.46
SV1 2,066 2,002 3,160 909 8.46
LA3 3,326 3,262 8,845 1463 8.46
UG_MB 3,554 3,490 9,874 1563 8.46
SB_Na 3,786 3,722 10,921 1665 8.46
SB_Oa 3,924 3,860 11,697 1726 8.46
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L-Pad and F-Pad Data Sheets Formation Descriptions (Closest & Most Analogous MPU Pads to Moose Pad)
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28.0 Anticipated Drilling Hazards
16” 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 Raven pad. However, be prepared for them. Remember that hydrate
gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates,
but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come
out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching.
Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate
formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud
circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized
mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump
contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x There are no wells with a CF < 1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
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1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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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 Raven pad. However, be prepared for them. While the likely depths
for hydrates are in the surface interval, remain vigilant. 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 if motor is used. Do not out drill our ability to clean the hole.
Anti-Collison:
There are wells in close proximity and deviation from plan could have a trickle-down effect on the
pattern for subsequent wells. 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 (running sands, Ungu coals and hard streaks):
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. Maintain mud parameters and increase MW to combat
running sand 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.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
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R-103 SB Injector
Drilling Procedure
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 61
Milne Point Unit
R-103 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 one mapped fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on R-
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 CF < 1.0
Page 62
Milne Point Unit
R-103 SB Injector
Drilling Procedure
29.0 Parker 273 Layout
Page 63
Milne Point Unit
R-103 SB Injector
Drilling Procedure
30.0 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 64
Milne Point Unit
R-103 SB Injector
Drilling Procedure
31.0 Parker 273 Choke Manifold Schematic
Page 65
Milne Point Unit
R-103 SB Injector
Drilling Procedure
32.0 Casing Design
Page 66
Milne Point Unit
R-103 SB Injector
Drilling Procedure
33.0 12-1/4” Hole Section MASP
Page 67
Milne Point Unit
R-103 SB Injector
Drilling Procedure
34.0 8-1/2” Hole Section MASP
Page 68
Milne Point Unit
R-103 SB Injector
Drilling Procedure
35.0 Spider Plot (NAD 27) (Governmental Sections)
Page 69
Milne Point Unit
R-103 SB Injector
Drilling Procedure
36.0 Surface Plat (As-Built) (NAD 27)
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-1000010002000300040005000True Vertical Depth (2000 usft/in)0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000 20000Vertical Section at 301.56° (2000 usft/in)R-103 wp04 tgt01R-103 wp04 tgt02R-103 wp04 tgt03R-103 wp04 tgt04R-103 wp04 tgt05R-103 wp04 tgt06R-103 wp04 tgt07R-103 wp04 tgt08R-103 wp04 tgt09R-103 wp04 tgt10R-103 wp04 tgt11R-103 wp04 tgt12R-103 wp04 tgt13R-103 wp04 tgt14R-103 wp04 tgt15R-103 wp04 Do Not Cross13 3/8" x 16"9 5/8" x 12 1/4"4 1/2" x 8 1/25001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750018000185001900019500200002050021142MPU R-103 wp04Start Dir 3º/100' : 400' MD, 400'TVDStart Dir 4º/100' : 600' MD, 599.63'TVDEnd Dir : 2444.91' MD, 1907.49' TVDStart Dir 4º/100' : 11336.76' MD, 