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:Wednesday, May 22, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Kam StJohn
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
I-25
MILNE PT UNIT I-25
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 05/22/2024
I-25
50-029-23776-00-00
223-119-0
W
SPT
3999
2231190 1500
115 116 115 115
INITAL P
Kam StJohn
4/13/2024
MIT-IA to 2000 Psi after 10 day stablization of injection. Monobore Injector No OA.
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 I-25
Inspection Date:
Tubing
OA
Packer Depth
248 2175 2100 2077IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitKPS240413111522
BBL Pumped:4.2 BBL Returned:4
Wednesday, May 22, 2024 Page 1 of 1
By Grace Christianson at 8:32 am, Apr 08, 2024
Completed
2/27/2024
JSB
RBDMS JSB 041524
GMGR19DEC2025
Drilling Manager
04/03/24
Monty M
Myers
Todd Sidoti for Taylor Wellman
Digitally signed by Todd
Sidoti
DN: cn=Todd Sidoti
Date: 2024.04.04 11:54:34 -
08'00'
Todd
Sidoti
_____________________________________________________________________________________
Revised By: JNL 3/28/2024
SCHEMATIC
Milne Point Unit
Well: MPU I-25
Last Completed: 2/27/2024
PTD: 223-119
5-1/2” x 4-1/2” Slotted Liner
Top (MD) Top (TVD) Btm (MD) Btm (TVD)
6,990’ 4,018’ 8,520’ 3,983’
9,104’ 3,978’ 17,855’ 4,203’
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 135’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,328’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,328’ 6,963’ 0.0758
5-1/2” Slotted/ Liner 17 / L-80 / JFE Bear 4.892” 6,795’ 8,939’ 0.0232
4-1/2” Slotted/ Liner 13.5 / L-80 / Hyd 625 3.920” 8,939’ 18,470’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 6,816’ 0.0087
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4"Stg 1 –Lead 635 sx / Tail 400 sx
Stg 2 –Lead 700 sx / Tail 270 sx
8-1/2” Uncemented Slotted Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” x 4-1/2” Tubing Hanger, 4-1/2” TCII
GENERAL WELL INFO
API#: 50-029-23776-00-00
Completion Date: 2/27/2024
WELL INCLINATION DETAIL
KOP @ 265’
90° Hole Angle = 7,121’ MD
TD =18,470’(MD) / TD =4,237 (TVD)
20”
Orig. KB Elev.:68.05’ / GL Elev.: 33.7’
3-1/2”
7
2
9-5/8”
1
4/5
3
See
Drilled/
Slotted
Liner
Detail
PBTD =18,468’(MD) / PBTD =4,237’(TVD)
9-5/8” ‘ES’
Cementer @
2,308’
5-1/2” x
4-1/2”
6
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 5,885’ Viking Sliding Sleeve (Opens Down) 2.813” X Profile 2.870”
2 5,937’ Baker Zenith Gauge 2.992”
3 5,985’ XN Nipple, 2.813”, 2.75” No-Go 2.750”
4 6,805’ Locater Sub, 8.25” No Go (bottom of locator spaced out 2.72’) 6.170”
5 6,806’ Bullet Seals – TXP Top Box x Mule Shoe (Bottom @ 6,816’) 6.170”
Lower Completion
6 6,795’ 9-5/8” SLZXP Liner Top Packer 6.210”
7 18,468’ Shoe
0
1
2 3
4
5
6
7
8
9
10
11
0
2
4
6
8
10
12
14
16
18
20
22
24
26
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
0102030
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
548540534529522514507501494489483478473468463459
2732 2723 2718 2714 2709 270627052705270427032703
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30 35
Pr
e
s
s
u
r
e
(p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
4
ACTIVITYDATE SUMMARY
2/28/2024
***WELL S/I ON ARRIVAL***
RUN 42BO TO OPEN SLIDING SLEEVE @ 5885' MD
***CONTINUE WSR ON 2-29-2024***
2/29/2024
***CONTINUED FROM 2-28-2024***
WATCH IA PRESSURE FOR 20 MINS, NO CHANGE IN PRESSURE
RUN QC, 3' X 1.875" STEM, 3.5" 42 BO, TOOLS FALL THROUGH SLEEVE
MULTIPLE TIMES (see log)
SET 3.5" X-LOCK, JET PUMP w/ SCREEN (13C ratio, 87" oal) @ 5885' MD
***WELL S/I ON DEPARTURE***
3/1/2024
MPU Well Support tied new Grassroots Injector in to process,as a 30 day
Producer,as per sundry. Crossed injection lateral over to 1502,then tied into
Test/Production. Tied injection candy cane down comer to Source Water header,with
new root valve and blinded that piping run. All surface lines/hardline PT'd and
wellhead serviced.
After 30 day sundry and well is slated for Injection,there will only be (1) piping flange
connection to make. Check and choke will need flopped,to flow opposite direction at
that time.
Handed well over to I&E Gang and assisted them. FCO'd and ready to POP.
No issues
3/2/2024
*** WELL SHUT-IN ON ARRIVAL.***
PULL 3-1/2" JETPUMP (ratio: 13C) FROM VIKING-SS AT 5,885' MD.
OPEN VIKING-SS AT 5,885' MD W/ 3-1/2" 42BO (see 800psi drop on ia).
SET 3-1/2" JETPUMP (ratio: 13C) IN VIKING-SS AT 5,885' MD.
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.
4/2/2024
I-25's sundry as Temporary Producer ended and it was shut-in 04/01/24. MPU Well
Support converted well to permanent Injector. Reversed choke and check at
wellhead,to orient correctly. Surface line PT'd to 3650# and well handed over to
Slickline.
No issues
4/2/2024
*** WELL SHUT-IN ON ARRIVAL.****
PULL 3-1/2' JETPUMP (ratio: 13C) FROM VIKING-SS AT 5,885' MD
LRS LOADED IA W/ 190bbls CORROSION INHIBITOR, 212bbls DIESEL.
CLOSE VIKING -SS AT 5,885' MD W/ 3-1/2" 42BO.
LRS PERFORMED PASSING MIT-IA TO 2000psi.
*** WELL SHUT-IN ON DEPARTIRE, PAD OP NOTIFIED.***
4/2/2024
T/I = 350/25 Load IA with 190 bbls Corrosion Inhibited 1% KCL, Pumped 202 bbls
diesel down IA for Freeze Protect, MIT-IA to 2000 psi, Passed, FWP = 320/100
Daily Report of Well Operations
PBU MPI-25
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT I-25
JBR 04/04/2024
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:test with 5" TJ 18 accumulator bottles avg 990psi pre charge.
TEST DATA
Rig Rep:Operator:Hilcorp Alaska, LLC Operator Rep:Jay Murphy
Contractor/Rig No.:Doyon 14 PTD#:2231190 DATE:2/8/2024
Well Class:DEV Inspection No:divKPS240207224105
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
Test Time:1.5
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:12.25 P
Vent Line(s) Size:16 P
Vent Line(s) Length:197 P
Closest Ignition Source:79 P
Outlet from Rig Substructure:189 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:26 P
Knife Valve Open Time:18 P
Diverter Misc:0 NA
Systems Pressure:P2950
Pressure After Closure:P1800
200 psi Recharge Time:P29
Full Recharge Time:P153
Nitrogen Bottles (Number of):P6
Avg. Pressure:P1928
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
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.
From:Brooks, Phoebe L (OGC)
To:Alaska NS - Doyon 14 - DSMs
Cc:Regg, James B (OGC)
Subject:RE: MPU I-25 Doyon 14, Initial BOP test results
Date:Friday, March 15, 2024 4:02:06 PM
Attachments:Doyon 14 02-15-24 Revised.xlsx
Mark,
I made a minor revision, changing the CH Misc test result to “NA”. Please update your copy.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
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 confidential 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 first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it
to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Alaska NS - Doyon 14 - DSMs <AlaskaNS-Doyon14-DSMs@hilcorp.com>
Sent: Friday, February 16, 2024 9:09 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay
<doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Cc: Ian Toomey - (C) <itoomey@hilcorp.com>
Subject: MPU I-25 Doyon 14, Initial BOP test results
Here is the test form for the initial BOP test completed 2/15/24
Thank you.
Mark Brouillet
Hilcorp Alaska, LLC
Doyon Rig 14
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-631-9850
mark.brouillet@Hilcorp.com
AlaskaNS-Doyon14-DSMs@hilcorp.com
Milne Point Unit I-25
PTD 2231190
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner:Rig No.:14 DATE:2/15/24
Rig Rep.:Rig Email:
Operator:
Operator Rep.:Op. Rep Email:
Well Name:PTD #2231190 Sundry #
Operation:Drilling:X Workover:Explor.:
Test:Initial:X Weekly:Bi-Weekly:Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1360
MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1 P
Permit On Location P Hazard Sec.P Lower Kelly 1 P
Standing Order Posted P Misc.NA Ball Type 2 P
Test Fluid Water Inside BOP 2 P
FSV Misc 0 NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0 N/A NA Trip Tank P P
Annular Preventer 1 13-5/8"P Pit Level Indicators P P
#1 Rams 1 2-7/8" x 5"P Flow Indicator P P
#2 Rams 1 Blinds P Meth Gas Detector P P
#3 Rams 1 2-7/8"X5"P H2S Gas Detector P P
#4 Rams 0 NA MS Misc 0 NA
#5 Rams 0 NA
#6 Rams 0 NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" X 5000 P Time/Pressure Test Result
HCR Valves 2 3-1/8" X 5000 FP System Pressure (psi)3000 P
Kill Line Valves 1 3-1/8" X 5000 P Pressure After Closure (psi)1600 P
Check Valve 0 NA 200 psi Attained (sec)50 P
BOP Misc 0 NA Full Pressure Attained (sec)219 P
Blind Switch Covers:All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 @ 1875 P
No. Valves 14 P ACC Misc 0 NA
Manual Chokes 1 P
Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result
CH Misc 0 NA Annular Preventer 14 P
#1 Rams 7 P
Coiled Tubing Only:#2 Rams 7 P
Inside Reel valves 0 NA #3 Rams 7 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:5.5 HCR Choke 2 P
Repair or replacement of equipment will be made within 0 days. HCR Kill 2 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 2/14/24 6:25am
Waived By
Test Start Date/Time:2/15/2024 17:30
(date)(time)Witness
Test Finish Date/Time:2/15/2024 23:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Guy Cook
Doyon
Test Annular with 3-1/2" test joint to 250/3000 psi. All other tests performed to 250/3000 psi. Test lower & upper rams with 3.5" &
5" test joints. Test H2S and LEL gas alarms. Test PVT, Gain/Loss and flow paddle. Test 4-1/2 IF & 3-1/2 IF TIW & Dart valves. All
test performed against test plug. AOGCC Guy Cook waived witness of test at 09:25 on 2/14/24. FP on HCR choke valve, cycle
valve & re-test (good).
