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
TO: Jim Regg DATE:
P.I. Supervisor
SUBJECT:
FROM:
Petroleum Inspector
Section:6 Township:11N Range:9W Meridian:Seward
Drilling Rig:Hilcorp 151 Rig Elevation:54.33 ft RKB Total Depth:9290 ft MD Lease No.:ADL0017589
Operator Rep:Suspend:X P&A:NA
Conductor:30"O.D. Shoe@ 384 Feet Csg Cut@ NA Feet
Surface:9-5/8"O.D. Shoe@ 4743 Feet Csg Cut@ NA Feet
Intermediate:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet
Production:4-1/2"O.D. Shoe@ 9289 Feet Csg Cut@ NA Feet
Liner:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet
Tubing:4-1/2"O.D. Tail@ 4620 Feet Tbg Cut@ 4577 Feet
Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified
Fullbore Retainer 4541 ft 4301 ft 8.7ppg Drillpipe tag
Initial 15 min 30 min 45 min Result
Tubing
IA 3288 3255 3245
OA 0 0 0
Initial 15 min 30 min 45 min Result
Tubing
IA
OA
Remarks:
Attachments:
I traveled to location to witness the drillpipe tag and mechanical integrity test (MIT) of a cement plug to suspend the motherbore
prior to redrill. Per company rep 70 barrels (bbls) of cement was pumped beneath the retainer laying 30 bbls on top once
unstung. A tapered mill was used to tag top or cement (TOC) at 4301 ft MD (-12.5 barrels deep from proposed TOC) with 8k lbs
down-hard tag. Even with finding TOC substantially deeper than anticipated, 240 feet of cement above retainer was more than
adequate. Closing in the well they got a passing MIT of the plug and 9-5/8" casing to a target of 3000psi. Tubing was not cut but
pulled from seal bore assembly. Above bottom depth of plug is retainer set depth. No issues.
September 25, 2025
Austin McLeod
Well Bore Plug & Abandonment
N Cook Inlet Unit A-17
Hilcorp Alaska, LLC
PTD 2230310; Sundry 325-490
none
Test Data:
P
Casing Removal:
Ryan Freeland
Casing/Tubing Data (depths are MD):
Plugging Data (depths are MD):
rev. 3-24-2022 2025-0925_Plug_Verification_NCIU_A-17_am
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________N COOK INLET UNIT A-17
JBR 11/13/2025
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:0
Tested with 5" and 4-1/2" Test Joints. Rig was well kept and Crew worked efficienly During BOPE test. Tested LEL and H2s
alarms (calibrated) 8-27-25. Test #7 had leaking test equipment. Tighten up hose connection, retest pass. Weather rolled in and
caught the crew change chopper @0930 . I did not witness Blinds or chokes. Chart is attached.
Test Results
TEST DATA
Rig Rep:Sam WilsonOperator:Hilcorp Alaska, LLC Operator Rep:Ryan Freeland
Rig Owner/Rig No.:Hilcorp 151 PTD#:2230310 DATE:9/24/2025
Type Operation:WRKOV Annular:
250/2500Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSTS250924034237
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 9
MASP:
1832
Sundry No:
325-490
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
13 PNo. Valves
1 NTManual Chokes
2 NTHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8"P
#1 Rams 1 5-1/2" x 2-7/8 P
#2 Rams 1 Blinds NT
#3 Rams 1 5-1/2" x 3-1/2 P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 3 3-1/8,3-1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P1850
200 PSI Attained P24
Full Pressure Attained P145
Blind Switch Covers:Pall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P16@2080
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P15
#1 Rams P12
#2 Rams P12
#3 Rams P14
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
BOPE Test – Hilcorp 151
NCIU A-17 (PTD 2230310)
AOGCC Insp # bopSTS25092403437
9/24/2025
COMBUSTIBLE GAS DETECTION SYSTEM
Rig and Mud Pits - State Compliance Testing
FACILITY NAME:Tyonek Platform Rig 151
ROOM DESIGNATION:Rig, Shakers, Well Room
Instructions: Use this form to record combustible gas detector calibration data and alarm tests.
Cal Gas Cal Gas Verify
Gas-Free Applied Gas-Free Applied Sensativity Alarms at
Sensor Tag Name Faulted? Reading Reading Reading Reading With 50%20 and 40%
Or Location (%LEL) (%LEL) (%LEL) (%LEL)Gas Applied YES NO
Rig Gas Detectors
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
Sensativity
With 50%
Gas Applied YES NO
RIG H2S DETECTORS
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
Note:
Comb gas used 50% LEL
H2S gas used 50ppm
NOTES: All devices activated as they should, No Faults or Errors on system.
TECHNICIAN:Brendon Baker STATE INSPECTOR: Sully Sullivan Date:9/24/25
Aux Wellbay Room (Ch. 14)No 0 50 PPM 0 50 PPM
151 Rig Floor (Ch. 13)No 0 50 PPM 0 50 PPM
151 Cellar (Ch.12)No 0 50 PPM 0 50 PPM
Spare- Not in use (Ch.11)No 0 50 PPM 0 50 PPM
151 Shakers (Ch.10)No 0 50 PPM 0 50 PPM
151 Trip Tank (Ch. 9)No 0 50 PPM 0 50 PPM
(PPM)(PPM)(PPM)(PPM)
151 Pits (Ch. 8)No 0 50 PPM 0 50 PPM
Faulted?Reading Reading Reading Reading and 20 ppm
Cal Gas Cal Gas Verify
Gas-Free Applied Gas-Free Applied Alarms at 10
Aux Wellbay Room (Ch. 7)No 0 50%0 50%
151 Rig Floor (Ch.6)No 0 50%0 50%
151 Cellar (Ch. 5)No 0 50%0 50%
Spare-not in use (Ch. 4)No 0 50%0 50%
Conditions As Found Conditions As Left
151 Pits (Ch. 1)No 0 50%0 50%
151 Shakers (Ch. 3)No 0 50%0 50%
151 Trip Tank (Ch. 2)No 0 50%0 50%
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9,290 7,621
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Sean Mclaughlin
Contact Email:sean.mclaughlin@hilcorp.com
Contact Phone:(907) 223-6784
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
N Cook Inlet Unit A-17
N Cook Inlet Tertiary System Gas Same
7,000 7,621'5,389'1,832psi See schematic
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Drilling Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-031
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20188-00-00
Hilcorp Alaska, LLC
CO 68A
Length Size
Proposed Pools:
L-80
TVD Burst
4,620
8,430psi
MD
1,630psi
6,870psi
384
3,449
384
4,743
30"
9-5/8"
384
4,743
6,580 - 7,088
4,712
4,458 - 4,942
6,9994-1/2"
9/15/2025
4-1/2"
LTP & SSSV 4,577 (MD) 3,354 (TVD) & 452 (MD) 452 (TVD)
9,289
Perforation Depth MD (ft):
m
n
P
s
2
6
5
6
t c
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 2:32 pm, Aug 19, 2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.08.19 14:08:50 -
08'00'
Sean
McLaughlin
(4311)
325-490
A.Dewhurst 28AUG25
10-407
MGR20AUG2025
48 hour notice to AOGCC.
DSR-8/19/25
* BOPE test to 3000 psi. Annular to 2500 psi. 48 hour notice to AOGCC.
* State witness tag of cement abandonment plug. TOC ~ 4100' MD.