3878.24'TVDEnd Dir : 11546.49' MD, 3910.68' TVDBegin GeosteeringTotal Depth : 21141.73' MD, 3973.75' TVDSV5Base PermafrostSV1UG4ALA3UG_MBSB_NaSB_OaHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU R-10316.80+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.006033293.28540339.26 70° 30' 6.8310 N 149° 40' 12.1790 WSURVEY PROGRAMDate: 2024-07-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool46.95 4116.00 MPU R-103 wp04 (MPU R-103) GYD_Quest GWD4116.00 11697.00 MPU R-103 wp04 (MPU R-103) GYD_Quest GWD11697.00 21141.73 MPU R-103 wp04 (MPU R-103) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1391.75 1328.00 1462.38 SV51873.75 1810.00 2317.37 Base Permafrost2065.75 2002.00 3158.96 SV12355.75 2292.00 4467.42 UG4A3325.75 3262.00 8843.98 LA33553.75 3490.00 9872.70 UG_MB3785.75 3722.00 10919.47 SB_Na3923.75 3860.00 11696.49 SB_OaREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-103, True NorthVertical (TVD) Reference:R-103 as Built @ 63.75usftMeasured Depth Reference:R-103 as Built @ 63.75usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Raven PadWell:Plan: MPU R-103Wellbore:MPU R-103Design:MPU R-103 wp04CASING DETAILSTVD TVDSS MD SizeName2277.86 2214.11 4116.00 13-3/8 13 3/8" x 16"3923.79 3860.04 11697.00 9-5/8 9 5/8" x 12 1/4"3973.75 3910.00 21141.73 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 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.002 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 400' MD, 400'TVD3 600.00 6.00 245.00 599.63 -4.42 -9.48 3.00 245.00 5.77 Start Dir 4º/100' : 600' MD, 599.63'TVD4 2444.91 77.19 299.88 1907.49 470.57 -1020.57 4.00 56.17 1115.91 End Dir : 2444.91' MD, 1907.49' TVD5 11336.76 77.19 299.88 3878.24 4790.85 -8538.32 0.00 0.00 9782.92 Start Dir 4º/100' : 11336.76' MD, 3878.24'TVD6 11546.49 85.00 303.00 3910.68 4898.88 -8714.90 4.00 21.78 9989.93 End Dir : 11546.49' MD, 3910.68' TVD7 11696.49 85.00 303.00 3923.75 4980.27 -8840.22 0.00 0.00 10139.31 R-103 wp04 tgt01 Begin Geosteering8 11737.08 86.22 303.07 3926.86 5002.33 -8874.15 3.00 3.19 10179.769 11840.49 86.22 303.07 3933.68 5058.63 -8960.63 0.00 0.00 10282.9210 11993.96 90.00 303.70 3938.75 5143.01 -9088.68 2.50 9.49 10436.1911 12443.96 90.00 303.70 3938.75 5392.69 -9463.06 0.00 0.00 10885.88 R-103 wp04 tgt0312 12607.01 94.89 303.91 3931.80 5483.30 -9598.38 3.00 2.42 11048.6113 12666.39 94.89 303.91 3926.74 5516.30 -9647.49 0.00 0.00 11107.7314 12839.32 89.70 303.98 3919.82 5612.75 -9790.78 3.00 179.19 11280.3015 13589.32 89.70 303.98 3923.75 6031.92 -10412.69 0.00 0.00 12029.63 R-103 wp04 tgt0516 13787.53 83.75 304.05 3935.06 6142.58 -10576.65 3.00 179.29 12227.2517 13821.52 83.75 304.05 3938.76 6161.50 -10604.64 0.00 0.00 12261.0018 14013.05 89.50 304.05 3950.02 6268.51 -10762.99 3.00 -0.04 12451.9419 15013.05 89.50 304.05 3958.75 6828.41 -11591.50 0.00 0.00 13450.96 R-103 wp04 tgt0720 15192.35 94.87 303.77 3951.91 6928.33 -11740.14 3.00 -2.97 13629.9121 15266.44 94.87 303.77 3945.62 6969.37 -11801.51 0.00 0.00 13703.6822 15412.35 90.50 303.99 3938.79 7050.60 -11922.48 3.00 177.12 13849.2723 16562.35 90.50 303.99 3928.75 7693.48 -12875.95 0.00 0.00 14998.20 R-103 wp04 tgt0924 16793.94 83.55 303.81 3940.75 7822.39 -13067.80 3.00 -178.51 15229.1425 16974.91 83.55 303.81 3961.07 7922.45 -13217.22 0.00 0.00 15408.8326 17236.49 91.40 303.99 3972.57 8068.09 -13433.95 3.00 1.33 15669.7327 18211.49 91.40 303.99 3948.75 8613.00 -14242.12 0.00 0.00 16643.57 R-103 wp04 tgt1128 18267.12 93.05 303.76 3946.59 8643.98 -14288.27 3.00 -7.85 16699.1129 18454.29 93.05 303.76 3936.62 8747.85 -14443.65 0.00 0.00 16885.8730 18582.96 89.20 303.99 3934.09 8819.54 -14550.44 3.00 176.61 17014.3931 19632.96 89.20 303.99 3948.75 9406.49 -15420.94 0.00 0.00 18063.34 R-103 wp04 tgt1332 19757.92 85.50 303.41 3954.53 9475.74 -15524.78 3.00 -171.13 18188.0733 19864.48 85.50 303.41 3962.90 9534.23 -15613.45 0.00 0.00 18294.2334 20006.73 89.75 303.75 3968.80 9612.83 -15731.83 3.00 4.57 18436.2435 21141.73 89.75 303.75 3973.75 10243.39 -16675.54 0.00 0.00 19570.40 R-103 wp04 tgt15 Total Depth : 21141.73' MD, 3973.75' TVD