O Williams / J Charlie
Hilcorp
M Brouillet / I Toomey
MPU I-25
Test Pressure (psi):
rig14@doyondrilling.com
skaNS-Doyon14-DSMs@hilcorp.c
Form 10-424 (Revised 08/2022)2024-0215_BOP_Doyon14_MPU_I-25
J. Regg; 4/3/2024
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: 03/13/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU I-25
PTD: 223-119
API: 50-029-23776-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (02/08/2024 to 02/22/2024)
x ROP, ABG, DGR, EWR-4, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL Geosteering Subfolders:
Please include current contact information if different from above.
223-119
T38613
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.14 08:53:15 -08'00'
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.
From:Mark Brouillet - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:Nathan Sperry; Ryan Thompson
Subject:Milne Point, I pad, Well I-25, Doyon 14, MIT-IA to 3500 psi per PTD# 223-119
Date:Tuesday, February 27, 2024 10:50:15 AM
Attachments:10-426 I-25.xlsx
Some people who received this message don't often get email from mark.brouillet@hilcorp.com. Learn why this isimportant
MIT Form 10-426 for submittal.
Thank you.
Mark Brouillet
Hilcorp Alaska, LLC
Doyon Rig 14
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-631-9850
mark.brouillet@Hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
MPU I-25
PTD 2231190
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-119 Type Inj W Tubing 0 Type Test P
Packer TVD 3999 BBL Pump 7.0 IA 0 3700 3600 3600 Interval I
Test psi 3500 BBL Return 7.0 OA Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp
Milne Point, I Pad, Well I-25
Waived by AOGCC Rep Kam StJohn
Mark Brouillet
02/27/24
Notes:MIT- IA to 3,500 psi per PTD # 223-119 Notification for test sent out 2/26/24 Waived by Kam StJohn 2/26/24 @ 09:24 Test time 2/27/2024 09:15
Notes:
Notes:
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Form 10-426 (Revised 01/2017)2024-0227_MIT_MPU_I-25
J. Regg; 5/10/2024
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-25
Hilcorp Alaska, LLC
Permit to Drill Number: 223-119
Surface Location: 2347' FNL, 4040' FEL, Sec 33, T13N, R10E, UM, AK
Bottomhole Location: 1247' FSL, 708' FEL, Sec 17, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this day of February 2024.
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.02.15 12:05:47
-06'00'
15
REVISED
Change of Bottom Hole
Location Over 500'
Drilling Manager
02/12/24
Monty M
Myers
By Grace Christianson at 9:11 am, Feb 13, 2024
223-119
DSR-2/13/24MGR14FEB24
50-029-23776-00-00
* BOPE test to 3000 psi. Annular to 2500 psi.
* MIT-IA to 3500 psi. 24 hour notice to state to witness.
* MIT-IA to 2000 psi after 10 days of stabilized injection.
State to witness.
* 30 day pre-production with jet pump approved with passing MIT-IA to 3500 psi.
SFD 2/14/2024*&:JLC 2/15/2024
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2024.02.15 12:06:32 -06'00'
02/15/24
02/15/24
Planned I 25 Top
Schrader Bluff
Oba intersection
point
Future I-24 OBa producer
(not drilled yet)
Future I-26 OBa producer
(not drilled yet)
Planned I 25
Oba Injector TD
I-25 AOR MAP- Revised 2/9/2024 to reflect extended TD
•All wells that penetrate the Schrader Bluff OBa labelled at top OBa
intersection point
•Wells that did not penetrate the Schrader Bluff OBa are labelled at TD
(NB is ~210’ shallower than OBa, Oa is ~67’ shallower than Oba)
•Green lines represent the footage in wells that are within the Schrader
Bluff PBA inside the ¼ mile radius of proposed injector, I-25
•Both Nb and Oa wells (above target zone) are shown on map but not
highlighted so map is less busy- included on AOR spreadsheet
•NOTE: Future I-24 through I-26 wells are almost directly underneath I-
31 through I-33 Oa wells
L-46, L-47 and L-48
are Schrader Bluff
Oa horizontal wells
L-42 Kuparuk Well (Intersects the
Schrader bluff 3900’ northwest of
here), therefore NOT in AOR
I-25 Original Planned TD
I-25 AOR
PTD API WELL STATUS
Top of SB
OBA (MD)
Top of SB
OBA (TVD)
CBL Top of
Cement
(MD)
CBL Top of
Cement
(TVD)
Schrader OBA
status Zonal Isolation
204-119 50-029-23214-00-00 MPU I-14 Oba Lateral 7586 3989 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%
washout, TOC is 4242' MD.
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1
bbls 15.8ppg class G cement through cement retainer.
204-119 50-029-23214-70-00 MPU I-14PB1 Oba Plug back 7586 3989 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%
washout, TOC is 4242' MD.
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1
bbls 15.8ppg class G cement through cement retainer.
204-119 50-029-23214-71-00 MPU I-14PB2 Oba Plug back 7586 3989 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%
washout, TOC is 4242' MD.
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1
bbls 15.8ppg class G cement through cement retainer.
204-120 50-029-23214-60-00 MPU I-14L1 OA Lateral N/A N/A N/A N/A N/A
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 45 bbls
15.8ppg class G through cement retainer.
204-121 50-029-23214-61-00 MPU I-14L2 NB Prod Lateral N/A N/A N/A N/A N/A
Annulus isolated via 7-5/8" cement job.
Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of
14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top of
retainer to 6,500' MD.
204-121 50-029-23214-72-00 MPU I-14L2PB1 NB Plug Back N/A N/A N/A N/A N/A
Annulus isolated via 7-5/8" cement job.
Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of
14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top of
retainer to 6,500' MD.
204-121 50-029-23214-73-00 MPU I-14L2PB2 NB Plug Back N/A N/A N/A N/A N/A
Annulus isolated via 7-5/8" cement job.
Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of
14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top of
retainer to 6,500' MD.
204-098 50-029-23212-60-00 MPU I-17 NB Prod Lateral 5069 3953 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-099 50-029-23212-60-00 MPU I-17L1 Oba Lateral 5069 3953 N/A N/A Open
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-100 50-029-23212-61-00 MPU I-17L2 OA Lateral N/A N/A N/A N/A N/A
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-064 50-029-23205-00-00 MPU J-26 NB Prod Lateral 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-064 50-029-23205-70-00 MPU J-26PB1 NB Plug back 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-064 50-029-23205-71-00 MPU J-26PB2 NB Plug back 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
Area of Review MPU I-25 SB OA
204-066 50-029-23205-60-00 MPU J-26L1** OBa Lateral 5556 4027 N/A N/A Closed Lateral isolated via iso sleeve and NB/OA reservoir abandonments.
204-067 50-029-23205-61-00 MPU J-26L2** OA Lateral N/A N/A N/A N/A Closed
OA reservoir P&A'd on 4/4/2022. Coil pumped 105 bbls 15.8ppg class G
cement. Washed to 5,100' MD.
197-200 50-029-228-25-00-00 MPU J-21 SB Producer, Shut In 5985 4000 N/A N/A Open
Cemented with 1471 sx PF 'E' and 258 sx Class 'G'. Final TOC reported 3.5'
from surface.
197-215 50-029-22832-00-00 MPU J-20 Schrader, P&A'd for J-20A 7848 3995 N/A N/A Closed
J-20 was abandoned via the J-20A sidetrack. J-20 was cemented to surface
via a 2 stage cement job with 84 bbls returned to surface on 12/2/1997.
197-208 50-029-22828-00-00 MPU J-17 SB Injector, Shut In 6479 4043 Surface surface Open
Well open to injection support in the NB, NC, OA and OB sands. Packers
isolate the NB/NC from the OA/OB.
195-159 50-029-22607-00-00 MPU J-19 P&A'd / Sidetracked 6625 4076 3693 2860 Closed
Balanced plug from 6390' MD to 5490'MD , 5450' MD to 4500' MD, and
4290' MD to 3600' MD.
204-073 50-029-23207-00-00 MPU J-25 P&A'd NB Lateral N/A N/A 2497 2472 N/A
Coil pumped 108 bbls of cmt in NB lateral on July 3, 2020. Cement tagged
at 3,887' SLMD on 7/13/2020.
194-101 50-029-22495-00-00 MPU J-09 P&A'd / Sidetracked 5776 4111 N/A N/A Closed
7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washout
estimated at 4,595' MD.