JLC 8/29/2025
Gregory C. Wilson Digitally signed by Gregory C. Wilson
Date: 2025.08.29 11:05:08 -08'00'08/29/25
RBDMS JSB 090425
Well Prognosis
Well: NCIU A-17
Date: 8/19/25
Well Name:NCIU A-17 API Number:50-883-20188-00-00
Current Status:Plug For Redrill
Estimated Start Date:9/15/25 Rig:Spartan 151
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:
Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:223-031
First Call Engineer:Sean Mclaughlin 907-223-6784
Second Call Engineer
AFE Number:
Attachments:
1.Current Schematic
2.Proposed Schematic
3.Proposed Operations
4.BOPE Schematic
_____________________________________________________________________________________
Updated By: JLL 04/22/25
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD:223-031
API: 50-883-20188-00-00
PBTD = 9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
8
6
7
Bel A
1
2
Tagged fill
@ 8,524
3/20/24
3
RKB = 66.6’
M-2
P1 - P2
Q-1
Ma
Na
La - Lb
Ka
Jb - Je
Hd - He
Bel B
Bel C
Bel D
Bel E
Bel E
Bel F
Bel G
Tagged @
7,536
03/28/25
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 4,743’
4-1/2"Prod Lnr 12.6 L-80 TXP 3.958”4,577’9,289’
4-1/2"Prod Tieback 12.6 L-80 HYD 533 3.958”Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’452’Giant Oil Tools TR-SCSSSV
2 1,009’1,000’ES Cementer
3 4,562’3,346’X Nipple 3.813” Profile
4 4,577’3,354’Liner hanger / LTP Assembly
5 4,620’3,379’Seal Stem
6 7,629'5,396'Composite Plug w/ 8' cement -TOC ~7,621 (4/15/24)
7 7,665'5,429'Composite Plug (04/14/24)
8 8,665’6,392’CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2”TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Aa 6,580'6,593'4,548'4,557'13'03/28/25 Open
Ab 6,612'6,655'4,570’4,602’43’03/27/25 Open
B 6,665’6,691’4,610’4,629’26’03/27/25 Open
Ba 6,703'6,729'4,638’4,658'26’03/27/25 Open
Bb 6,745'6,764'4,670’4,685’19’03/27/25 Open
B 6,773’6,826’4,692’4,734’53’03/27/25 Open
Bd 6,856'6,861'4,757'4,761'5'03/27/25 Open
Ca 6,933'6,948'4,819’4,830’15’03/27/25 Open
Cb 6,965’7,020’4,842’4,888’55’03/27/25 Open
Da 7,028'7,107'4,894’4,957’79’03/26/25 Open
Eb 7,169'7,225'5,007’5,052’56’03/26/25 Open
Ec 7,267'7,271'5,085'5,089'4'03/26/25 Open
Ed 7,280'7,300’5,096’5,112’20’03/26/25 Open
E 7,300’7,314’5,112’5,124’14’03/26/25 Open
Fa 7,326'7,338'5,134'5,143'10'03/26/25 Open
Fb 7,369'7,382'5,169'5,180'13'03/26/25 Open
GaL 7,437’7,467’5,226’5,252’30’03/26/25 Open
Isolated Perforation Details on Page 2
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’1,864’3.833 SFO-1 16 Dome 800 10/27/23
2 4,508’3,315’3.833 SFO-1 24 Orifice N/A 10/27/23
NOTE
7,275 RA Marker
8,280’RA Marker
Fish
7,621’CBP Remnants
_____________________________________________________________________________________
Updated By: JLL 04/22/25
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD:223-031
API: 50-883-20188-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Hd 7,642'7,651'5,408'5,416'9'04/14/24 Isolated 04/15/24
He 7,656'7,662'5,421'5,426'6'04/14/24 Isolated 04/15/24
Ib 7,842'7,862'5,595'5,614'20'03/29/24 Isolated 04/14/24
Ja 7,974'7,990'5,722'5,737'16'03/29/24 Isolated 04/14/24
Je 8,071'8,075'5,815'5,819'4'03/29/24 Isolated 04/14/24
Ka 8,111'8,127'5,854'5,869'16'03/23/24 Isolated 04/14/24
La 8,147'8,155'5,888'5,896'8'03/23/24 Isolated 04/14/24
Lb 8,219'8,223'5,958'5,962'4'03/22/24 Isolated 04/14/24
Ma 8,269'8,276'6,007'6,013'7'03/22/24 Isolated 04/14/24
M-2 8,299’8,309’6,036’6,045’10’12/17/23 Isolated 04/14/24
Na 8,374'8,378'6,108'6,112'4'03/22/24 Isolated 04/14/24
P-1 8,462’8,468’6,194’6,200’6’12/16/23 Isolated 04/14/24
P-2 8,506’8,520’6,237’6,250’14’12/16/23 Isolated 04/14/24
Q-1 8,568‘8,578‘6,297’6,307’10’12/16/23 Isolated 04/14/24
Q-5 8,674’8,684’6,400’6,410’10’12/11/23 Isolated 12/13/23
Q-6 8,706’8,716’6,432’6,441’10’12/10/23 Isolated 12/13/23
S-3 8,966’8,980’6,685’6,698’14’12/10/23 Isolated 12/13/23
_____________________________________________________________________________________
Updated By: CJD 08/19/25
Proposed Schematic
North Cook Inlet Unit
NCIU A-17
PTD:223-031
API: 50-883-20188-00-00
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 4,743’
4-1/2"Prod Lnr 12.6 L-80 TXP 3.958”4,577’9,289’
4-1/2"Prod Tieback 12.6 L-80 HYD 533 3.958”Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 1,009’1,000’ES Cementer
2 ±1,600’1,543’Whipstock
3 ±4,500’3,310’Cement Retainer (Pump 70 bbls) 50 bbl to bottom perf +20 bbl excess – 30
bbls on top ~400’ above retainer to ±4,100’ MD
4 4,577’3,354’Liner hanger / LTP Assembly
5 7,629'5,396'Composite Plug w/ 8' cement -TOC ~7,621 (4/15/24)
6 7,665'5,429'Composite Plug (04/14/24)
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2”TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Aa 6,580'6,593'4,548'4,557'13'03/28/25 To Be Plugged
Ab 6,612'6,655'4,570’4,602’43’03/27/25 To Be Plugged
B 6,665’6,691’4,610’4,629’26’03/27/25 To Be Plugged
Ba 6,703'6,729'4,638’4,658'26’03/27/25 To Be Plugged
Bb 6,745'6,764'4,670’4,685’19’03/27/25 To Be Plugged
B 6,773’6,826’4,692’4,734’53’03/27/25 To Be Plugged
Bd 6,856'6,861'4,757'4,761'5'03/27/25 To Be Plugged
Ca 6,933'6,948'4,819’4,830’15’03/27/25 To Be Plugged
Cb 6,965’7,020’4,842’4,888’55’03/27/25 To Be Plugged
Da 7,028'7,107'4,894’4,957’79’03/26/25 To Be Plugged
Eb 7,169'7,225'5,007’5,052’56’03/26/25 To Be Plugged
Ec 7,267'7,271'5,085'5,089'4'03/26/25 To Be Plugged
Ed 7,280'7,300’5,096’5,112’20’03/26/25 To Be Plugged
E 7,300’7,314’5,112’5,124’14’03/26/25 To Be Plugged
Fa 7,326'7,338'5,134'5,143'10'03/26/25 To Be Plugged
Fb 7,369'7,382'5,169'5,180'13'03/26/25 To Be Plugged
GaL 7,437’7,467’5,226’5,252’30’03/26/25 To Be Plugged
Isolated Perforation Details on Page 2
NOTE
7,275 RA Marker
8,280’RA Marker
Fish
7,621’CBP Remnants
_____________________________________________________________________________________
Updated By: CJD 08/19/25
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD:223-031
API: 50-883-20188-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Hd 7,642'7,651'5,408'5,416'9'04/14/24 Isolated 04/15/24
He 7,656'7,662'5,421'5,426'6'04/14/24 Isolated 04/15/24
Ib 7,842'7,862'5,595'5,614'20'03/29/24 Isolated 04/14/24
Ja 7,974'7,990'5,722'5,737'16'03/29/24 Isolated 04/14/24
Je 8,071'8,075'5,815'5,819'4'03/29/24 Isolated 04/14/24
Ka 8,111'8,127'5,854'5,869'16'03/23/24 Isolated 04/14/24
La 8,147'8,155'5,888'5,896'8'03/23/24 Isolated 04/14/24
Lb 8,219'8,223'5,958'5,962'4'03/22/24 Isolated 04/14/24
Ma 8,269'8,276'6,007'6,013'7'03/22/24 Isolated 04/14/24
M-2 8,299’8,309’6,036’6,045’10’12/17/23 Isolated 04/14/24
Na 8,374'8,378'6,108'6,112'4'03/22/24 Isolated 04/14/24
P-1 8,462’8,468’6,194’6,200’6’12/16/23 Isolated 04/14/24
P-2 8,506’8,520’6,237’6,250’14’12/16/23 Isolated 04/14/24
Q-1 8,568‘8,578‘6,297’6,307’10’12/16/23 Isolated 04/14/24
Q-5 8,674’8,684’6,400’6,410’10’12/11/23 Isolated 12/13/23
Q-6 8,706’8,716’6,432’6,441’10’12/10/23 Isolated 12/13/23
S-3 8,966’8,980’6,685’6,698’14’12/10/23 Isolated 12/13/23
Well Prognosis
Well: NCIU A-17
Date: 8/19/25
1. BOP N/U and Test
1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug
2. N/U to 11” 5M
3. N/U 13-5/8” x 5M BOP as follows (top down):
x 13-5/8” x 5M Shaffer annular BOP.
x 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in
btm cavity)
x 13-5/8” mud cross
x 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR)
x N/U pitcher nipple, install flowline.
x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or
“master valve”.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the
manual valve.
x 11” 5M Clamp hub adapter required
4. Test BOPE.
x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Ensure to leave “A” section side outlet valves open during BOP testing so pressure
does not build up beneath the TWC. Confirm the correct valves are opened!!!
x Test VBRs on 4.5” and 5” (if using 5” DP)test joints (3000 psi)
x Test Annular on 4.5” test joint (2500 psi)
x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE.
5. Pull Blanking plug and BPV
2. Preparatory Work and Mud Program
1. Mix 9.0 WBM mud for 8-1/2” hole section.
2. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s)
x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can
deliver 422 gpm at 115 spm.
x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both
pumps.
Well Prognosis
Well: NCIU A-17
Date: 8/19/25
3. 8-1/2” Production hole mud program summary:
x Primary weighting material to be used for the hole section will be barite to minimize
solids. Ensure enough barite is on location to weight up the active system 1ppg
above highest anticipated MW in the event of a well control situation.
x Pason PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, and
Toolpusher office.
System Type:LNSD WBM
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity
Yield
Point pH HPHT
1600’- TD 8.8-10.3 40-53 6-15 13-24 8.5-9.5 ч 11.0
System Formulation: 2% KCL/BDF-976/GEM GP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
DEXTRID LT
PAC L
BDF-976
GEM GP
BARACARB 5/25/50
STEELSEAL 50/100/400
BAROFIBRE
BAROTROL PLUS
SOLTEX
BAROID 41
ALDACIDE-G
0.905 bbl
7 ppb
0.2 ppb (9 pH)
1.0 ppb (as required 18 YP)
1-2 ppb
1 ppb
4 ppb
1.0% by volume
5 ppb (1.7 ppb of each)
5 ppb (1.7 ppb of each)
1.7 ppb
4.0 ppb
2 – 4 ppb
as needed
0.1 ppb
Well Prognosis
Well: NCIU A-17
Date: 8/19/25
4. Program mud weights are generated by reviewing data from producing & shut in offset wells,
estimated BHP’s from formations capable of producing fluids or gas and formations which
could require mud weights for hole stabilization.
5. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be
overbalanced and have the challenge to mitigate lost circulation.
3. Decomplete, Plug parent wellbore
Operation Steps:
1. Pull 4-1/2” tubing from PBR at 4577’.
2. Set wear bushing in wellhead. Ensure ID of wear bushing >8-1/2”.
3. PU 9-5/8” cement retainer and set at 4500’
4. Pump 70 bbls of 15.3# below the retainer
x ~50 bbl to bottom perforation and 20 bbls excess
x 4-1/2” CBP at 7629’ with 8’ cement and fill above, last tag at 7536’
x 4-1/2” CBP at 7665’
x 4-1/2” CIBP at 8665’
5. Unsting from retainer and lay in 30 bbls of cement above the retainer (~400’)
6. WOC, Tag cement (AOGCC notification required for opportunity to witness)
7. Pressure test 9-5/8” casing to 3000 psi.
4. Set Whipstock, Mill Window
Operation Steps:
1. Make up the WIS hydraulic set Whipstock.
2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with
whipstock assembly
¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock
assembly.