-5000
-3750
-2500
-1250
0
1250
2500
3750
5000
6250
7500
8750
10000
11250
12500
13750
15000
16250
South(-)/North(+) (2500 usft/in)-16250 -15000 -13750 -12500 -11250 -10000 -8750 -7500 -6250 -5000 -3750 -2500 -1250 0
West(-)/East(+) (2500 usft/in)
R-103 wp04 Do Not Cross
R-103 wp04 tgt15
R-103 wp04 tgt14
R-103 wp04 tgt13
R-103 wp04 tgt12
R-103 wp04 tgt11
R-103 wp04 tgt10
R-103 wp04 tgt09
R-103 wp04 tgt08
R-103 wp04 tgt07
R-103 wp04 tgt06
R-103 wp04 tgt05
R-103 wp04 tgt04
R-103 wp04 tgt03
R-103 wp04 tgt02
R-103 wp04 tgt01
13 3/8" x 16"
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"50012501750200022502500275030003250350037503974MPU R-103 wp04
Start Dir 3º/100' : 400' MD, 400'TVD
Start Dir 4º/100' : 600' MD, 599.63'TVD
End Dir : 2444.91' MD, 1907.49' TVD
Start Dir 4º/100' : 11336.76' MD, 3878.24'TVD
End Dir : 11546.49' MD, 3910.68' TVD
Begin Geosteering
Total Depth : 21141.73' MD, 3973.75' TVD
CASING DETAILS
TVD TVDSS MD Size Name
2277.86 2214.11 4116.00 13-3/8 13 3/8" x 16"
3923.79 3860.04 11697.00 9-5/8 9 5/8" x 12 1/4"
3973.75 3910.00 21141.73 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt Raven Pad
Well: Plan: MPU R-103
Wellbore: MPU R-103
Plan: MPU R-103 wp04
WELL DETAILS: Plan: MPU R-103
16.80
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6033293.28 540339.26 70° 30' 6.8310 N 149° 40' 12.1790 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU R-103, True North
Vertical (TVD) Reference: R-103 as Built @ 63.75usft
Measured Depth Reference:R-103 as Built @ 63.75usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor1100 2200 3300 4400 5500 6600 7700 8800 9900 11000 12100 13200 14300 15400 16500 17600 18700 19800 20900Measured Depth (2200 usft/in)MPU R-101MPU R-101 PB1MPU R-106 wp02MPU R-104 wp02MPU M-30MPU R-105 wp03MPU R-107 wp02MPU R-102 No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU R-103 NAD 1927 (NADCON CONUS)Alaska Zone 0416.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006033293.28540339.2670° 30' 6.8310 N149° 40' 12.1790 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-103, True NorthVertical (TVD) Reference:R-103 as Built @ 63.75usftMeasured Depth Reference:R-103 as Built @ 63.75usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2024-07-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool46.95 4116.00 MPU R-103 wp04 (MPU R-103) GYD_Quest GWD4116.00 11697.00 MPU R-103 wp04 (MPU R-103) GYD_Quest GWD11697.00 21141.73 MPU R-103 wp04 (MPU R-103) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)1100 2200 3300 4400 5500 6600 7700 8800 9900 11000 12100 13200 14300 15400 16500 17600 18700 19800 20900Measured Depth (2200 usft/in)MPU R-101MPU R-111 wp02MPU R-106 wp02MPU R-141MPU R-104 wp02MPU R-110 wp02MPU R-142MPU R-107 wp02MPU R-102 wp08NO GLOBAL FILTER: Using user defined selection & filtering criteria46.95 To 21141.73Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-103Wellbore: MPU R-103Plan: MPU R-103 wp04CASING DETAILSTVD TVDSS MD Size Name2277.86 2214.11 4116.00 13-3/8 13 3/8" x 16"3923.79 3860.04 11697.00 9-5/8 9 5/8" x 12 1/4"3973.75 3910.00 21141.73 4-1/2 4 1/2" x 8 1/2"
1
Dewhurst, Andrew D (OGC)
From:Dewhurst, Andrew D (OGC)
Sent:Monday, 26 August, 2024 14:06
To:Graham Emerson; Frank Roach
Cc:Joseph Lastufka; Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Rixse, Melvin G
(OGC)
Subject:RE: [EXTERNAL] MPU R-103 PTD (224-114): Mudlogging
Graham,
Thank you.
From: Graham Emerson <Graham.Emerson@hilcorp.com>
Sent: Monday, 26 August, 2024 14:05
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Frank Roach <Frank.Roach@hilcorp.com>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] MPU R-103 PTD (224-114): Mudlogging
Hi Andy,
Yes we have Halliburton mudlogging setting up to mudlog the Intermediate hole on R-103 as per the agreed terms
with Steve.