Cmt Rtnr @ 5,360', Could not inject beneath retainer, PT 7" to 3000psi f/
30 min, AOGCC approval to sidetrack well. J-09 P&A'd
199-114 50-029-22495-01-00 MPU J-09A OA Producer N/A N/A N/A N/A N/A
97sks of cement pumped with bonzai completion, packer depth 5,199',
cement valve 6,013'.
Reservoir abandoned 3/27/22 via coil tubing by pumping 50 bbls 15.8ppg
class G. Tagged TOC at 5,237' CTMD.
199-117 50-029-22497-01-00 MPU J-08A OB Prod Shut in 5788 4110 4714 3808 Open
Cement valve at 5,776' MD, pump 15 bbls, returns observed on BU TOC at
TOL @ 4,714' MD. Status of Oba will be closed using service coil pre-rig
204-136 50-029-23218-60-00 MPU I-19L1 Suspended OA Lateral N/A N/A 3334 2680 N/A Suspended
199-107 50-029-22952-00-00 MPU J-15 SB Injector P&A'd 6916 4159 N/A N/A Closed Abandoned. Full P&A performed in September/October 2020.
197-220 50-029-22834-00-00 MPU J-18 SB Injector Shut In 7952 4131 Surface surface
Open**NB, OA, Ob sands open.
220-057 50-029-23684-00-00 MPU I-38 NB Producer N/A N/A N/A N/A N/A Not Open
220-057 50-029-23684-70-00 MPU I-38PB1 NB Plug back N/A N/A N/A N/A N/A Not Open
220-057 50-029-23684-71-00 MPU I-38PB2 NB Plug back N/A N/A N/A N/A N/A Not Open
220-060 50-029-23686-00-00 MPU I-39 NB Injector N/A N/A N/A N/A N/A Not Open
220-071 50-029-23689-00-00 MPU I-40 Nb Producer N/A N/A N/A N/A N/A Not Open
223-066 50-029-237-63-00-00 MPU I-31 OA Producer N/A N/A N/A N/A N/A Not Open
223-054 50-029-237-59-00-00 MPU I-32 OA Injector N/A N/A N/A N/A N/A Not Open
223-070 50-029-237-64-00-00 MPU I-33 OA Producer N/A N/A N/A N/A N/A Not Open
215-120 50-029-23552-00-00 MPU L-48 OA Injector N/A N/A N/A N/A N/A Not Open
215-117 50-029-23550-00-00 MPU L-47 OA Producer N/A N/A N/A N/A N/A Not Open
215-118 50-029-23551-00-00 MPU L-46 OA Producer N/A N/A N/A N/A N/A Not Open
215-118 50-029-23551-00-00 MPU L-46PB1 OA plugback N/A N/A N/A N/A N/A Not Open
TBD TBD MPU I-24 OBA Producer TBD TBD TBD TBD Will be Open Not Drilled
TBD TBD MPU I-26 OBA Producer TBD TBD TBD TBD Will be open Not Drilled
Milne Point Unit
(MPU) I-25
Drilling Program
Version 2
2/12/2024
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 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 BOP N/U and Test.................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ...................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 39
18.0 RDMO ...................................................................................................................................... 40
19.0 Post-Rig Work ......................................................................................................................... 41
20.0 Doyon 14 Diverter Schematic .................................................................................................. 42
21.0 Doyon 14 BOP Schematic ........................................................................................................ 43
22.0 Wellhead Schematic ................................................................................................................. 44
23.0 Days Vs Depth .......................................................................................................................... 45
24.0 Formation Tops & Information............................................................................................... 46
25.0 Anticipated Drilling Hazards .................................................................................................. 47
26.0 Doyon 14 Layout ...................................................................................................................... 51
27.0 FIT Procedure .......................................................................................................................... 52
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 53
29.0 Casing Design ........................................................................................................................... 54
30.0 8-1/2” Hole Section MASP ....................................................................................................... 55
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 57
Page 2
Milne Point Unit
I-25 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU I-25
Pad Milne Point “I” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff OBa Sand
Planned Well TD, MD / TVD 20,126’ MD / 4,197’ TVD
PBTD, MD / TVD 20,126’ MD / 4,197’ TVD
Surface Location (Governmental) 2347' FSL, 1269' FWL, Sec. 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551330 Y= 6009460
Top of Productive Horizon
(Governmental)1133' FNL, 2421' FWL, Sec 32, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 547215 Y= 6011233
BHL (Governmental) 1247' FSL, 708' FEL, Sec 17, T13N, R10E, UM, AK
BHL (NAD 27) X= 549242 Y=6024185
AFE Drilling Days 21 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1360 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1760 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 33.7 ft = 67.4 ft
GL Elevation above MSL: 33.7 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
I-25 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
I-25 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2”5-1/2” 4.892”4.767”6.050”17 L-80 JFE Bear 7,740 6,290 397
4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
I-25 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
Report covers operations from 6am to 6am
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.
Ensure time entry adds up to 24 hours total.
Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
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
Health and Safety: Notify EHS field coordinator.
Environmental: Drilling Environmental Coordinator
Notify Drilling Manager & Drilling Engineer on all incidents
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Milne Point Unit
I-25 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Milne Point Unit
I-25 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
MPU I-25 is a grassroots injector planned to be drilled in the Schrader Bluff OBa sand. I-25 is part of a
multi well program targeting the Schrader Bluff sand on I-Pad. I-25 will be pre-produced for 30 days.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff OBa sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in
the open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 6th, 2024, pending rig schedule.
Surface casing will be run to 6,955’ MD / 3,999’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 4-1/2” injection liner.
7. Run 3-1/2” tubing.
8. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
Page 8
Milne Point Unit
I-25 SB Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
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.
BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-25. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
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.
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.
All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
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
Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
Page 9
Milne Point Unit
I-25 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for pre-producing up to 30 days via a reverse circulating jet pump completion.
This will allow us to measure skin and evaluate the benefits of pre-producing our injectors in the future.
During flow back, Hilcorp will have a 24/7 man watch while the well is online and producing. Section 19
details the steps required to make this happen. Note also that the MIT-IA has been changed from 2,500 psi to
3,500 psi.
Page 10
Milne Point Unit
I-25 SB Injector
Drilling Procedure
Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
13-5/8” x 5M Hydril “GK” Annular BOP
13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
Mud cross w/ 3” x 5M side outlets
13-5/8” x 5M Hydril MPL Single ram
3-1/8” x 5M Choke Line
3-1/8” x 5M Kill line
3-1/8” x 5M Choke manifold
Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
Well control event (BOP’s utilized to shut in the well to control influx of formation fluids).
24 hours notice prior to spud.
24 hours notice prior to testing BOPs.
24 hours notice prior to casing running & cement operations.
Any other notifications required in PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 I-25 will utilize a newly set 20” conductor on I-Pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80 F).
9.10 Ensure 6” liners in mud pumps.
Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
N/U 21-1/4” diverter “T”.
Knife gate, 16” diverter line.
Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
Diverter line must be 75 ft from nearest ignition source
Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
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:
A prohibition on vehicle parking
A prohibition on ignition sources or running equipment
A prohibition on staged equipment or materials
Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Use GWD until MWD surveys are clean.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 5” 19.5# S-135.
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.
Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OBa sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
Hold a safety meeting with rig crews to discuss:
Conductor broaching ops and mitigation procedures.
Well control procedures and rig evacuation
Flow rates, hole cleaning, mud cooling, etc.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Keep mud as cool as possible to keep from washing out permafrost.
Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoff’s, increase in pump pressure, or changes in hookload are seen
Slow in/out of slips and while tripping to keep swab and surge pressures low
Ensure shakers are functioning properly. Check for holes in screens on connections.
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.
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).
Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
Gas hydrates have not been seen on I-Pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be
prepared for hydrates:
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Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
Monitor returns for hydrates, checking pressurized & non-pressurized scales
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.
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.
AC: All wells have a clearance factor greater than 1.0 in the surface interval.
12-1/4” hole mud program summary:
Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid
will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with
a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base
Permafrost
8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate
zone
PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total)
can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore.
Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to
reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of
the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with
caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 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
Pump at full drill rate (400-600 gpm), and maximize rotation.
Pull slowly, 5 – 10 ft / minute.
Monitor well for any signs of packing off or losses.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
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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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
R/U of CRT if hole conditions require.
R/U a fill up tool to fill casing while running if the CRT is not used.
Ensure all casing has been drifted to 8-1/2” on the location prior to running.
Note that 47# drift is 8.525”
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
Ensure bypass baffle is correctly installed on top of float collar.
Ensure proper operation of float equipment while picking up.
Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.4 Float equipment and Stage tool equipment drawings:
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12.5 Continue running 9-5/8” surface casing
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
1 centralizer every joint to ~ 1000’ MD from shoe
1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
Do not place tongs on ES cementer, this can cause damage to the tool.
Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8” surface casing
Centralizers: 1 centralizer every 3rd joint to 200’ from surface
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to surface
Ensure drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
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
Review test reports and ensure pump times are acceptable.
Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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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.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement is in the Stage 2 table in step 13.23.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
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
Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in
bottom cavity.
Single ram can be dressed with 2-7/8” x 5” VBRs
N/U bell nipple, install flowline.
Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
Confirm test pressures with PTD
Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swab kick at 9.5ppg BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Ensure MWD is R/U and operational.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 5” 19.5# S-135 DS50 & NC50.
Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
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15.10 8-1/2” hole section mud program summary:
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.
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.
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
Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
Dump and dilute as necessary to keep drilled solids to an absolute minimum.
MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique:
Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
RPM: 120+
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.
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every stand (confirm frequency with co man)
Monitor ECD, pump pressure & hookload trends for hole cleaning indication
Surveys can be taken more frequently if deemed necessary.