¾Avoid sudden starts and stops while running the whipstock.
¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to
spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that
slips are removed slowly when releasing the work string to RIH. These precautions are required to
Well Prognosis
Well: NCIU A-17
Date: 8/19/25
avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the
packer.
3. Orient whipstock as directed by the directional driller. The directional plan specifies 150 deg
ROHS.
4. Set the top of the whipstock at ~1600’ MD
x 9-5/8” Collars per casing tally.
Mill Window under drilling permit.
Well Prognosis
Well: NCIU A-17
Date: 8/19/25
BOPE Schematic
Sundry Application
Well Name______________________________
(PTD _________; Sundry _________)
Plug for Re-drill Well
Workflow
This process is used to identify wells that are suspended for a very short time prior to being
re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and
assigned a current status of "Suspended."
Step Task Responsible
1 The initial reviewer will check to ensure that the "Plug for Redrill" box in
the upper left corner of Form 10-403 is checked. If the "Abandon" or
"Suspend" boxes are also checked, cross out that erroneous entry and
initial it on the Form 10-403.
Geologist
2 If the “Abandon” box is checked in Box 15 (Well Status after proposed
work) the initial reviewer will cross out that checkbox and instead, check
the "Suspended" box and initial those changes.
Geologist
The drilling engineer will serve as quality control for steps 1 and 2.
Petroleum
Engineer
(QC)
3 When the RA2 receives a Form 10-403 with a check in the "Plug for
Redrill" box, they will enter the Typ_Work code "IPBRD" into the
History tab for the well in RBDMS. This code automatically generates
a comment in the well history that states "Intent: Plug for Redrill."
Research
Analyst 2
4 When the RA2 receives Form 10-407, they will check the History tab
in RBDMS for the IPBRD code. If IPBRD is present and there is no
evidence that a subsequent re-drill has been completed, the RA2 will
assign a status of SUSPENDED to the well bore in RBDMS. The RA2
will update the status on the 10-407 form to SUSPENDED, and date
and initial this change.
If the RA2 does not see the "Intent: Plug for Redrill" comment or code,
they will enter the status listed on the Form 10-407 into RBDMS.
Research
Analyst 2
5 When the Form 10-407 for the redrill is received, the RA2 will change the
original well's status from SUSPENDED to ABANDONED.
Research
Analyst 2
6 The first week of every January and July, the RA2 and a Geologist or
Reservoir Engineer will check the "Well by Type Work Outstanding"
user query in RBDMS to ensure that all Plug for Redrill sundried wells
have been updated to reflect current status.
At this same time, they will also review the list of suspended wells for
accuracy and assign expiration dates as needed.
Research
Analyst 2
Geologist or
Reservoir
Engineer
NCIU A-17
223-031
A.Dewhurst 28AUG25
325-490
A.Dewhurst 28AUG25
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________N COOK INLET UNIT A-17
JBR 04/03/2025
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:0 Test Results
TEST DATA
Rig Rep:Jeremy HartOperator:Hilcorp Alaska, LLC Operator Rep:John Conrad
Rig Owner/Rig No.:Fox 8 PTD#:2230310 DATE:2/28/2025
Type Operation:WRKOV Annular:
Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopBDB250302125121
Inspector Brian Bixby
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 3
MASP:
1832
Sundry No:
325-056
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 0 NA
Lower Kelly 0 NA
Ball Type 0 NA
Inside BOP 0 NA
FSV Misc 0 NA
5 PNo. Valves
2 PManual Chokes
0 NAHydraulic Chokes
0 NACH Misc
Stripper 1 2"P
Annular Preventer 0 NA
#1 Rams 1 Blind/Shear P
#2 Rams 1 2" Pipe Slip P
#3 Rams 0 NA
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 2 2"P
HCR Valves 0 NA
Kill Line Valves 2 2"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P2900
Pressure After Closure P2450
200 PSI Attained P33
Full Pressure Attained P61
Blind Switch Covers:PYes
Bottle precharge P
Nitgn Btls# &psi (avg)NA
ACC Misc NA0
NA NATrip Tank
NA NAPit Level Indicators
NA NAFlow Indicator
NA NAMeth Gas Detector
NA NAH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 1 P
Annular Preventer NA0
#1 Rams P16
#2 Rams P16
#3 Rams NA0
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke NA0
HCR Kill NA0
9
9
9 999
9
9
9
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2.Operator Name: 4.Current Well Class:5.Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8.Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9.Property Designation (Lease Number):10.Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9,290 N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14.Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16.Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Eric Dickerman
Contact Email:Eric.Dickerman@hilcorp.com
Contact Phone:(907) 564-4061
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
N Cook Inlet Unit A-17
N Cook Inlet Tertiary System Gas Same
7,000 7,152 4,993 1,832psi See schematic
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-031
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20188-00-00
Hilcorp Alaska, LLC
CO 68A
Length Size
Proposed Pools:
L-80
TVD Burst
4,620
8,430psi
MD
1,630psi
6,870psi
384
3,449
384
4,743
30"
9-5/8"
384
4,743
6,580 - 7,088
4,712
4,458 - 4,942
6,9994-1/2"
Other: CTCO / N2 Operations
2/18/2025
4-1/2"
LTP & SSSV 4,577 (MD) 3,354 (TVD) & 452 (MD) 452 (TVD)
9,289
Perforation Depth MD (ft):
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Gavin Gluyas at 8:56 am, Feb 04, 2025
325-056
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.02.04 06:50:41 -
09'00'
Dan Marlowe
(1267)
CT BOP test to 3000 psi.
BJM 2/12/25 SFD 2/11/2025
10-404
X
Perforate
*&:
2/18/2025
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.02.18 09:45:16
-09'00'
RBDMS JSB 021825
Mill Bridge Plugs, Perforate
Well: NCIU A-17
Well Name:NCIU A-17 API Number:50-883-20188-00
Current Status:Online gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:223-031
First Call Engineer:Eric Dickerman 307-250-4013
Second Call Engineer:Casey Morse 907-777-8322
Maximum Expected BHP:2,355 psi at 5,233’ tvd 0.45psi/ft to deepest proposed
Max. Potential Surface Pressure:1,832 psi Using 0.1 psi/ft gradient to surface
Brief Well Summary
NCIU A-17 was initially completed in December 2023 in the Lower Beluga. In March of 2024 perforations were
added uphole, however the Beluga Ib interval added water. A slickline BHA was left in the hole while
attempting to shut off the water, so the well was plugged back with a bridge plug at 7,665’ and the Upper
Beluga was perforated in multiple plug and perf iterations due to water from the Beluga Eb interval. There was
some gas that was bypassed in this interval due to the water production, which leads to this project to open up
more producing intervals to get the production rate above the unloading rate. If above the unloading rate, the
Beluga Eb sands may not have to be isolated. If below the unloading rate, the Beluga Eb water will be patched.
Objective:
Mill two composite bridge plugs to gain access to the deep Upper Beluga sands (Beluga Eb to Beluga Ga). Patch
Beluga Eb interval. Infill add perf the rest of the Upper Beluga.
Notes on wellbore condition:
- Tubing retrievable SSSV.
- 11/6/24:
o Slickline tagged fill at 7,034’ kb.
Proposed and existing perforations lie within the Tertiary System
Gas Pool as defined in CO 68A. SFD
Mill Bridge Plugs, Perforate
Well: NCIU A-17
Coiled Tubing Procedure:
1. MIRU Fox Energy offshore Coiled Tubing and pressure control equipment.
2. Pressure test lubricator to 250 psi low / 3,000 psi high.
a. Multiple wells planned for CT intervention on this Leg #1.
b. Hilcorp requests a weekly CT BOP test requirement while on this leg, instead of each well.
3. MU milling/cleanout BHA.
4. Mill out cement cap and bridge plug from 7,159’ and 7,192’ respectively, then continue in hole and mill
out the bridge plug at 7,364’. Push all plug remnants to bridge plug and cement cap at 7,621’.
a. Working fluid will be 6% KCl (8.6ppg).
b. Take returns to surface up the CT x tubing annulus.
c. Add foam and nitrogen as necessary to carry solids to surface.
d. Utilize gas lift to assist with hole cleaning.
5. RIH and blow well dry with nitrogen.
6. RDMO CT. Hand well over to Operations to test production.
Slickline procedure:
7. MIRU slickline and pressure control equipment.
8. Pressure test lubricator to 250 psi low / 3,000 psi high.
9. Make a dummy patch drift to PBTD.
10. RDMO Slickline.
Eline Patch procedure:
11. MIRU Eline and pressure control equipment.
12. Pressure test lubricator to 250 psi low / 3,000 psi high.
13. Set patch across the Beluga Eb perforations at 7,196’ – 7,225’ md.
14. RDMO Eline. Hand well over to Operations to test production.
Eline Perf procedure:
15. MIRU Eline and pressure control equipment.
16. Pressure test lubricator to 250 psi low / 3,000 psi high.
17. RIH and perforate Beluga gas sands from ± 6,545’ - ± 7,629’ md (± 4,523’ - ± 5,396’ tvd) per RE/Geo.
a. All proposed perforations are within Tertiary System Gas Pool.
b. Top pool is at top Sterling sands, bottom pool is below PBTD.
18. RDMO Eline.
CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water).