Thanks
Graham
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Monday, August 26, 2024 1:53 PM
To: Frank Roach <frank.roach@hilcorp.com>; Graham Emerson <Graham.Emerson@hilcorp.com>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] MPU R-103 PTD (224-114): Mudlogging
Graham,
I am compleƟng my review of the MPU R-103 PTD and wanted to conĮrm that you are sƟll planning to acquire mudlogs
as per previous discussions with Steve. The last email indicated either for R-103 or R-104. Will it be ready for R-103?
You don't often get email from graham.emerson@hilcorp.com. Learn why this is important
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2
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas ConservaƟon Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
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1
Dewhurst, Andrew D (OGC)
From:Davies, Stephen F (OGC)
Sent:Monday, 26 August, 2024 10:25
To:Dewhurst, Andrew D (OGC)
Cc:Guhl, Meredith D (OGC)
Subject:FW: [EXTERNAL] RE: MPU R-Pad Mudlogging and Sampling Requirements
Andy,
Here’s the latest email I have from Graham regarding R-Pad mud logging and sampling. Nothing deĮnite was decided:
Candidates were either R-103 in September or R-104 in October. But things change…
Cheers,
Steve
From: Graham Emerson <Graham.Emerson@hilcorp.com>
Sent: Thursday, July 18, 2024 10:29 AM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] RE: MPU R-Pad Mudlogging and Sampling Requirements
Hi Steve,
Thank you for the email. No indications of hydrate or shallow gas were seen in R-141, R-142 or R-101 shallow
sections. The rig has a ‘GasWatch’ system that monitors total gas. My drilling engineer is looking into the dataset
that is recorded and I will get back to you on this shortly.
Noted on your cuttings sample interval request. I will work with the mudlogging company and get samples at a
frequency that is practical for them but will strive to get close to your intervals mentioned below.
Next step is I will reach out to mudlogging outƱts to get an idea on timing for getting them on location. I am
thinking of targeting R-103 (September) or R-104 (October). I’m sure you appreciate the schedule can shift around
a little.
Many thanks.
Graham
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Wednesday, July 17, 2024 1:29 PM
To: Graham Emerson <Graham.Emerson@hilcorp.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] RE: MPU R-Pad Mudlogging and Sampling Requirements
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
2
Hi Graham,
With the sample-spacing condiƟon below and if indicaƟons of shallow gas or gas hydrates are not encountered in any of
the iniƟal wells drilled from MPU R-Pad, Hilcorp’s proposal to mud log and collect cu ƫngs samples across only the
intermediate secƟon of one well from MPU R-Pad is reasonable and acceptable given that mud logs and samples were
obtained at nearby F- and L-Pads (wells MPU F-46 and Milne Point L-01), and neither signiĮcant shallow gas nor gas
hydrates have been reported at either of these pads.* CollecƟon of the mud log and samples across the intermediate
secƟon in one R-Pad well is warranted as departure from F-46 will range from about 0.6 miles at the base of permafrost
to 1.6 miles at the top of the OA sand. Mud logging and collec Ɵng cuƫngs samples across the producƟon porƟon of the
well is not necessary as these will not signiĮcantly add to the geologic and engineering knowledge for this por Ɵon of the
Schrader Bluī Oil Pool.
(* Per the “L-Pad and F-Pad Data Sheet FormaƟon DescripƟons” provided in within the MPU R-101 Permit to Drill
ApplicaƟon).
x Hilcorp’s proposed 100-foot interval for cuƫngs samples is a bit broad. For secƟons of high-drill rate, please
collect samples as closely as pracƟcal (adhering to safety pracƟces at all Ɵmes to ensure the well-being of the
mud logging crew) decreasing to 50-foot samples when the drill rate makes that interval safe and prac Ɵcal,
decreasing again to 30-foot intervals when safe and pracƟcal, and then—if possible—10-foot samples through
the uppermost OA to get a more representaƟve sample for that sand.
The other bullet points presented in your email below are acceptable.
For the Įrst wells drilled from R-Pad, were indicaƟons of shallow gas or gas hydrates encountered while drilling surface
hole? If so, were they monitored and recorded? If so, please submit those monitoring records to AOGCC.
Regards and Be Well,
Steve Davies
Senior Petroleum Geologist
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation
Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain conƱdential and/or privileged information. The
unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,
without Ʊrst saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or
steve.davies@alaska.gov.