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.
Use ADR to stay in section.
Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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Drilling Procedure
Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
8-1/2” Lateral A/C:
I-32 has a 0.428 CF. This is an active OA polymer injector that will be shut-in. The
close approach interval is in the Schrader reservoir in the production interval. The
reservoir pressure is expected to be normal and there is no HSE risk.
J-08A has a 0.075 CF. This is a Schrader OB producer in the same pressure regime. The
risk is primarily financial as a collision would result in a bit trip and open hole sidetrack.
The plan is to geosteer away from J-08A to minimize the collision risk.
J-09A has a 0.737 CF. This well will has been reservoir P&A’d.
J-26L2 has a 0.275 CF. This multi-lateral has been P&A’d with cement. There is no
HSE risk associated with a collision.
L-48 has a 0.938 CF. L-48 is a Schrader OA injector. L-48 is a Schrader OA injector that
is and will be shut-in. The risk is primarily financial as a collision would result in a bit
trip and open hole sidetrack.
Schrader Bluff OBa Concretions: 4-6% Historically
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
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.
Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
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.
Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
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.
Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
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Drilling Procedure
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
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
Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
Rotate at maximum rpm that can be sustained.
Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud weight if necessary
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
If necessary, increase MW at shoe for any higher than expected pressure seen
Ensure fluid coming out of hole has passed a PST at the possum belly
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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Drilling Procedure
16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion)
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner with slotted liner, the following well control response procedure will be
followed:
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.
With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 5-1/2” and 4-1/2” liner running equipment.
Ensure 5-1/2” and 4-1/2” Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV.
Ensure the liner has been drifted on the deck prior to running.
Be sure to count the total # of joints on the deck before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 5-1/2” x 4-1/2” injection liner.
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.
Make up the lower 9,500’ of 4-1/2” and make up the remainder with 5-1/2”.
Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Use lift nubbins and stabbing guides for the liner run.
Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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Drilling Procedure
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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Drilling Procedure
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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Drilling Procedure
16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
Ensure 5” DP/HWDP has been drifted
There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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Drilling Procedure
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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Drilling Procedure
17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
Ensure wear bushing is pulled.
Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
Ensure all tubing has been drifted in the pipe shed prior to running.
Be sure to count the total # of joints in the pipe shed before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
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
3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
3-½” “XN” nipple at TBD (Set below 70 degrees)
1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
3-½” SGM-FS XDPG Gauge at TBD
1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
3-1/2” Sliding sleeve TBD
3-½” 9.3#/ft, L-80 EUE 8RD tubing
3-½” 9.3#/ft, L-80 EUE 8RD space out pups
1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
Tubing hanger with 3-1/2” EUE 8RD pin down
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Drilling Procedure
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i.Provide proper notification to the AOGCC for the right to witness the test.
ii. Complete form 10-426 and submit to the required recipients. Copy
nathan.sperry@hilcorp.com and ryan.thompson@hilcorp.com on the e-mail.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Pull BPV. Set TWC. Test tree to 5000 psi.
17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
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Drilling Procedure
19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 13C jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
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Drilling Procedure
20.0 Doyon 14 Diverter Schematic
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I-25 SB Injector
Drilling Procedure
21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
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Drilling Procedure
23.0 Days Vs Depth
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Drilling Procedure
24.0 Formation Tops & Information
MPU I-25 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1817 1750 2081 799 8.46
SV1 1998 1931 2400 879 8.46
UG4 2294 2227 2923 1010 8.46
UG_MB 3488 3421 5284 1534 8.46
SCHRADER NB 3737 3670 5827 1644 8.46
SCHRADER OBa 3999 3932 6957 1759 8.46
I-pad Data Sheet Formation Description
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25.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have not been seen on this 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:
AC: All wells have a clearance factor greater than 1.0 in the surface interval.
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. I-04A had 36ppm H2S (2012).
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I-25 SB Injector
Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (5) faults that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
8-1/2” Lateral A/C:
I-32 has a 0.428 CF. This is an active OA polymer injector that will be shut-in. The close
approach interval is in the Schrader reservoir in the production interval. The reservoir pressure is
expected to be normal and there is no HSE risk.
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Drilling Procedure
J-08A has a 0.075 CF. This is a Schrader OB producer in the same pressure regime. The risk is
primarily financial as a collision would result in a bit trip and open hole sidetrack. The plan is to
geosteer away from J-08A to minimize the collision risk.
J-09A has a 0.737 CF. This well will has been reservoir P&A’d.
J-26L2 has a 0.275 CF. This multi-lateral has been P&A’d with cement. There is no HSE risk
associated with a collision.
L-48 has a 0.938 CF. L-48 is a Schrader OA injector. L-48 is a Schrader OA injector that is and
will be shut-in. The risk is primarily financial as a collision would result in a bit trip and open
hole sidetrack.
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Drilling Procedure
26.0 Doyon 14 Layout
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Drilling Procedure
27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
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Page 54
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I-25 SB Injector
Drilling Procedure
29.0 Casing Design
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Drilling Procedure
30.0 8-1/2” Hole Section MASP
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Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
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.
Schrader Bluff Oil
MPU I-25 (Revised Application)
223-119
Milne Point
WELL PERMIT CHECKLIST
Company Hilcorp Alaska, LLC
Well Name:MILNE PT UNIT I-25
Initial Class/Type SER / 1WINJ GeoArea 890 Unit 11328 On/Off Shore On
Program SERField & Pool Well bore seg
Annular DisposalPTD#:2231190
MILNE POINT, SCHRADER BLFF OIL - 525140
NA1 Permit fee attached
Yes ADL025906, ADL025517, and ADL0255152 Lease number appropriate
Yes3 Unique well name and number
Yes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by 477, 477.0054 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
NA6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
Yes11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
Yes Area Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For
Yes15 All wells within 1/4 mile area of review identified (For service well only)
Yes Planned for 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 135'18 Conductor string provided
Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWs
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizons
Yes23 Casing designs adequate for C, T, B & permafrost
Yes Doyon 14 rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pit
NA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approved
Yes Halliburton collision scan shows 5 close approaches. HSE managed.26 Adequate wellbore separation proposed
Yes 16" Diverter below BOPE27 If diverter required, does it meet regulations
Yes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequate
Yes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulation
Yes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)
No Doyon 14 choke manifold 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)
Yes32 Work will occur without operation shutdown
Yes No H2S events documented on MPU I Pad.33 Is presence of H2S gas probable
Yes 30 wells reviewed within 1/4 mile34 Mechanical condition of wells within AOR verified (For service well only)
No H2S has been measured in MPU I-04A (36 ppm in 2012)35 Permit can be issued w/o hydrogen sulfide measures
Yes Reservoir anticipated to be normally pressured (8.46 ppg EMW). Could encounter pressures from offset injectors36 Data presented on potential overpressure zones
NA37 Seismic analysis of shallow gas zones
NA38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
SFD
Date
2/14/2024
Appr
MGR
Date
12/20/2023
Appr
SFD
Date
2/14/2024
Administration
Engineering
Geology
Geologic
Commissioner:
GCW
Date:Engineering
Commissioner:
JLC
Date Public
Commissioner
BWH
Date Revised Permit to Drill Application necessary because bottom-hole location has been changed by more than 500 feet. SFD
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-25
Hilcorp Alaska, LLC
Permit to Drill Number: 223-119
Surface Location: 2347’ FSL, 4040’ FEL, SEC. 33, T13N, R10E, UM, AK
Bottomhole Location: 536’ FSL, 745’ FEL, SEC. 17, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of January, 202. 31
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.01.31 15:25:37 -09'00'
Drilling Manager
12/08/23
Monty M
Myers
By Grace Christianson at 3:33 pm, Dec 08, 2023
223-119
DSR-12/14/23MGR20DEC2023
* BOPE test to 3000 psi. Annular to 2500 psi.
* MIT-IA to 3500 psi. 24 hour notice for state to witness.
* MIT-IA to 3500 psi after 10 days of stabilized injection. State to witness.
* 30 day pre-production with jet pump approved with passing
MIT-IA to 3500 psi.
50-029-23776-00-00
A.Dewhurst 26JAN24
*&:JLC 1/31/2024
1/31/24
1/31/24Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2024.01.31 15:25:58 -09'00'
I-25 AOR Map
•All wells that penetrate the Schrader Bluff OBa labelled at top OBa
intersection point
•Wells thatdid not petrate the Schrader Bluff Oba are labelled at TD
(NB is ~210’ shallower than Oba, Oa is ~67’ shallower that Oba)
•Green lines representthe footage in wells that are within the Schrader
Bluff OBA inside the ¼ mile radius of proposed injector, I-25
•Both Nb and Oa wells (above target zone) are shown on map but not
highlighted so map is less busy- included on AOR spreadsheet
Future I-26 Oba producer
(not drilled yet)
Future I-24 Oba producer
(not drilled yet)
Planned I-25
Oba Injector TD
I-25 AOR Map
•All wells that penetrate the Schrader Bluff OBa labelled at top OBa
intersection point
•Wells that did not petrate the Schrader Bluff Oba are labelled at TD
(NB is ~210’ shallower than Oba, Oa is ~67’ shallower that Oba)
•Green linesrepresentthe footage in wells that are within the Schrader
Bluff OBa inside the ¼ mile radius of proposed injector, I-25
•Both Nb andOa wells (above target zone) are shown on map but not
highlighted so map is less busy- included on AOR spreadsheet
•NOTE: FutureI-24 through I-26 Oba wells are almost directly
underneath I-31 through I-33 Oa wells
Planned I-25 Top
Schrader Bluff
Oba intersection
point
PTD API WELL STATUS
Top of SB
OBA (MD)
Top of SB
OBA (TVD)
CBL Top of
Cement
(MD)
CBL Top of
Cement
(TVD)
Schrader OBA
status Zonal Isolation
204-119 50-029-23214-00-00 MPU I-14 Oba Lateral 7586 3989 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%
washout, TOC is 4242' MD.