19. RU nitrogen to tubing and pressure test lines to 3,000psi (or higher if needed).
20. Pressure up on tubing and displace water back into formation.
21. MIRU Eline and pressure control equipment.
22. Pressure test lubricator to 250psi low / 3,000psi high.
23. Set 4-1/2” isolation plug or patch per OE.
24. RDMO Nitrogen and Eline.
Request is denied. Track record of BOP test
performance must be demonstrated before these
requests will be considered. -bjm
Mill Bridge Plugs, Perforate
Well: NCIU A-17
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. CT BOP Drawing (Fox energy)
4. Nitrogen procedure
_____________________________________________________________________________________
Updated By: JLL 05/02/24
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
11
7
8
9
10
1
2
Tagged fill
@ 8,524
3/20/24
3
RKB = 66.6’
M-2
P1 -P2
Q-1
Ma
Na
La -Lb
Ka
Jb -Je
Hd -He
Fb - Ga
Ed
Fa
Ec
Eb
Aa
Ab
Ac
Ba
Bb
Bd
Ca
Cd
Db
Cb
Da
Cc
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 7,159' 4,999' Cement Plug -TOC ~7,152'
7 7,192' 5,025' Composite Plug (4/19/24)
8 7,364' 5,165' Composite Plug (4/18/24)
9 7,629' 5,396' Composite Plug w/ 8' cement -TOC ~7,621 (4/15/24)
10 7,665' 5,429' Composite Plug (04/14/24)
11 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Aa 6,580' 6,593' 4,548' 4,557' 13' 04/20/24 Open
Ab 6,612' 6,617' 4,570' 4,574' 5' 04/20/24 Open
Ac 6,639' 6,645' 4,590' 4,595' 6' 04/19/24 Open
Ba 6,720' 6,729' 4,651' 4,658' 9' 04/19/24 Open
Bb 6,753' 6,758' 4,677' 4,681' 5' 04/19/24 Open
Bd 6,856' 6,861' 4,757' 4,761' 5' 04/19/24 Open
Ca 6,941' 6,945' 4,825' 4,828' 4' 04/19/24 Open
Cb 6,966' 6,970' 4,845' 4,848' 4' 04/28/24 Open
Cc 6,983' 6,987' 4,858' 4,861' 4' 04/28/24 Open
Cd 7,010' 7,020' 4,880' 4,888' 10' 04/19/24 Open
Da 7,028' 7,038' 4,894' 4,902' 10' 04/28/24 Open
Db 7,072' 7,088' 4,929' 4,942' 16' 04/19/24 Open
Eb 7,196' 7,216' 5,028' 5,044' 20' 04/17/24 Isolated 04/19/24
Eb 7,216' 7,225' 5,044' 5,052' 9' 04/16/24 Isolated 04/19/24
Ec 7,267' 7,271' 5,085' 5,089' 4' 04/16/24 Isolated 04/19/24
Ed 7,282' 7,286' 5,098' 5,101' 4' 04/16/24 Isolated 04/19/24
Fa 7,327' 7,337' 5,184' 5,143' 10' 04/16/24 Isolated 04/19/24
Fb 7,369' 7,382' 5,169' 5,180' 13' 04/16/24 Isolated 04/18/24
Ga 7,437' 7,445' 5,226' 5,233' 8' 04/16/24 Isolated 04/18/24
Hd 7,642' 7,651' 5,408' 5,416' 9' 04/14/24 Isolated 04/15/24
He 7,656' 7,662' 5,421' 5,426' 6' 04/14/24 Isolated 04/15/24
Ib 7,842' 7,862' 5,595' 5,614' 20' 03/29/24 Isolated 04/14/24
Ja 7,974' 7,990' 5,722' 5,737' 16' 03/29/24 Isolated 04/14/24
Je 8,071' 8,075' 5,815' 5,819' 4' 03/29/24 Isolated 04/14/24
Ka 8,111' 8,127' 5,854' 5,869' 16' 03/23/24 Isolated 04/14/24
La 8,147' 8,155' 5,888' 5,896' 8' 03/23/24 Isolated 04/14/24
Lb 8,219' 8,223' 5,958' 5,962' 4' 03/22/24 Isolated 04/14/24
Ma 8,269' 8,276' 6,007' 6,013' 7' 03/22/24 Isolated 04/14/24
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Isolated 04/14/24
Na 8,374' 8,378' 6,108' 6,112' 4' 03/22/24 Isolated 04/14/24
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Isolated 04/14/24
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Isolated 04/14/24
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Isolated 04/14/24
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ 3.833 SFO-1 16 Dome 800 10/27/23
2 4,508’ 3,315’ 3.833 SFO-1 24 Orifice N/A 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
_____________________________________________________________________________________
Updated By: EPD 02/03/25
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
12
7
9
10
11
8
1
2
Tagged fill
@ 8,524
3/20/24
3
RKB = 66.6’
M-2
P1 -P2
Q-1
Ma
Na
La -Lb
Ka
Jb -Je
Hd -He
Fb - Ga
Ed
Fa
Ec
Eb
Aa
Ab
Ac
Ba
Bb
Bd
Ca
Cd
Db
Cb
Da
Cc
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 7,159'4,999'Cement Plug -TOC ~7,152'
7 7,192'5,025'Composite Plug (4/19/24)
8 7,364'5,165'Composite Plug (4/18/24)
9 ±7,190 ±7,230’ Patch over Beluga Eb perforations
10 7,629' 5,396' Composite Plug w/ 8' cement -TOC ~7,621 (4/15/24) –Fish CBP remnants
11 7,665' 5,429' Composite Plug (04/14/24)
12 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Beluga ±6,545’ ±7,629’ ±4,523’ ±5,396 TBD Proposed
Aa 6,580' 6,593' 4,548' 4,557' 13' 04/20/24 Open
Ab 6,612' 6,617' 4,570' 4,574' 5' 04/20/24 Open
Ac 6,639' 6,645' 4,590' 4,595' 6' 04/19/24 Open
Ba 6,720' 6,729' 4,651' 4,658' 9' 04/19/24 Open
Bb 6,753' 6,758' 4,677' 4,681' 5' 04/19/24 Open
Bd 6,856' 6,861' 4,757' 4,761' 5' 04/19/24 Open
Ca 6,941' 6,945' 4,825' 4,828' 4' 04/19/24 Open
Cb 6,966' 6,970' 4,845' 4,848' 4' 04/28/24 Open
Cc 6,983' 6,987' 4,858' 4,861' 4' 04/28/24 Open
Cd 7,010' 7,020' 4,880' 4,888' 10' 04/19/24 Open
Da 7,028' 7,038' 4,894' 4,902' 10' 04/28/24 Open
Db 7,072' 7,088' 4,929' 4,942' 16' 04/19/24 Open
Eb 7,196' 7,216' 5,028' 5,044' 20' 04/17/24 Isolate w/Patch
Eb 7,216' 7,225' 5,044' 5,052' 9' 04/16/24 Isolate w/Patch
Ec 7,267' 7,271' 5,085' 5,089' 4' 04/16/24 Open
Ed 7,282' 7,286' 5,098' 5,101' 4' 04/16/24 Open
Fa 7,327' 7,337' 5,184' 5,143' 10' 04/16/24 Open
Fb 7,369' 7,382' 5,169' 5,180' 13' 04/16/24 Open
Ga 7,437' 7,445' 5,226' 5,233' 8' 04/16/24 Open
Hd 7,642' 7,651' 5,408' 5,416' 9' 04/14/24 Isolated 04/15/24
He 7,656' 7,662' 5,421' 5,426' 6' 04/14/24 Isolated 04/15/24
Ib 7,842' 7,862' 5,595' 5,614' 20' 03/29/24 Isolated 04/14/24
Ja 7,974' 7,990' 5,722' 5,737' 16' 03/29/24 Isolated 04/14/24
Je 8,071' 8,075' 5,815' 5,819' 4' 03/29/24 Isolated 04/14/24
Ka 8,111' 8,127' 5,854' 5,869' 16' 03/23/24 Isolated 04/14/24
La 8,147' 8,155' 5,888' 5,896' 8' 03/23/24 Isolated 04/14/24
Lb 8,219' 8,223' 5,958' 5,962' 4' 03/22/24 Isolated 04/14/24
Ma 8,269' 8,276' 6,007' 6,013' 7' 03/22/24 Isolated 04/14/24
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Isolated 04/14/24
Na 8,374' 8,378' 6,108' 6,112' 4' 03/22/24 Isolated 04/14/24
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Isolated 04/14/24
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Isolated 04/14/24
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Isolated 04/14/24
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ 3.833 SFO-1 16 Dome 800 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
KLU A-1
Well Head Rig Up
1
1
1
1
4 1/16" 15K Lubricator - 10 ft
100" Gooseneck
HR680 Injector Head
4 1/16" 10K Flow Cross, 2" 1502 10k Flanged
Valves
4 1/16" 15K Lubricator - 10 ft
API Flange Adapter 10K to 5K for riser/wellhead
Hydraulic Stripper 4 1/6" 15K
API Bowen CB56 15K
4 1/16" 10K Combi BOPs
Blind/Shear Ram
Pipe/Slip Ram
4 1/16" 10K bottom flange
4 1/16" 5K flanged Riser - 10 ft if necessary
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/28/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240528
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 5/13/2024 AK E-LINE CIBP/Cement
HV B-12 50231200310000 207123 4/26/2024 AK E-LINE PPROF
HV B-16A 50231200400100 222070 4/24/2024 AK E-LINE PPROF
HV B-17 50231200490000 215189 4/23/2024 AK E-LINE Perf
KTU 43-6XRD2 50133203280200 205117 5/10/2024 AK E-LINE Perf
LRU C-02 50283201900000 223057 5/8/2024 AK E-LINE Perf
MPU C-11A 50029213210100 221001 2/17/2024 AK E-LINE SetPacker
NCIU A-17 50883201880000 223031 4/13/2024 AK E-LINE Plug/Perf/GPT
Please include current contact information if different from above.