From: Graham Emerson <Graham.Emerson@hilcorp.com>
Sent: Monday, July 15, 2024 12:48 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL] RE: R pad mudlogging and sampling requirements
Hi Steve,
Thanks for the conversation today. Here is my proposal based on out chat and using the M-03 (Moose pad)
[500292361400] well as an analog for mudlogging on a new pad. Attached is a slide showing the location of R pad
3
just 2000ft from F pad on surface. The slide also shows the well design for our Raven pad 3 string wells so you can
visualize the zone we propose to log on a map and cross section.
_________________________________________________________________
• Propose logging Intermediate hole (lower Sagavanirktok -> Top Schrader Oa sands)
– Complete set of washed and dried cutting samples (approx.. 100’md increment). Minimum of ¼
cup in volume. 10-30’md increment through the Oa sands at casing point TD
– Show reports (as shows occur in hole section (referenced above))
– Total gas and C1-C5 logs for above interval
– Lithology log and lithology descriptions for above interval
– * as discussed, there would be no plan to mudlog in the production hole (lateral section) due to the
limited value added with the well staying in the Oa sands
I will reach out to logging companies once you are happy with the scope. I can then give you a better idea of
timing. Likely we will get this done in the next 2-3months. Likely one of well MPR-103, R-104 or R-105.
Thanks
Graham
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Monday, July 15, 2024 10:44 AM
To: Graham Emerson <Graham.Emerson@hilcorp.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL] RE: R pad mudlogging and sampling requirements
Graham,
This is a historical AOGCC policy that is not explicitly spelled out in the regulations but falls instead under Section
(a) of that regulation: “…unless the commission speciƱes the type of each log to be run.” Recording a mud log and
collecting cuttings samples at one well from each new pad—and especially here within a previously untapped
portion of the reservoir—signiƱcantly adds to the geologic and engineering knowledge for this portion of the Milne
Point Unit.
Thanks and Be Well,
Steve Davies
AOGCC
From: Graham Emerson <Graham.Emerson@hilcorp.com>
Sent: Monday, July 15, 2024 10:34 AM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Subject: R pad mudlogging and sampling requirements
Hi Steve,
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I am the geologist working on the Milne Point Raven Pad drilling. I was hoping we could chat brieƲy on the
requirements for logging and sampling for R Pad.
I did not see a reference to the new pad requirement in the 20 AAC 25.071. Logs and geologic data. Am I looking
in the right place?
My oƯice number is below and I am happy to call you on your oƯice number at a convenient time for you.
Regards
Graham
__________________________________________________________________________________________________________
______________________
Joe,
I’m reviewing Hilcorp’s PTD application for MPU R-102. Please be advised that AOGCC’s long-standing policy is to
require a mud log and cuttings samples from one well drilled from each new drill pad. Which well will be Hilcorp’s
choice for mud logging and sampling from the new MPU R-Pad?
Thanks and Be Well,
Steve Davies
AOGCC
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
Collect samples from intermediate hole section. See note below:
mudlog (for intermediate hole section)
MPU R-103
SCHRADER BLUFF OIL
224-114
Spacing Exception granted in CO 477A.003 Ammended
Mudlogging intervals: for sections of high-drill rate, collect samples as closely as practical (adhering to safety practices at all times
to ensure the well-being of the mud logging crew) decreasing to 50-foot samples when the drill rate makes that interval safe and
practical, decreasing again to 30-foot intervals when safe and practical, and then 10-foot samples through the uppermost OA. See
attached emails for details. -A.Dewhurst 26 AUG 24
MILNE POINT
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT R-103Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241140MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes ADL025509, ADL388235, and ADL3550182 Lease number appropriateYes3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by CO 477, 477.0054 Well located in a defined poolNo BHL is outside Milne Point Unit5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedNo BHL is within 500 of offset ENI's Nikaitchuq Unit9 Operator only affected partyYes10 Operator has appropriate bond in forceNo CO 477A.003 Ammended was granted on 25 June, 202411 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-C14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYes15 All wells within 1/4 mile area of review identified (For service well only)Yes Up to 30 days16 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 165'18 Conductor string providedYes 13-3/8" L-80 68# to 2278' TVD19 Surface casing protects all known USDWsYes Fully cemented20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes 13-3/8" x 9-5/8" covering the overburden23 Casing designs adequate for C, T, B & permafrostYes Parker 273 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no close approaches26 Adequate wellbore separation proposedYes 16" Diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to 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 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Parker 273 has 14 x 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/16" remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo MPU R pad has no H2S history. Monitoring will be required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated; however, rig will have H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normally pressured reservoir. MPD to mitigate any abnormal pressures.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate8/26/2024ApprMGRDate8/28/2024ApprADDDate8/22/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&: JLC 8/29/2024