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1
bbls 15.8ppg class G cement through cement retainer.
204-119 50-029-23214-70-00 MPU I-14PB1 Oba Plug back 7586 3989 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%
washout, TOC is 4242' MD.
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1
bbls 15.8ppg class G cement through cement retainer.
204-119 50-029-23214-71-00 MPU I-14PB2 Oba Plug back 7586 3989 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%
washout, TOC is 4242' MD.
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1
bbls 15.8ppg class G cement through cement retainer.
204-120 50-029-23214-60-00 MPU I-14L1 OA Lateral N/A N/A N/A N/A N/A
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 45 bbls
15.8ppg class G through cement retainer.
204-121 50-029-23214-61-00 MPU I-14L2 NB Prod Lateral N/A N/A N/A N/A N/A
Annulus isolated via 7-5/8" cement job.
Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of
14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top of
retainer to 6,500' MD.
204-121 50-029-23214-72-00 MPU I-14L2PB1 NB Plug Back N/A N/A N/A N/A N/A
Annulus isolated via 7-5/8" cement job.
Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of
14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top of
retainer to 6,500' MD.
204-121 50-029-23214-73-00 MPU I-14L2PB2 NB Plug Back N/A N/A N/A N/A N/A
Annulus isolated via 7-5/8" cement job.
Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of
14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top of
retainer to 6,500' MD.
204-098 50-029-23212-60-00 MPU I-17 NB Prod Lateral 5069 3953 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-099 50-029-23212-60-00 MPU I-17L1 Oba Lateral 5069 3953 N/A N/A Open
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-100 50-029-23212-61-00 MPU I-17L2 OA Lateral N/A N/A N/A N/A N/A
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-064 50-029-23205-00-00 MPU J-26 NB Prod Lateral 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-064 50-029-23205-70-00 MPU J-26PB1 NB Plug back 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-064 50-029-23205-71-00 MPU J-26PB2 NB Plug back 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
Area of Review MPU I-25 SB OA
204-066 50-029-23205-60-00 MPU J-26L1** OBa Lateral 5556 4027 N/A N/A Closed Lateral isolated via iso sleeve and NB/OA reservoir abandonments.
204-067 50-029-23205-61-00 MPU J-26L2** OA Lateral N/A N/A N/A N/A Closed
OA reservoir P&A'd on 4/4/2022. Coil pumped 105 bbls 15.8ppg class G
cement. Washed to 5,100' MD.
197-200 50-029-228-25-00-00 MPU J-21 SB Producer, Shut In 5985 4000 N/A N/A Open
Cemented with 1471 sx PF 'E' and 258 sx Class 'G'. Final TOC reported 3.5'
from surface.
197-215 50-029-22832-00-00 MPU J-20 Schrader, P&A'd for J-20A 7848 3995 N/A N/A Closed
J-20 was abandoned via the J-20A sidetrack. J-20 was cemented to surface
via a 2 stage cement job with 84 bbls returned to surface on 12/2/1997.
197-208 50-029-22828-00-00 MPU J-17 SB Injector, Shut In 6479 4043 Surface surface Open
Well open to injection support in the NB, NC, OA and OB sands. Packers
isolate the NB/NC from the OA/OB.
195-159 50-029-22607-00-00 MPU J-19 P&A'd / Sidetracked 6625 4076 3693 2860 Closed
Balanced plug from 6390' MD to 5490'MD , 5450' MD to 4500' MD, and
4290' MD to 3600' MD.
204-073 50-029-23207-00-00 MPU J-25 P&A'd NB Lateral N/A N/A 2497 2472 N/A
Coil pumped 108 bbls of cmt in NB lateral on July 3, 2020. Cement tagged
at 3,887' SLMD on 7/13/2020.
194-101 50-029-22495-00-00 MPU J-09 P&A'd / Sidetracked 5776 4111 N/A N/A Closed
7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washout
estimated at 4,595' MD.
Cmt Rtnr @ 5,360', Could not inject beneath retainer, PT 7" to 3000psi f/
30 min, AOGCC approval to sidetrack well. J-09 P&A'd
199-114 50-029-22495-01-00 MPU J-09A OA Producer N/A N/A N/A N/A N/A
97sks of cement pumped with bonzai completion, packer depth 5,199',
cement valve 6,013'.
Reservoir abandoned 3/27/22 via coil tubing by pumping 50 bbls 15.8ppg
class G. Tagged TOC at 5,237' CTMD.
199-117 50-029-22497-01-00 MPU J-08A OB Prod Shut in 5788 4110 4714 3808 Open
Cement valve at 5,776' MD, pump 15 bbls, returns observed on BU TOC at
TOL @ 4,714' MD. Status of Oba will be closed using service coil pre-rig
204-136 50-029-23218-60-00 MPU I-19L1 Suspended OA Lateral N/A N/A 3334 2680 N/A Suspended
199-107 50-029-22952-00-00 MPU J-15 SB Injector P&A'd 6916 4159 N/A N/A Closed Abandoned. Full P&A performed in September/October 2020.
197-220 50-029-22834-00-00 MPU J-18 SB Injector Shut In 7952 4131 Surface surface Open**NB, OA, Ob sands open.
220-057 50-029-23684-00-00 MPU I-38 NB Producer N/A N/A N/A N/A N/A Not Open
220-057 50-029-23684-70-00 MPU I-38PB1 NB Plug back N/A N/A N/A N/A N/A Not Open
220-057 50-029-23684-71-00 MPU I-38PB2 NB Plug back N/A N/A N/A N/A N/A Not Open
220-060 50-029-23686-00-00 MPU I-39 NB Injector N/A N/A N/A N/A N/A Not Open
220-071 50-029-23689-00-00 MPU I-40 Nb Producer N/A N/A N/A N/A N/A Not Open
223-066 50-029-237-63-00-00 MPU I-31 OA Producer N/A N/A N/A N/A N/A Not Open
223-054 50-029-237-59-00-00 MPU I-32 OA Injector N/A N/A N/A N/A N/A Not Open
223-070 50-029-237-64-00-00 MPU I-33 OA Producer N/A N/A N/A N/A N/A Not Open
PTD API WELL STATUS
Top of SB
OBA (MD)
Top of SB
OBA (TVD)
CBL Top of
Cement
(MD)
CBL Top of
Cement
(TVD)
Schrader OBA
status Zonal Isolation
204-119 50-029-23214-00-00 MPU I-14 Oba Lateral 7586 3989 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%
washout, TOC is 4242' MD.
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1
bbls 15.8ppg class G cement through cement retainer.
204-120 50-029-23214-60-00 MPU I-14L1 OA Lateral N/A N/A N/A N/A Closed
Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 45 bbls
15.8ppg class G through cement retainer.
204-121 50-029-23214-61-00 MPU I-14L2 NB Prod Lateral N/A N/A N/A N/A N/A
Annulus isolated via 7-5/8" cement job.
Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of
14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top of
retainer to 6,500' MD.
204-098 50-029-23212-60-00 MPU I-17 NB Prod Lateral 5069 3953 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-099 50-029-23212-60-00 MPU I-17L1 Oba Lateral 5069 3953 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-100 50-029-23212-61-00 MPU I-17L2 OA Lateral N/A N/A N/A N/A Open
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-064 50-029-23205-00-00 MPU J-26 NB Prod Lateral 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-066 50-029-23205-60-00 MPU J-26L1** OBa Lateral 5556 4027 N/A N/A N/A Lateral isolated via iso sleeve and NB/OA reservoir abandonments.
204-067 50-029-23205-61-00 MPU J-26L2** OA Lateral N/A N/A
N/A N/A Open
OA reservoir P&A'd on 4/4/2022. Coil pumped 105 bbls 15.8ppg class G
cement. Washed to 5,100' MD.
197-200 50-029-228-25-00-00 MPU J-21 SB Producer, Shut In 5985 4000 N/A N/A Open
Cemented with 1471 sx PF 'E' and 258 sx Class 'G'. Final TOC reported 3.5'
from surface.
197-215 50-029-22832-00-00 MPU J-20 Schrader, P&A'd for J-20A 7848 3995 N/A N/A Closed
J-20 was abandoned via the J-20A sidetrack. J-20 was cemented to surface
via a 2 stage cement job with 84 bbls returned to surface on 12/2/1997.
197-208 50-029-22828-00-00 MPU J-17 SB Injector, Shut In 6479 4043 Surface surface Open
Well open to injection support in the NB, NC, OA and OB sands. Packers
isolate the NB/NC from the OA/OB.
195-159 50-029-22607-00-00 MPU J-19 P&A'd / Sidetracked 6625 4076 3693 2860 Closed
Balanced plug from 6390' MD to 5490'MD , 5450' MD to 4500' MD, and
4290' MD to 3600' MD.
204-073 50-029-23207-00-00 MPU J-25 P&A'd NB Lateral N/A N/A
2497 2472 Closed
Coil pumped 108 bbls of cmt in NB lateral on July 3, 2020. Cement tagged
at 3,887' SLMD on 7/13/2020.
194-101 50-029-22495-00-00 MPU J-09 P&A'd / Sidetracked 5776 4111 N/A N/A Closed
7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washout
estimated at 4,595' MD.