T38851
T38852
T38853
T38854
T38855
T38856
T38857
T38858NCIU A-17 50883201880000 223031 4/13/2024 AK E-LINE Plug/Perf/GPT
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.29 09:23:53 -08'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Operations
Development Exploratory
Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 9,290 feet See schematic feet
true vertical 7,000 feet N/A feet
Effective Depth measured 7,152 feet 4,577 feet
true vertical 4,993 feet 3,354 feet
Perforation depth Measured depth 6,580 - 7,088 feet
True Vertical depth 4,548 - 4,942 feet
Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 4,620 (MD) 3,379 (TVD)
4,577 (MD) 452 (MD)
Packers and SSSV (type, measured and true vertical depth) LTP 3,354 (TVD) TR-SCSSSV 452 (TVD)
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:Tertiary System Gas
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title:Contact Phone:
7,500psi
1,630psi
6,870psi
8,430psi
4,743 3,449
Burst Collapse
230psi
4,750psi
measured
TVD
Production
Liner
4,712
Casing
Structural
6,9999,289
384
4,743
384Conductor
Surface
Intermediate
30"
9-5/8"
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-031
50-883-20188-00-00
3. Address:
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0017589 / ADL0037831
N Cook Inlet / Tertiary System Gas
N Cook Inlet Unit A-17
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
N/A
358
Size
384
0115840
0 23751
53
324-116
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
2607
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Ryan Rupert
Ryan.Rupert@hilcorp.com
907 777-8503Operations Manager
N/A
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 9:52 am, May 22, 2024
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2024.05.22 07:36:19 -
08'00'
Dan Marlowe
(1267)
DSR-5/22/24
RBDMS JSB 053024
_____________________________________________________________________________________
Updated By: JLL 05/02/24
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
11
7
8
9
10
1
2
Tagged fill
@ 8,524
3/20/24
3
RKB = 66.6’
M-2
P1 -P2
Q-1
Ma
Na
La -Lb
Ka
Jb -Je
Hd -He
Fb - Ga
Ed
Fa
Ec
Eb
Aa
Ab
Ac
Ba
Bb
Bd
Ca
Cd
Db
Cb
Da
Cc
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 7,159' 4,999' Cement Plug -TOC ~7,152'
7 7,192' 5,025' Composite Plug (4/19/24)
8 7,364' 5,165' Composite Plug (4/18/24)
9 7,629' 5,396' Composite Plug w/ 8' cement -TOC ~7,621 (4/15/24)
10 7,665' 5,429' Composite Plug (04/14/24)
11 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Aa 6,580' 6,593' 4,548' 4,557' 13' 04/20/24 Open
Ab 6,612' 6,617' 4,570' 4,574' 5' 04/20/24 Open
Ac 6,639' 6,645' 4,590' 4,595' 6' 04/19/24 Open
Ba 6,720' 6,729' 4,651' 4,658' 9' 04/19/24 Open
Bb 6,753' 6,758' 4,677' 4,681' 5' 04/19/24 Open
Bd 6,856' 6,861' 4,757' 4,761' 5' 04/19/24 Open
Ca 6,941' 6,945' 4,825' 4,828' 4' 04/19/24 Open
Cb 6,966' 6,970' 4,845' 4,848' 4' 04/28/24 Open
Cc 6,983' 6,987' 4,858' 4,861' 4' 04/28/24 Open
Cd 7,010' 7,020' 4,880' 4,888' 10' 04/19/24 Open
Da 7,028' 7,038' 4,894' 4,902' 10' 04/28/24 Open
Db 7,072' 7,088' 4,929' 4,942' 16' 04/19/24 Open
Eb 7,196' 7,216' 5,028' 5,044' 20' 04/17/24 Isolated 04/19/24
Eb 7,216' 7,225' 5,044' 5,052' 9' 04/16/24 Isolated 04/19/24
Ec 7,267' 7,271' 5,085' 5,089' 4' 04/16/24 Isolated 04/19/24
Ed 7,282' 7,286' 5,098' 5,101' 4' 04/16/24 Isolated 04/19/24
Fa 7,327' 7,337' 5,184' 5,143' 10' 04/16/24 Isolated 04/19/24
Fb 7,369' 7,382' 5,169' 5,180' 13' 04/16/24 Isolated 04/18/24
Ga 7,437' 7,445' 5,226' 5,233' 8' 04/16/24 Isolated 04/18/24
Hd 7,642' 7,651' 5,408' 5,416' 9' 04/14/24 Isolated 04/15/24
He 7,656' 7,662' 5,421' 5,426' 6' 04/14/24 Isolated 04/15/24
Ib 7,842' 7,862' 5,595' 5,614' 20' 03/29/24 Isolated 04/14/24
Ja 7,974' 7,990' 5,722' 5,737' 16' 03/29/24 Isolated 04/14/24
Je 8,071' 8,075' 5,815' 5,819' 4' 03/29/24 Isolated 04/14/24
Ka 8,111' 8,127' 5,854' 5,869' 16' 03/23/24 Isolated 04/14/24
La 8,147' 8,155' 5,888' 5,896' 8' 03/23/24 Isolated 04/14/24
Lb 8,219' 8,223' 5,958' 5,962' 4' 03/22/24 Isolated 04/14/24
Ma 8,269' 8,276' 6,007' 6,013' 7' 03/22/24 Isolated 04/14/24
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Isolated 04/14/24
Na 8,374' 8,378' 6,108' 6,112' 4' 03/22/24 Isolated 04/14/24
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Isolated 04/14/24
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Isolated 04/14/24
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Isolated 04/14/24
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ 3.833 SFO-1 16 Dome 800 10/27/23
2 4,508’ 3,315’ 3.833 SFO-1 24 Orifice N/A 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
Well Name:NCIU A-17
API #:50883201880000 Field:North Cook Inlet Unit Start Date:3/22/2024
Permit #:223031 Sundry #:324-116 End Date:4/28/2024
3/22/2024
3/23/2024
3/28/2024
4/13/2024
4/14/2024
4/15/2024
Daily Operations:
Mobe Fox N2 hands to platform, PJSM/PTW, R/U pump lines, P/T 800/4450 good. pressure well up to 4k attempt to push fluid away,
R/U e-line PT lubricator 300/4000, good, RIH w/GPT tools. tag BTM @ 7680', fluid level @6157', POOH w/e-line, l/d tools install night
cap, pressure up tubing t/4350 w/N2, shut in for night.
PJSM/PTW, P/U 3 57" composite plug, RIH & set @7665', pick up free, RIH & tag, good, POOH, bleed WHP t/1130psi, Perforate BEL Hd
7642-7651', Perforate BEL He 7656 - 7662', bleed well down t/484, monitor no build, R/U N2 push fluid away. secure well for night
PJSM/PTW, RIH W/GPT tool string, tag composite plug @ 7665', fluid level@ 7657', RIH set Composite bridge plug @7629' Pickup off
plug clean, RIH tag plug on depth, good, RIH w/3.5" dump bailer loaded 5gal 17PPG cmt, dump on plug @7629', est top of cmt 7621',
POOH, secure well for night.
Well Operations Summary
R/U e-line PT t/250/3000 Good, RIH w/ 2.75" 6 SPF, 60% phasing, 15g shot guns t/ tag @ 8465' correlate
gun run #1, Pull gun up on depth, ccl 8362.6’, 11.4’ to top shot from ccl placing perfs @8374- 8378’ Beluga Na, Pre shot 1082psi, 5 min
1082, 10 min 1082, 15 min 1082, POOH all shots fired, & dry, gun run #2, RIH, Pull gun #2 into position ccl@8250.6, 18.4’ ccl, to top
shot, placing shots @8269-8276’,Beluga Ma, fire gun, Pre shot 1080psi, 5 min 1081, 10 min 1082, Pull gun #3 into position ccl@8208.8,
10.2’ ccl, to top shot, placing shots @8219-8223, Beluga Lb fire gun, Pre shot 1086psi, 5 min 1089, 10 min 1091, POOH, all shots fired,
damp & some mud. secure well for night.
P/U 2.75" 6 SPF, 60% phasing, 15g shot guns 4 & 5 on switch, RIH send correlation in, Perforate Beluga La 8147-8155', & Beluga Ka8111-
8127', Run GPT finding fluid @ 5720', flow well dropping pressure down f/1117-500psi shut in, Log accoss perforations then back up out
of fluid level, send logs in for evaluation, POOH secure well for night.
Held PJSM and approved PTW, M/u Gun Gamma, Shock Sub, and 5' and 16' 2-7/8" 6spf switch gas guns. RIH and Perf Beluga Jd sand at
(8,053'-8,058') and Beluga Ja sand at (7,974'-7990'). POOH bottom gun for Beluga Jd did not fire. Found det cord was kinked and didn't
burn. Order to forgo Beluga Jd sands. M/u Gun Gamma, Shock Sub, and 4' and 20' 2-7/8" 6spf switch gas guns. RIH and Perf Beluga Je
sand at (8071'-8075') and Beluga Ib sand at (7,842'-7,862'). POOH. Sticky pulling out. Guns covered in sand and silt. All shots fired. Well
is slugging muddy fluid, orders to R/d EL for night, flow and monitor well.
Page 1 of 2
Well Name:NCIU A-17
API #:50883201880000 Field:North Cook Inlet Unit Start Date:3/22/2024
Permit #:223031 Sundry #:324-116 End Date:4/28/2024
4/16/2024
4/17/2024
4/18/2024
4/19/2024
4/20/2024
4/28/2024
PTSM/PTW, P/U 2 3/4" 6 spf, 60 deg phasing guns, tagged fill @7160’, Perforated Beluga Ab 6612-6617’ & Beluga Aa 6580-6593', RIH
w/3 ½” bailer dumped 5 gal 17ppg cmt at 7159’ ETC 7152’, Run GPT log f/7100'up, fluid level 7018', POOH R/D e-line, turn well over to
production.
PT Lubricator 250psi/3000psi, Run GPT Fluid level at 7,016ft (Top perf at 6,580ft) tag at 7,099'. Perf Bel Da (7,028-7,038), Cc (6,983-
6,987), Cb (6,966-6,970). Secure well, SDFN
PJSM, PTW, wait on weather for plugs to arrive, SITP ~275psi, Run GPT, tag @ 7558' fluid level @ 7311', Push fluid away with lift gas,
@430psi, verify fluid level@7340', RIH correlate & set 3.57" composite Bridge plug @7364', pick up clean, RIH tag same good, flow well
monitor fluid level w/GPT tools in hole, secure well for night while production flows well. ( .628MSCFD 58psi @ 19:45 hours)
PJSM/PTW, P/U 2 3/4" 6spf, 60deg phasing perf guns, RIh SITP 74psi perforate Beluga Ga 7437-7445’, Beluga FB 7369-7382, Beluga Fa
7327-7337’, SITP 277psi, flow well, Shoot while flowing Beluga Ed 7282-7286’, Beluga Ec 7267-7271, Beluga Eb 7216-7225’, install night
cap, production flow well for night. 54psi .700MCFD
PJSM/PTW, P/U 2 3/4" 6spf, 60deg phasing perf guns, well flowing .450 54psi, perforate Bel Eb 7196-7216’ Flow rate dropped to 0 , RIH
tag fill @7565’ POOH, Run GPT find fluid level @6856’, push fluid away with lift gas t/~7340’, secure well, wait on weather for plugs to
arrive.
Daily Operations:
Well Operations Summary
PTSM/PTW, Run GPT, tagged fill @ 7330', fluid level @6770', push fluid down to 7230’ with lift gas, RIH set 3.57” plug @7192’, pick up
clean, RIH tag same good, bleed well down t/56psi, perforate w/2 3/4" 6 spf, 60 deg phasing guns, shoot Beluga Db 7072-7088’, Beluga
Cd 7010-7020’, Beluga Ca 6941-6945’, Beluga Bd 6856-6861, Beluga Bb 6753-6758’, Beluga Ba 6720-6729’, Beluga Ac 6639-6645’
flowing Tubing pressure 74psi, 2.34mmscfd. Secure well for night while production flows.
Page 2 of 2
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/21/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240521
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
END 3-07A 50029219110100 198147 5/11/2024 HALLIBURTON Coilflag
MPU E-19 50029227460000 197037 3/25/2024 READ CaliperSurvey
MPU F-66A 50029226970100 196162 5/8/2024 READ CaliperSurvey
MPI 1-27 50029216930000 187009 5/7/2024 READ PPROF
MPU L-17 50029225390000 194169 5/8/2024 READ CaliperSurvey
NCI A-12B 50883200320200 223053 5/2/2024 READ MAPP
NCI A-17 50883201880000 223031 5/3/2024 READ MAPP
PBU 11-41 50029237820000 224017 5/11/2024 HALLIBURTON RBT/Coilflag
PBU D-31B 50029226720200 212168 5/12/2024 HALLIBURTON RBT
PBU F-31A 50029216470100 212002 5/8/2024 READ CaliperSurvey
PBU J-19 50029216290000 186135 5/2/2024 HALLIBURTON RBT
PBU L-292 50029237510000 223025 5/6/2024 HALLIBURTON PPROF
Please include current contact information if different from above.
T38831
T38832
T38833
T38834
T38835
T38836
T38837
T38838
T38839
T38840
T38841
T38842
NCI A-17 50883201880000 223031 5/3/2024 READ MAPP
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.22 09:57:50 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/10/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240510-1
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 242-04 50283201640000 212041 3/11/2024 AK E-LINE Perf
LRU C-01RD 50283200610100 201168 4/26/2024 AK E-LINE Perf
LRU C-02 50283201900000 223057 4/28/2024 AK E-LINE Perf
MPU F-65 50029227526000 223121 5/3/2024 AK E-LINE HoistCut
MPU L-07 50029220280000 190037 4/26/2024 AK E-LINE Perf
NCIU A-17 50883201880000 223031 4/28/2024 AK E-LINE GPT/Perf
NCIU B-02 50883200900100 197210 4/29/2024 AK E-LINE PPROF
NCIU B-02 50883200900100 197210 5/4/2024 AK E-LINE PPROF
PAXTON 6 50133207070000 222054 4/13/2024 AK E-LINE GPT/CIBP/Perf
PAXTON 6 50133207070000 222054 4/16/2024 AK E-LINE GPT/CIBP/Perf
SRU 14B-27 50133206040000 212089 4/23/2024 AK E-LINE Caliper
SRU 32C-15 50133206130000 213070 4/24/2024 AK E-LINE Caliper
TBU M-15 50733204220000 190109 4/18/2024 AK E-LINE GPT/Puncher
TBU M-23 50733207190000 224018 5/1/2024 AK E-LINE CBL
Please include current contact information if different from above.
T38780
T38781
T38782
T38783
T38784
T38785
T38786
T38786
T38787
T38787
T38788
T38789
T38790
T38791
NCIU A-17 50883201880000 223031 4/28/2024 AK E-LINE GPT/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.13 15:31:19 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/1/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240501
Well API #PTD #Log Date Log Company Log Type AOGCC Eset#
HV B-13 50231200320000 207151 4/10/2024 YELLOW JACKET GPT-PERF
KU 13-06A 50133207160000 223112 3/27/2024 YELLOW JACKET GPT-PERF
KU 13-06A 50133207160000 223112 4/1/2024 YELLOW JACKET GPT-PLUG-PERF
KU 13-06A 50133207160000 223112 3/22/2024 YELLOW JACKET GPT-PERF
KU 33-08 50133207180000 224008 4/30/2024 YELLOW JACKET SCBL
KU 41-08 50133207170000 224005 4/23/2024 YELLOW JACKET SCBL
KU 41-08 50133207170000 224005 4/11/2024 AK E-LINE GPT/Perf/CIBP
MPU F-30A 50029226230100 213188 4/12/2024 READ CaliperSurvey
MPU S-13 50029230930000 202114 4/16/2024 READ Caliper Survey
NCI A-17 50883201880000 223031 3/22/2024 AK E-LINE Perf
Paxton 6 50133207070000 222054 4/14/2024 AK E-LINE GPT/Perf
PBU PTM P1-13 50029223720000 193074 4/8/2024 YELLOW JACKET CBL
SRU 232-15 50133207140000 223091 3/28/2024 YELLOW JACKET GPT-PLUG-PERF
SRU 232-15 50133207140000 223091 4/22/2024 YELLOW JACKET PLUG-PERF
SRU 241-33B 50133206960000 221053 4/12/2024 YELLOW JACKET GPT-PERF
SRU 241-33B 50133206960000 221053 4/4/2024 YELLOW JACKET GPT-PERF
Please include current contact information if different from above.
T38745
T38746
T38746
T38746
T38747
T38748
T38748
T38749
T38750
T38751
T38752
T38753
T38754
T38754
T38755
T38755
NCI A-17 50883201880000 223031 3/22/2024 AK E-LINE Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.05.13 09:32:35 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/19/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240419
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 4/5/2024 AK E-Line Perf
BRU 242-04 50283201640000 212041 3/20/2024 AK E-Line JB/PProf
NCIU A-17 50883201880000 223031 3/27/2024 AK E-Line GPT/Perf
PBU 05-02A 50029201440100 201241 4/6/2024 Halliburton PPROF
PBU 09-35A 50029213140100 193031 4/9/2024 Halliburton RBT
PBU 13-24A 50029207390100 204243 4/5/2024 Halliburton RBT
PBU B-14A 50029203490100 209059 4/2/2024 Halliburton RBT
PBU D-31B 50029226720200 212168 4/7/2024 Halliburton PERF
SRU 222-33 50133207150000 223100 3/27/2024 AK E-Line CIBP/Perf
SRU 224-10 50133101380100 222124 3/29/2024 AK E-Line CIBP/Perf
SRU 241-33B 50133206960000 221053 4/2/2024 AK E-Line CIBP
Please include current contact information if different from above
T38718
T38719
T38720
T38721
T38722
T38723
T38724
T38725
T38726
T38727
T38728
NCIU A-17 50883201880000 223031 3/27/2024 AK E-Line GPT/Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.04.19 14:54:13 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 3/20/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240320
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 19RD 50133205790100 219188 2/2/2024 AK E-LINE Perf
CLU 14 50133206840000 219078 12/11/2023 AK E-LINE Perf
IRU 41-01 50283200880000 192109 11/15/2023 AK E-LINE PERF
KBU 22-06Y 50133206500000 215044 12/29/2023 AK E-LINE PERF
MPU C-14 50029213440000 185088 3/4/2024 AK E-LINE Whipstock
MPU L-62 50029236850000 220059 3/3/2024 AK E-LINE TubingPunch
NCIU A-17 50883201880000 223031 12/13/2024 AK E-LINE GPT /Plug /Perf
Paxton 6 50133207070000 222054 2/27/2024 AK E-LINE Plug/Perf
PBU BORE V-109 50029231200000 202202 2/13/2024 AK E-LINE TubingPunch
Please include current contact information if different from above.
T38657
T38658
T38659
T38660
T38661
T38662
T38663
T38664
T38665
NCIU A-17 50883201880000 223031 12/13/2024 AK E-LINE GPT /Plug /Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.21 13:14:02 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 3/15/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240315
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut
BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf
BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP
BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF
BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf
GP ST 18742 37 (AN-
37) 50733203940000 187109 11/22/2023 AK E-LINE Perf
KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF
KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch
PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch
NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT
NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT
NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf
SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE
GPT-Cmnt-CIBP-
Perf
Please include current contact information if different from above.
T38630
T38630
T38631
T38632
T38633
T38634
T38635
T38636
T38637
T38638
T38639
T38640
T38641
NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.18 08:49:06 -08'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2.Operator Name: 4.Current Well Class:5.Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9,290 N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Ryan Rupert
Contact Email:Ryan.Rupert@hilcorp.com
Contact Phone:(907) 777-8503
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
N Cook Inlet Unit A-17
N Cook Inlet Tertiary System Gas Same
7,000 8,665 6,392 2,685psi 8,665
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-031
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20188-00-00
Hilcorp Alaska, LLC
CO 68A
Length Size
Proposed Pools:
12.6
TVD Burst
4,620
8,430psi
MD
1,630psi
6,870psi
384
3,449
384
4,743
30"
9-5/8"
384
4,743
8,299 - 8,578
4,712
6,036 - 6,307
6,9994-1/2"
Other: CTCO / N2 Operations
3/11/2024
4-1/2"
LTP & SSSV 4,577 (MD) 3,354 (TVD) & 452 (MD) 452 (TVD)
9,289
Perforation Depth MD (ft):
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 10:15 am, Feb 28, 2024
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2024.02.26 11:36:10 -
09'00'
Dan Marlowe
(1267)
324-116
SFD 2/29/2024 DSR-2/29/24BJM 2/29/24
CT BOP test to 3000 psi.