Cmt Rtnr @ 5,360', Could not inject beneath retainer, PT 7" to 3000psi f/
30 min, AOGCC approval to sidetrack well. J-09 P&A'd
199-114 50-029-22495-01-00 MPU J-09A OA Producer
N/A N/A
N/A N/A Open
97sks of cement pumped with bonzai completion, packer depth 5,199',
cement valve 6,013'.
Reservoir abandoned 3/27/22 via coil tubing by pumping 50 bbls 15.8ppg
class G. Tagged TOC at 5,237' CTMD.
199-117 50-029-22497-01-00 MPU J-08A OB Prod Shut in 5788 4110 4714 3808 Closed
Cement valve at 5,776' MD, pump 15 bbls, returns observed on BU TOC at
TOL @ 4,714' MD.
204-136 50-029-23218-60-00 MPU I-19L1 Suspended OA Lateral N/A N/A 3334 2680 Closed Suspended
Area of Review MPU I-25 SB OA
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199-107 50-029-22952-00-00 MPU J-15 SB Injector P&A'd 6916 4159 N/A N/A Closed Abandoned. Full P&A performed in September/October 2020.
197-220 50-029-22834-00-00 MPU J-18 SB Injector Shut In 7952 4131 Surface surface Open**NB, OA, Ob sands open.
220-057 50-029-23684-00-00 MPU I-38 NB Producer N/A N/A N/A N/A N/A Not Open
220-060 50-029-23686-00-00 MPU I-39 NB Injector N/A N/A N/A N/A N/A Not Open
220-071 50-029-23689-00-00 MPU I-40 Nb Producer N/A N/A N/A N/A N/A Not Open
223-066 50-029-237-63-00-00 MPU I-31 OA Producer N/A N/A N/A N/A N/A Not Open
223-054 50-029-237-59-00-00 MPU I-32 OA Injector N/A N/A N/A N/A N/A Not Open
223-070 50-029-237-64-00-00 MPU I-33 OA Producer N/A N/A N/A N/A N/A Not Open
215-120 50-029-23552-00-00 MPU L-48 OA Injector N/A N/A N/A N/A N/A Not Open
215-117 50-029-23550-00-00 MPU L-47 OA Producer N/A N/A N/A N/A N/A Not Open
TBD TBD MPU I-24 OBA Producer TBD TBD TBD TBD Will be Open Not Drilled
TBD TBD MPU I-26 OBA Producer TBD TBD TBD TBD Will be open Not Drilled
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Milne Point Unit
(MPU) I-25
Application for Permit to Drill
Version 1
12/06/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 BOP N/U and Test.................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ...................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 39
18.0 RDMO ...................................................................................................................................... 40
19.0 Post-Rig Work ......................................................................................................................... 41
20.0 Doyon 14 Diverter Schematic .................................................................................................. 42
21.0 Doyon 14 BOP Schematic ........................................................................................................ 43
22.0 Wellhead Schematic ................................................................................................................. 44
23.0 Days Vs Depth .......................................................................................................................... 45
24.0 Formation Tops & Information............................................................................................... 46
25.0 Anticipated Drilling Hazards .................................................................................................. 47
26.0 Doyon 14 Layout ...................................................................................................................... 51
27.0 FIT Procedure .......................................................................................................................... 52
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 53
29.0 Casing Design ........................................................................................................................... 54
30.0 8-1/2” Hole Section MASP ....................................................................................................... 55
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 57
Page 2
Milne Point Unit
I-25 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU I-25
Pad Milne Point “I” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff OBa Sand
Planned Well TD, MD / TVD 19,411’ MD / 4,234’ TVD
PBTD, MD / TVD 19,411’ MD / 4,234’ TVD
Surface Location (Governmental) 2347' FSL, 1269' FWL, Sec. 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551330 Y= 6009460
Top of Productive Horizon
(Governmental)1133' FNL, 2421' FWL, Sec 32, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 547215 Y= 6011233
BHL (Governmental) 536' FSL, 745' FEL, Sec 17, T13N, R10E, UM, AK
BHL (NAD 27) X= 549212 Y=6023473
AFE Drilling Days 21 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1360 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1760 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 33.7 ft = 67.4 ft
GL Elevation above MSL: 33.7 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2”5-1/2” 4.892”4.767”6.050”17 L-80 JFE Bear 7,740 6,290 397
4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
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 I-25 is a grassroots injector planned to be drilled in the Schrader Bluff OBa sand. I-25 is part of a
multi well program targeting the Schrader Bluff sand on I-Pad. I-25 will be pre-produced for 30 days.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff OBa sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in
the open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 13th, 2024, pending rig schedule.
Surface casing will be run to 6,955’ MD / 3,999’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 4-1/2” injection liner.
7. Run 3-1/2” tubing.
8. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
p
I-25 will be pre-produced for 30 days.
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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 I-25. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for pre-producing up to 30 days via a reverse circulating jet pump completion.
This will allow us to measure skin and evaluate the benefits of pre-producing our injectors in the future.
During flow back, Hilcorp will have a 24/7 man watch while the well is online and producing. Section 19
details the steps required to make this happen. Note also that the MIT-IA has been changed from 2,500 psi to
3,500 psi.
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 I-25 will utilize a newly set 20” conductor on I-Pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Use GWD until MWD surveys are clean.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OBa sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoff’s, increase in pump pressure, or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
x Gas hydrates have not been seen on I-Pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be
prepared for hydrates:
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x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x AC: All wells have a clearance factor greater than 1.0 in the surface interval.
12-1/4” hole mud program summary:
Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid
will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with
a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base
Permafrost
8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate
zone
PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total)
can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore.
Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to
reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of
the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with
caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 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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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.4 Float equipment and Stage tool equipment drawings:
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12.5 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to surface
x Ensure drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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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.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement is in the Stage 2 table in step 13.23.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x N/U bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.4ppg PP (swabbed kick at 9.5ppg BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is R/U and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 DS50 & NC50.
x Run a ported float in the production hole section.
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
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every stand (confirm frequency with co man)
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x 8-1/2” Lateral A/C:
x I-32 has a 0.444 CF. This is an active OA polymer injector that will be shut-in. The
close approach interval is in the Schrader reservoir in the production interval. The
reservoir pressure is expected to be normal and there is no HSE risk.
x J-08A has a 0.079 CF. This is a Schrader OB producer in the same pressure regime. The
risk is primarily financial as a collision would result in a bit trip and open hole sidetrack.
The plan is to geosteer away from J-08A to minimize the collision risk.
x J-09A has a 0.744 CF. This well will has been reservoir P&A’d.
x J-18 has a 0.781 CF. This is a Schrader injector that has been and will be shut-in. The
original Kuparuk completion was abandoned for a Schrader re-complete.
x J-26L1 has a 0.025 CF. This multi-lateral has been P&A’d with cement. There is no
HSE risk associated with a collision.
x Schrader Bluff OBa Concretions: 4-6% Historically
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
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x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion)
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner with slotted liner, the following well control response procedure will be
followed:
x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” crossover
installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW).
This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner.
x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 5-1/2” and 4-1/2” liner running equipment.
x Ensure 5-1/2” and 4-1/2” Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 5-1/2” x 4-1/2” injection liner.
x Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
x Uppermost 3,000’ will be 5-1/2”.
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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5-1/2” 17# L-80 JFE Bear
Casing OD Minimum Optimum Maximum
Operating Torque
5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs
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Drilling Procedure
4-1/2” 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD (Set below 70 degrees)
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-1/2” Sliding sleeve TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
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17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i.Provide proper notification to the AOGCC for the right to witness the test.
ii. Complete form 10-426 and submit to the required recipients. Copy
nathan.sperry@hilcorp.com and ryan.thompson@hilcorp.com on the e-mail.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Pull BPV. Set TWC. Test tree to 5000 psi.
17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
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19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 13C jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
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20.0 Doyon 14 Diverter Schematic
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21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
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22.0 Wellhead Schematic
Superceded
Corrected drawing at end of PTD. - mgr
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23.0 Days Vs Depth
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24.0 Formation Tops & Information
MPU I-25 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1817 1750 2081 799 8.46
SV1 1998 1931 2400 879 8.46
UG4 2294 2227 2923 1010 8.46
UG_MB 3488 3421 5284 1534 8.46
SCHRADER NB 3737 3670 5827 1644 8.46
SCHRADER OA 3999 3932 6957 1759 8.46
I-pad Data Sheet Formation Description
Page 47
Milne Point Unit
I-25 SB Injector
Drilling Procedure
25.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have not been seen on this 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 AC: All wells have a clearance factor greater than 1.0 in the surface interval.
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. I-04A had 36ppm H2S (2012).
Page 48
Milne Point Unit
I-25 SB Injector
Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 49
Milne Point Unit
I-25 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (5) faults that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
8-1/2” Lateral A/C:
x I-32 has a 0.444 CF. This is an active OA polymer injector that will be shut-in. The close
approach interval is in the Schrader reservoir in the production interval. The reservoir pressure is
expected to be normal and there is no HSE risk.
Page 50
Milne Point Unit
I-25 SB Injector
Drilling Procedure
x J-08A has a 0.079 CF. This is a Schrader OB producer in the same pressure regime. The risk is
primarily financial as a collision would result in a bit trip and open hole sidetrack. The plan is to
geosteer away from J-08A to minimize the collision risk.
x J-09A has a 0.744 CF. This well will has been reservoir P&A’d.
x J-18 has a 0.781 CF. This is a Schrader injector that has been and will be shut-in. The original
Kuparuk completion was abandoned for a Schrader re-complete.
x J-26L1 has a 0.025 CF. This multi-lateral has been P&A’d with cement. There is no HSE risk
associated with a collision.