X
10-404
CT
*&:
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.03.01 13:46:15 -09'00'03/01/24
RBDMS JSB 030524
CT FCO + Perfs
Well: NCIU A-17
Well Name:NCIU A-17 API Number:50-883-20188-00-00
Current Status:Online gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:223-031
First Call Engineer:Ryan Rupert (907) 301-1736 (c)
Second Call Engineer:Dan Marlowe (907) 398-9904 (c)
Maximum Expected BHP:3,324 psi @ 6,392’ TVD 0.52psi/ft to PBTD
Max. Potential Surface Pressure: 2685 psi Using 0.1 psi/ft
Brief Well Summary
New drill NCIU A-17 came online in December-2023 with perforations in the lower beluga. The flowing WHP
slowly decreased since then, and the well has since sanded up and died. The well was close to the unloading rate
before. This sundry aims to cleanout solids, return the well to production, and add perfs. All existing and
proposed perforations below are within the Tertiary System Gas Pool.
The goal of this project is to clean out fill and add more Tertiary System Gas Pool perfs
Pertinent wellbore information:
- TRSSSV installed
- Live GLV’s currently installed
- Feb-2024 SL diagnostics
o SL bails from 2630’ to 3320’ MD over 4 days (clay / water mix)
o Breaks through, and drifts down to 7974’ MD with a 3” bailer (hard packed clay) perfs form
8300 – 8600’ MD
- 1/11/24: SL tags at 8605’ MD with a 1.75” bailer (CIBP at 8665’ MD)
- Dec-2023 plug / perf
o EL confirmed fluid level at 8810’ MD after N2 displace (required 4000psi)
o CIBP set at 8665’ MD
o Lowest 3 perf intervals shot with 2-3/4” guns as long as 14’
o GPT shows fluid level at 8530’ MD (10’ below P-2 perfs)
o No tags since CIBP set
CT FCO + Perfs
Well: NCIU A-17
Coiled Tubing FCO Procedure
1. MIRU Coiled Tubing and pressure control equipment
2. PT lubricator to 250psi low / 3000psi high
3. MU FCO BHA
4. RIH and cleanout to PBTD or as deep as practical
a. Working fluid will be water (8.33ppg or greater)
b. Take returns to surface up the CT x tubing annulus
c. Add foam and nitrogen as necessary to carry solids to surface
d. Can use GL to assist with hole cleaning
5. Once cleanout is completed, blow well down with nitrogen
6. RDMO CT
E-Line Perf procedure
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250psi low / 3000psi high
3. RIH and perforate Gas sands from ±6,546 - ±8,665’ MD (±4,523’ - ±6,392’ TVD) per RE/Geo
4. RDMO EL
CONTINGENCY: (if any zone makes unwanted solids or water)
1. RU nitrogen to tubing and PT lines to 4000psi
2. Pressure up on tubing and displace water back into formation
3. MIRU E-line and pressure control equipment
4. PT lubricator to 250psi low / 3000psi high (higher if needed due to N2 pressure)
5. Set 4-1/2” CIBP or patch per OE
6. RDMO Nitrogen and EL
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. CT BOP Drawing
4. Nitrogen procedure
CT BOP test to 3000 psi.
_____________________________________________________________________________________
Updated By: JLL 01/02/24
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
1
2
3
RKB = 66.6’
M-2
P1 -
P2
Q-1
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)Btm (TVD) FT Date Status
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Open
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Open
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Open
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Open
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ SFO-1 Dome 10/27/23
2 4,508’ 3,315’ SFO-1 Orifice 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
_____________________________________________________________________________________
Updated By: JLL 01/09/24
PROPOSED
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
1
2
3
RKB = 66.6’
M-2
P1 -
P2
Q-1
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
BEL ±6,546’ ±8,665’ ±4,523’ ±6,392’ ±2,119’ Future Proposed
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Open
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Open
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Open
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Open
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ SFO-1 Dome 10/27/23
2 4,508’ 3,315’ SFO-1 Orifice 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
SLB Stack Drawing
Not Drawn To Scale--- For Reference Only
2 1/16 10M
Flanged
Plug Valve
(Manual)
from KP
Well Floor
HR 580 Injector Head with 72" Gooseneck
4.06" 10K Conventional Stripper – 1.75"
C062 Pin Connection
Manual
2 1/16 10M
Provided by client
Blind/Shear
Pipe/Slip
4 1/16 10M
Combi BOP
Lubricator to
Injector Head
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2.Operator Name: 4.Current Well Class:5.Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9,290 N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Ryan Rupert
Contact Email:Ryan.Rupert@hilcorp.com
Contact Phone:(907) 777-8503
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Other: N2 Operations
1/24/2024
4-1/2"
LTP & SSSV 4,577 (MD) 3,354 (TVD) & 452 (MD) 452 (TVD)
9,289
Perforation Depth MD (ft):
8,299 - 8,578
4,712
6,036 - 6,307
6,9994-1/2"
30"
9-5/8"
384
4,743
MD
1,630psi
6,870psi
384
3,449
384
4,743
Length Size
Proposed Pools:
12.6
TVD Burst
4,620
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-031
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20188-00-00
Hilcorp Alaska, LLC
CO 68A
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
N Cook Inlet Unit A-17
N Cook Inlet Tertiary System Gas Same
7,000 8,665 6,392 2,685psi 8,665
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 9:36 am, Jan 10, 2024
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2024.01.10 08:44:10 -
09'00'
Dan Marlowe
(1267)
324-00
SFD 1/12/2024
10-404
Perforate
BJM 1/16/24 DSR-1/26/24*&:JLC 1/26/2024
Brett W. Huber, Sr.Digitally signed by Brett W. Huber,
Sr.
Date: 2024.01.26 15:20:10 -09'00'01/26/24
RBDMS JSB 012924
Perfs
Well: NCIU A-17
Well Name:NCIU A-17 API Number:50-883-20188-00-00
Current Status:Online gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:223-031
First Call Engineer:Ryan Rupert (907) 301-1736 (c)
Second Call Engineer:Dan Marlowe (907) 398-9904 (c)
Maximum Expected BHP:3,324 psi @ 6,392’ TVD 0.52psi/ft to PBTD
Max. Potential Surface Pressure: 2685 psi Using 0.1 psi/ft
Brief Well Summary
New drill NCIU A-17 came online in December-2023 with perforations in the lower beluga. The flowing WHP has
slowly decreased since then, and the well is almost at header pressure. The well is close to unloading rate, and
may need additional perfs shot soon. All existing and proposed perforations below are within the Tertiary System
Gas Pool.
The goal of this project is to add more Beluga perfs
Pertinent wellbore information:
- TRSSSV installed
- Live GLV’s currently installed and the IA is displaced to gas lift
- Dec-2023 plug / perf
o EL confirmed fluid level at 8810’ MD after N2 displace (required 4000psi)
o CIBP set at 8665’ MD
o Lowest 3 perf intervals shot with 2-3/4” guns as long as 14’
o GPT shows fluid level at 8530’ MD (10’ below P-2 perfs)
o No tags since CIBP set
All existing and proposed perforations below are within the Tertiary System
Gas Pool.Agree. SFD
Perfs
Well: NCIU A-17
Beluga E-Line Perf procedure
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250psi low / 3000psi high
3. RIH and perforate Beluga gas sands from ±6,546 - ±8,665’ MD (±4,523’ - ±6,392’ TVD) per RE/Geo
4. RDMO EL
CONTINGENCY: (if any zone makes unwanted solids or water)
1. RU nitrogen to tubing and PT lines to 4000psi
2. Pressure up on tubing and displace water back into formation
3. MIRU E-line and pressure control equipment
4. PT lubricator to 250psi low / 3000psi high (higher if needed due to N2 pressure)
5. Set 4-1/2” CIBP or patch per OE
6. RDMO Nitrogen and EL
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. Nitrogen procedure
±6,546 - ±8,665’ MD (±4,523’ - ±6,392’ TVD) p
_____________________________________________________________________________________
Updated By: JLL 01/02/24
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
1
2
3
RKB = 66.6’
M-2
P1 -
P2
Q-1
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)Btm (TVD) FT Date Status
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Open
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Open
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Open
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Open
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ SFO-1 Dome 10/27/23
2 4,508’ 3,315’ SFO-1 Orifice 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
_____________________________________________________________________________________
Updated By: JLL 01/09/24
PROPOSED
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
1
2
3
RKB = 66.6’
M-2
P1 -
P2
Q-1
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
BEL ±6,546’ ±8,665’ ±4,523’ ±6,392’ ±2,119’ Future Proposed
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Open
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Open
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Open
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Open
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ SFO-1 Dome 10/27/23
2 4,508’ 3,315’ SFO-1 Orifice 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): North Cook Inlet Unit
GL: N/A BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 101 (ft MSL)
22. Logs Obtained:
23.
BOTTOM
30" - 384'
4-1/2" L-80 6,999'
4-1/2" L-80 3,379'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
069592 687
12/29/2023 24
Flow Tubing
69
2672
N/A26720
N/A
N/A
452' MD / 452' TVD
9,290' MD / 7,000' TVD
9,206' MD / 6,918' TVD
1075' FNL, 1209' FWL, Sec 1, T11N, R10W, SM, AK
1054' FNL, 984' FWL, Sec 1, T11N, R10W, SM, AK
Choke Size:
9-5/8" 47# L-80 Surface 4,743' Surface 3,449' 12-1/4"
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
9,289' 3,353'
- 384'
Water-Bbl:
PRODUCTION TEST
12/17/2023
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
326951
326726
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
NCIU A-17October 22, 20231249' FNL, 973' FWL, Sec 6, T11N, R9W, SM, AK
126.6'
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2586979
SETTING DEPTH TVD
2587003
TOP HOLE SIZE
CBL 11-28-23, LWD (DGR, PWD, ADR, ALD, CTN, DDSR) + PB1, Tie In/Perf Logs
Tertiary System Gas Pool
ADL 17589 / ADL 37831
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
331992 2586730
50-883-20188-00-00July 20, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
12/10/2023 223-031 / 323-603
N/A
PACKER SET (MD/TVD)
Surface
Conductor
12.6#
Driven
Stg 1 L - 592 sx / T - 250 sx
12.6#
Surface
4,577'
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
L - 695 sx / T - 185 sx8-1/2"
TUBING RECORD
Tieback Assy.4,620'
Stg 2 L - 380 sx
Surface Tieback
N/A
SIZE DEPTH SET (MD)
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 1:55 pm, Jan 04, 2024
Completed
12/10/2023
JSB
RBDMS JSB 011824
GDSR-3/5/24
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval Bel M2 8299' 6036'
5060' 3634'
6554' 4529'
7163' 5002'
7586' 5357'
8078' 5822'
8336' 6071'
8390' 6124'
8439' 6172'
8539' 6269'
8746' 6471'
8834' 6556'
9010' 6727'
9276' 6978'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
INSTRUCTIONS
Bel U
Bel N
Bel O
Bel R
Bel S
Bel T
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Bel Q
Bel H
Sterling A
Bel K
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
Bel P
Bel A
TPI (Top of Producing Interval).