Page 51
Milne Point Unit
I-25 SB Injector
Drilling Procedure
26.0 Doyon 14 Layout
Page 52
Milne Point Unit
I-25 SB Injector
Drilling Procedure
27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 53
Milne Point Unit
I-25 SB Injector
Drilling Procedure
28.0 Doyon 14 Choke Manifold Schematic
Page 54
Milne Point Unit
I-25 SB Injector
Drilling Procedure
29.0 Casing Design
Page 55
Milne Point Unit
I-25 SB Injector
Drilling Procedure
30.0 8-1/2” Hole Section MASP
Page 56
Milne Point Unit
I-25 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Milne Point Unit
I-25 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Built) (NAD 27)
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-2000
-1000
0
1000
2000
3000
4000
5000
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0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000
Vertical Section at 359.00° (2000 usft/in)
I-25 wp08 tgt02
I-25 wp08 heel tgt
I-25 wp08 tgt03
I-25 wp08 tgt04
I-25 wp08 tgt05
I-25 wp08 tgt06
I-25 wp08 tgt07
I-25 wp08 tgt08
I-25 wp08 tgt09
I-25 wp08 tgt10
I-25 wp08 tgt11
I-25 wp08 tgt12
I-25 wp08 tgt13
I-25 wp08 tgt14
I-25 wp08 tgt15
I-25 wp08 tgt16
I-25 wp08 tgt17
I-25 wp08 tgt18
I-25 wp08 tgt19
I-25 wp08 tgt20
I-25 wp08 tgt21
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
5 0 0
1 0 0 0
1 5 0 0
2000
2500
3000
3 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6000
6500
7000
7500
80
0
0
8500
90
0
0
95
0
0
10000
10
5
0
0
11000
115
0
0
12000
12500
13000
13500
14000
14500
15000
15500
16000
16500
17000
17500
18000
18500
19000
19411
MPU I-25 wp09
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 4º/100' : 500' MD, 499.63'TVD
Start Dir 4.2º/100' : 900' MD, 887.48'TVD
End Dir : 2028.94' MD, 1788.13' TVD
Start Dir 4.75º/100' : 3278.94' MD, 2496.14'TVD
End Dir : 3522.06' MD, 2625' TVD
Start Dir 5º/100' : 5208.23' MD, 3451.37'TVD
End Dir : 6764.32' MD, 3985.16' TVD
Start Dir 3º/100' : 6854.32' MD, 3993'TVD
End Dir : 6928.36' MD, 3998.02' TVD
Begin Geosteering
Total Depth : 19411.32' MD, 4234.4' T
SV6
Base Permafrost
SV1
UG4
UG_MB
SB_NB
SB_OBA
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: MPU I-25i
33.70
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 6009460.20 551330.41 70° 26' 11.7545 N 149° 34' 53.3768 W
SURVEY PROGRAM
Date: 2020-07-15T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1800.00 MPU I-25 wp09 (MPU I-25i) GYD_Quest GWD
1800.00 6950.00 MPU I-25 wp09 (MPU I-25i) 3_MWD+IFR2+MS+Sag
6950.00 19411.32 MPU I-25 wp09 (MPU I-25i) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
828.40 761.00 837.37 SV6
1817.40 1750.00 2080.61 Base Permafrost
1998.40 1931.00 2400.17 SV1
2294.40 2227.00 2922.76 UG4
3488.40 3421.00 5283.92 UG_MB
3737.40 3670.00 5827.07 SB_NB
3999.40 3932.00 6956.78 SB_OBA
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-25i, True North
Vertical (TVD) Reference:MPU I-25 as staked rkb @ 67.40usft
Measured Depth Reference:MPU I-25 as staked rkb @ 67.40usft
Calculation Method: Minimum Curvature
Project:Milne Point
Site:M Pt I Pad
Well:Plan: MPU I-25i
Wellbore:MPU I-25i
Design:MPU I-25 wp09
CASING DETAILS
TVD TVDSS MD Size Name
3999.31 3931.91 6955.00 9-5/8 9 5/8" x 12 1/4"
4234.40 4167.00 19411.32 4-1/2 4 1/2" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00
2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD
3 500.00 6.00 345.00 499.63 10.11 -2.71 3.00 345.00 10.15 Start Dir 4º/100' : 500' MD, 499.63'TVD
4 700.00 14.00 345.00 696.44 43.62 -11.69 4.00 0.00 43.82
5 900.00 20.44 328.63 887.48 96.90 -36.17 4.00 -45.00 97.51 Start Dir 4.2º/100' : 900' MD, 887.48'TVD
6 2028.94 55.50 269.10 1788.13 267.76 -638.70 4.20 -74.74 278.87 End Dir : 2028.94' MD, 1788.13' TVD
7 3278.94 55.50 269.10 2496.14 251.58 -1668.73 0.00 0.00 280.66 Start Dir 4.75º/100' : 3278.94' MD, 2496.14'TVD
8 3522.06 60.65 281.29 2625.00 270.82 -1873.50 4.75 66.85 303.47 End Dir : 3522.06' MD, 2625' TVD
9 5208.23 60.65 281.29 3451.37 558.59 -3314.84 0.00 0.00 616.36 Start Dir 5º/100' : 5208.23' MD, 3451.37'TVD
10 6764.32 85.00 0.10 3985.16 1637.60 -4103.68 5.00 88.90 1708.97 End Dir : 6764.32' MD, 3985.16' TVD
11 6854.32 85.00 0.10 3993.00 1727.26 -4103.52 0.00 0.00 1798.61 I-25 wp08 heel tgt Start Dir 3º/100' : 6854.32' MD, 3993'TVD
12 6928.36 87.22 0.11 3998.02 1801.13 -4103.39 3.00 0.28 1872.47 End Dir : 6928.36' MD, 3998.02' TVD
13 7468.43 87.22 0.11 4024.20 2340.57 -4102.34 0.00 0.00 2411.80
14 7717.47 92.20 0.25 4025.46 2589.52 -4101.56 2.00 1.60 2660.70
15 7927.47 92.20 0.25 4017.40 2799.36 -4100.64 0.00 0.00 2870.50 I-25 wp08 tgt03
16 8010.25 90.17 1.27 4015.69 2882.11 -4099.54 2.75 153.24 2953.22
17 8086.00 90.17 1.27 4015.47 2957.85 -4097.85 0.00 0.00 3028.91
18 8310.40 84.00 1.50 4026.88 3181.78 -4092.43 2.75 177.92 3252.72
19 8585.40 84.00 1.50 4055.63 3455.18 -4085.27 0.00 0.00 3525.95
20 8858.13 91.50 1.50 4066.33 3727.41 -4078.14 2.75 0.00 3798.02
21 9008.13 91.50 1.50 4062.40 3877.31 -4074.22 0.00 0.00 3947.82 I-25 wp08 tgt06
22 9226.84 95.39 5.35 4049.25 4095.15 -4061.20 2.50 44.53 4165.41
23 9568.08 95.39 5.35 4017.19 4433.40 -4029.53 0.00 0.00 4503.05
24 9743.73 91.00 5.35 4007.40 4607.98 -4013.18 2.50 179.98 4677.31 I-25 wp08 tgt08
25 10040.22 84.67 10.42 4018.61 4901.20 -3972.61 2.73 141.43 4969.79
26 10065.57 84.67 10.42 4020.97 4926.03 -3968.05 0.00 0.00 4994.53
27 10298.30 91.00 9.80 4029.76 5154.87 -3927.25 2.73 -5.56 5222.63
28 10548.30 91.00 9.80 4025.40 5401.19 -3884.71 0.00 0.00 5468.16 I-25 wp08 tgt10
29 10717.60 86.93 8.64 4028.46 5568.23 -3857.59 2.50 -164.16 5634.70
30 11220.36 86.93 8.64 4055.40 6064.56 -3782.13 0.00 0.00 6129.64 I-25 wp08 tgt11
31 11558.11 88.80 16.89 4068.02 6393.44 -3707.61 2.50 77.40 6457.17
32 14098.01 88.80 16.89 4121.40 8823.30 -2970.05 0.00 0.00 8873.80 I-25 wp08 tgt14
33 14106.97 89.01 16.82 4121.57 8831.88 -2967.45 2.50 -16.10 8882.32
34 15661.21 89.01 16.82 4148.40 10319.37 -2517.70 0.00 0.00 10361.74 I-25 wp08 tgt16
35 15956.77 88.22 9.47 4155.54 10606.90 -2450.53 2.50 -96.19 10648.05
36 16283.46 88.22 9.47 4165.66 10928.98 -2396.78 0.00 0.00 10969.15
37 16334.48 89.50 9.50 4166.67 10979.30 -2388.37 2.50 1.18 11019.31
38 17334.48 89.50 9.50 4175.40 11965.55 -2223.33 0.00 0.00 12002.53 I-25 wp08 tgt18
39 17449.05 86.79 8.57 4179.11 12078.62 -2205.35 2.50 -161.17 12115.27
40 18222.00 86.79 8.57 4222.40 12841.74 -2090.28 0.00 0.00 12876.26 I-25 wp08 tgt19
41 18527.02 89.70 1.52 4231.75 13145.20 -2063.49 2.50 -67.67 13179.22
42 18846.50 89.70 1.52 4233.40 13464.57 -2054.99 0.00 0.00 13498.38 I-25 wp08 tgt20
43 18924.94 89.91 3.47 4233.66 13542.93 -2051.58 2.50 83.86 13576.67
44 19411.32 89.91 3.47 4234.40 14028.41 -2022.11 0.00 0.00 14061.56 I-25 wp08 tgt21 Total Depth : 19411.32' MD, 4234.4' TVD
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
12750
13500
14250
So
u
t
h
(
-
)
/
N
o
r
t
h
(
+
)
(
1
5
0
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-7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000
West(-)/East(+) (1500 usft/in)
I-25 wp08 tgt21
I-25 wp08 tgt20
I-25 wp08 tgt19
I-25 wp08 tgt18
I-25 wp08 tgt17
I-25 wp08 tgt16
I-25 wp08 tgt15
I-25 wp08 tgt14
I-25 wp08 tgt13
I-25 wp08 tgt12
I-25 wp08 tgt11
I-25 wp08 tgt10
I-25 wp08 tgt09
I-25 wp08 tgt08
I-25 wp08 tgt07
I-25 wp08 tgt06
I-25 wp08 tgt05
I-25 wp08 tgt04
I-25 wp08 tgt03
I-25 wp08 heel tgt
I-25 wp08 tgt02
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
1 0 0 01500
1750
2000
2250
2500
27
5
0
30
0
0
325
0
35003750
4000
4234
MPU I-25 wp09
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 4º/100' : 500' MD, 499.63'TVD
Start Dir 4.2º/100' : 900' MD, 887.48'TVD
End Dir : 2028.94' MD, 1788.13' TVD
Start Dir 4.75º/100' : 3278.94' MD, 2496.14'TVD
End Dir : 3522.06' MD, 2625' TVD
Start Dir 5º/100' : 5208.23' MD, 3451.37'TVD
End Dir : 6764.32' MD, 3985.16' TVD
Start Dir 3º/100' : 6854.32' MD, 3993'TVD
End Dir : 6928.36' MD, 3998.02' TVD
Begin Geosteering
Total Depth : 19411.32' MD, 4234.4' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3999.31 3931.91 6955.00 9-5/8 9 5/8" x 12 1/4"
4234.40 4167.00 19411.32 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-25i
Wellbore: MPU I-25i
Plan: MPU I-25 wp09
WELL DETAILS: Plan: MPU I-25i
33.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009460.20 551330.41
70° 26' 11.7545 N 149° 34' 53.3768 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-25i, True North
Vertical (TVD) Reference:MPU I-25 as staked rkb @ 67.40usft
Measured Depth Reference:MPU I-25 as staked rkb @ 67.40usft
Calculation Method:Minimum Curvature
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Measured Depth (750 usft/in)
MPI-10
MPI-14L2
MPI-14
MPU I-32
MPI-13
MPU I-26 wp08
MPI-17L1
MPU I-39iMPI-12
MPI-17
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: MPU I-25i NAD 1927 (NADCON CONUS)Alaska Zone 04
33.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009460.20 551330.41 70° 26' 11.7545 N 149° 34' 53.3768 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-25i, True North
Vertical (TVD) Reference: MPU I-25 as staked rkb @ 67.40usft
Measured Depth Reference:MPU I-25 as staked rkb @ 67.40usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2020-07-15T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1800.00 MPU I-25 wp09 (MPU I-25i) GYD_Quest GWD
1800.00 6950.00 MPU I-25 wp09 (MPU I-25i) 3_MWD+IFR2+MS+Sag
6950.00 19411.32 MPU I-25 wp09 (MPU I-25i) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125
Measured Depth (750 usft/in)
MPI-14
MPU I-33
MPU I-32
MPI-13
MPU I-26 wp08
MPI-08
MPU I-24 wp04
MPU I-40
MPU I-39i
MPU I-39i
MPI-11
MPI-12L1MPI-12
NO GLOBAL FILTER: Using user defined selection & filtering criteria
33.70 To 19411.32
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-25i
Wellbore: MPU I-25i
Plan: MPU I-25 wp09
Ladder / S.F. Plots
1 of 2
CASING DETAILS
TVD TVDSS MD Size Name
3999.31 3931.91 6955.00 9-5/8 9 5/8" x 12 1/4"
4234.40 4167.00 19411.32 4-1/2 4 1/2" x 8 1/2"
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4.00
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F
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t
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7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250 21000
Measured Depth (1500 usft/in)
MPJ-15
MPI-09
MPI-14L2PB1
MPI-14L2
MPI-14
MPU I-23 wp06
MPU I-33
MPU I-32
MPJ-08A
MPJ-09A
MPJ-19
MPJ-25
MPJ-26L1
MPJ-26
MPJ-26L2
MPJ-17 MPU I-40 MPU I-39i
MPL-48
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
NOERRORS
WELL DETAILS:Plan: MPU I-25i NAD 1927 (NADCON CONUS)Alaska Zone 04
33.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009460.20 551330.41 70° 26' 11.7545 N 149° 34' 53.3768 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-25i, True North
Vertical (TVD) Reference: MPU I-25 as staked rkb @ 67.40usft
Measured Depth Reference:MPU I-25 as staked rkb @ 67.40usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2020-07-15T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1800.00 MPU I-25 wp09 (MPU I-25i) GYD_Quest GWD
1800.00 6950.00 MPU I-25 wp09 (MPU I-25i) 3_MWD+IFR2+MS+Sag
6950.00 19411.32 MPU I-25 wp09 (MPU I-25i) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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/
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7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250 21000
Measured Depth (1500 usft/in)
MPU I-32
MPU I-32
MPU I-32
MPJ-26L1
MPJ-26L2
NO GLOBAL FILTER: Using user defined selection & filtering criteria
33.70 To 19411.32
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-25i
Wellbore: MPU I-25i
Plan: MPU I-25 wp09
Ladder / S.F. Plots
2 of 2
CASING DETAILS
TVD TVDSS MD Size Name
3999.31 3931.91 6955.00 9-5/8 9 5/8" x 12 1/4"
4234.40 4167.00 19411.32 4-1/2 4 1/2" x 8 1/2"
1
Dewhurst, Andrew D (OGC)
From:Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent:Friday, January 26, 2024 14:52
To:Dewhurst, Andrew D (OGC); Joseph Lastufka
Cc:Rixse, Melvin G (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Roby, David S (OGC)
Subject:RE: [EXTERNAL] RE: MPU I-25 (Unapproved PTD #223-119) Updated AOR
Follow Up Flag:Follow up
Flag Status:Completed
Hi Andy,
The operaƟons engineer who performed the cement calculaƟons for the AOR is out but I’ve been able to dig up some
informaƟon. I’m coming up with a slightly deeper TOC.
There was an ES cementer in the string w/ the top at 6017.92’ MD. It looks like they pumped 51 bbls in stage 1 and 31
bbls in stage 2.
Using 7” casing w/ 8-1/2” hole and 20% washout, I’m calculaƟng 1,143.8’ column of cement. That would put TOC at
4874’ MD.
2
3
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
From: Dewhurst, Andrew D (OGC) [mailto:andrew.dewhurst@alaska.gov]
Sent: Thursday, January 25, 2024 4:02 PM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>
Subject: [EXTERNAL] RE: MPU I-25 (Unapproved PTD #223-119) Updated AOR
Nathan,
There is one well on the AOR list I have a quesƟon about: MPU J-09 (PTD 194-101).
Would you detail your TOC calculaƟon? I didn’t see any informaƟon in the well files regarding the actual 2nd stage 7”
casing cement volumes.
7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washout esƟmated at 4,595' MD.
Thanks,
Andy
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
4
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
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Monday, January 22, 2024 10:09
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>
Subject: MPU I-25 (Unapproved PTD #223-119) Updated AOR
Andrew,
Please see replacement Area of Review for MPU I-25 (Unapproved PTD #223-119). Please replace the previous version
with this updated version. If you have any quesƟons or need addiƟonal informaƟon, please let me know. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
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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
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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.
MPU I-25
X
223-119
MILNE POINT
SCHRADER BLUFF OIL POOL
WELL PERMIT CHECKLIST
Company Hilcorp Alaska, LLC
Well Name:MILNE PT UNIT I-25
Initial Class/Type SER / PEND GeoArea 890 Unit 11328 On/Off Shore On
Program SERField & Pool Well bore seg
Annular DisposalPTD#:2231190
MILNE POINT, SCHRADER BLFF OIL - 525140
NA1 Permit fee attached
Yes ADL025906, ADL025517, and ADL0255152 Lease number appropriate
Yes3 Unique well name and number
Yes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by 477, 477.0054 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
NA6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
Yes11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
Yes Area Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For
Yes15 All wells within 1/4 mile area of review identified (For service well only)
Yes Planned for 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 135'18 Conductor string provided
Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWs
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizons
Yes23 Casing designs adequate for C, T, B & permafrost
Yes Doyon 14 rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pit
NA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approved
Yes Halliburton collision scan shows 5 close approaches. HSE managed.26 Adequate wellbore separation proposed
Yes 16" Diverter below BOPE27 If diverter required, does it meet regulations
Yes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequate
Yes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulation
Yes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)
No Doyon 14 choke manifold 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)
Yes32 Work will occur without operation shutdown
Yes No H2S events documented on MPU I Pad.33 Is presence of H2S gas probable
Yes 30 wells reviewed within 1/4 mile34 Mechanical condition of wells within AOR verified (For service well only)
No H2S has been measured in MPU I-04A (36 ppm in 2012)35 Permit can be issued w/o hydrogen sulfide measures
Yes Reservoir anticipated to be normally pressured (8.46 ppg EMW). Could encounter pressures from offset injectors36 Data presented on potential overpressure zones
NA37 Seismic analysis of shallow gas zones
NA38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
ADD
Date
1/26/2024
Appr
MGR
Date
12/20/2023
Appr
ADD
Date
1/17/2024
Administration
Engineering
Geology
Geologic
Commissioner:Date:Engineering
Commissioner:Date Public
Commissioner Date
*&:JLC 1/31/2024