Authorized Name and
Bel E
Formation Name at TD:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
01/04/24
Monty M
Myers
_____________________________________________________________________________________
Updated By: JLL 01/02/24
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
Q-5 –
S-3
4/5
6
1
2
3
RKB = 66.6’
M-2
P1 -
P2
Q-1
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ Giant Oil Tools TR-SCSSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
6 8,665’ 6,392’ CIBP (12/13/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” TOC @ 4,630’ MD (CBL 11/28/23) TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)Btm (TVD) FT Date Status
M-2 8,299’ 8,309’ 6,036’ 6,045’ 10’ 12/17/23 Open
P-1 8,462’ 8,468’ 6,194’ 6,200’ 6’ 12/16/23 Open
P-2 8,506’ 8,520’ 6,237’ 6,250’ 14’ 12/16/23 Open
Q-1 8,568‘ 8,578‘ 6,297’ 6,307’ 10’ 12/16/23 Open
Q-5 8,674’ 8,684’ 6,400’ 6,410’ 10’ 12/11/23 Isolated 12/13/23
Q-6 8,706’ 8,716’ 6,432’ 6,441’ 10’ 12/10/23 Isolated 12/13/23
S-3 8,966’ 8,980’ 6,685’ 6,698’ 14’ 12/10/23 Isolated 12/13/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ SFO-1 Dome 10/27/23
2 4,508’ 3,315’ SFO-1 Orifice 10/27/23
NOTE
7,275 RA Marker
8,280’ RA Marker
Page 1/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:6/29/2023 End Date:
Report Number
1
Report Start Date
7/15/2023
Report End Date
7/16/2023
Operation
Install wing decks. R/U service lines, low/high pressure mud lines, and drain lines from upper pipe rack. Install handrails on crossway to upper deck. Install pollution pan
on flow box. Work the M/V Titan receiving Sperry and Baroid shacks, Misc hoses, vac unit and riser spool for diverter system.
Gave AOGCC 48 hr notice for diverter test at 1830 hrs.
Function tested rotary table. R/U hoses and lower deep well pump. Install stars on crossway. Cleaning and organizing sack room future mud product. Installing
landing/walkway from rig to Tyonek platform. Took on potable water. Working on rig acceptance check list.
Report Number
2
Report Start Date
7/16/2023
Report End Date
7/17/2023
Operation
Continue Installing temp landing/walkway from rig to Tyonek platform. Continue working on rig acceptance check list. organize main and cantilevers decks. Install st-80
base plate. Had meeting w/ platform and go over all simops operations. welder working on flow nipple.
Welder continues to work on flow nipple. wire in mud shack Mwd shack and platform gai-tronics to jack up. lay out choke and kill lines on platform deck. Start r/up gas
detection system.
Welder finished up on flow nipple modifications. Adjusted rotary table break. Rebuilt header valve on #2 mud pump. Work boat utilizing Tyonek crane to transfer over
cement silos due to tide direction. Received mud engineer, MWD and DD from boat.
Cont. working boat off-loading cement silos, off-load mud products and received 527 bbls of drill water. Install studs in annular and N/U 5' riser spool and flow nipple.
Organize decks in prep for drill pipe.Set 60' walk way and prep for welding. R/U drill water, fuel and black water lines from rig.
Report Number
3
Report Start Date
7/17/2023
Report End Date
7/18/2023
Operation
Continue install 60' gang way and prep for welding. continue R/U drill water, fuel and black water lines from rig to platform. finish nip/up flow nipple. Remove blind flanges
from pit dump valves. continue r/up mud lab and Mwd shack and equipment.
Stage 60' walk way and prep for welding. R/U drill water, fuel and black water lines from rig to platform.
Held pre-spud meeting and platform orientation for drilling hands. Continue prep rig for drill ready install 2nd set stairs off rig to platform. take on water in pits and start
mixing mud continue work rig acceptance chk list. Prep decks for drill pipe. continue r/up gas detection system.
Transfer ST-80 from deck and R/U on rig floor, Checked pre-charge in accumulator bottles, Off-loaded 5" DP from boat, Transferred fuel from Tyonek platform.
Transferred 2 cmt pods to rig bulk silos.
Cont. working boat off-loading 5" HWDP and 5" pup jts. Shift pods around and transfer remaining cmt from pods to rig bulk silos . Transfer water to pits and resume
making mud. Dressed out shakers and mud cleaner. Cont. working on rig acceptance check list.
Report Number
4
Report Start Date
7/18/2023
Report End Date
7/19/2023
Operation
Cont. working on rig acceptance check list. Install safety lines on gumbo shunt line. Repair hyd. fitting on annular and replac e fittings on knife valves. Install koomey hoses
to Annular and knife valve. Install hyd. fitting for ST-80. Cut window in sand trap.
Secure diverter to new deck pad eyes. R/U hoses on centrifuge. Function test ST-80 and check for leak-good. Hang off traveling block and slip/cut 97ft of 1-3/8" drill line.
Weld pad eyes on deck for Diverter tie down. Re-arange deck for morning boat MV-Titan.
Install hole covers in redundant return holes in flow ditch, Install 4" brass valves on 30" conductor. Cont building mud. Check and clean Y-screens on accumulator. Strap
and P/U 5", #19.5, s-135 DP and RIH T/193', Work boat.
Cont. to work boat. Cont. to P/U DP and RIH tagging @ 377'. POOH and rack back 3 stds leaving 1 across annular.. Charge accumulator and perform function test on
diverter system.(Annular=28 sec, Knife valve= 2 sec).
Report Number
5
Report Start Date
7/19/2023
Report End Date
7/20/2023
Operation
POOH and l/d mule shoe.
Cable f/crown bell is to short, measure and re-order new one at 90ft.
P/U 5"dp in mouse hole, rack in derrick.
While p/u dp noticed loose wraps on draw works. Hung off block, spooled off wraps w/tugger and re-spooled w/tension.
Test diverter w/AOGCC Rep. Austin McCleod witness, 21 sec. t/close 21-1/4" 2M annular and 7 sec. t/open 16" Knife valve on 5" std DP. Koomey draw down: 3100psi
start, 2100psi finish, 200psi attained 22sec. full system pressure 107sec. tested all gas alarms.
Re-move all bolts f/16" vent line and prep f/extension. Cont. building 8.9ppg mud as per Haliburton Mud Engineer.
Route hoses f/Brake cooling water t/tank P-20-0. Adjust hyd. controls valve on ST-80.
Resume P/U 5"dp in mouse hole, rack in derrick for a total of 36 stds at 00:00 hrs. Worked boat and assisted Tyonek crane operator with the 40/20' Diverter extensions.
Cont. P/U 5"dp in mouse hole, rack in derrick for a total of 53 stds of DP in the derrick. M/U . Completed the building of Spud Mud.
Service draw works and start P/U 5" HWDP and rack back in derrick.
Report Number
6
Report Start Date
7/20/2023
Report End Date
7/21/2023
Operation
Cont.lay out HWDP, strap and get OD/ID and FN. P/U 17jts and jar, rack same in derrick.
Test rig ESD/blackout shut down and bring back rig back on line.
Hold pre-job w/crew and Haliburton DD/MWD, p/u 12.25" BHA as per DD/MWD/Gyro t/377'.
Flood conductor w/FIW and check for leaks-flow box bottom plate leaking.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151Permit to Drill (PTD) #:223031
Page 2/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
Conduct 151 / Tyonek well control / abandon drill between jack-up and production. Well diverted and all accounted for in 14 minutes.
Re-seal flow box bottom plate, also leak at top of the annular, re-tighten same. Simop- rig up AK E-line and Gyro Data, repair Gai-tronics in drill shack, un-pin pop-off and
flush thru same. Pressure test mud pumps/mud lines to 2700 psi-good test.
Displace well over to 8.9 PPG spud mud @ 470 GPM, 700 PSI. Conducted meeting with gyro, DD and Driller about spud plan while d isplacing.
Oriented tool face as per DD and GYRO, Prior to drilling ahead attempted to break circulation and noticed there we no holes for returns in ditch, pumps off but drain back
allowed 2 bbls to flow over flow ditch into the inlet. Cut ditch holes and verified circulation.
Cleaned out conductor and 5' of new hole to 389' at 450 GPM, 620' PSI, No rotation, 1-2K WOB.
After drilling down stand and attempting to break out of the first stand noticed the saver sub was breaking out of the top drive and not DP. After further investigation we
discovered that the Saver sub was to long at 6 1/2". Grabbed the only 5 1/2" long saver sub and installed.
Made up and broke out of stump to verify saver sub length would work. No other issues.
Drill 12.25" surface hole F/389' T/513', 360 GPM, 590 PSI, 50 RPM, 2-3K TQ, 0-5K WOB. Sliding as directed by DD. Distance to P lan 1.86', High 1.86', Left/Right 0'.
Report Number
7
Report Start Date
7/21/2023
Report End Date
7/22/2023
Operation
Daily Discharge= 304 BBLS\nCumulative Discharge= 304 BBLS\nDaily Metal= 0 LBS\nCumulative Metal= 0 LBS
Cont. slide drilling f/513' t/925', 567gpm, 1100psi, 42%flow, p/u wt=98k, s/o wt=95k.
gyro survey every 30ft t/691' w/15ft separation f/A-13, 16.6ft separation f/B-3 and 23ft f/bit w/both. Last survey @785' w/26.3 ft f/nearest well.
Drill f/925' t/946', 50rpm, 572gpm, 1050psi, 44%flow, p/u wt=98k, s/o wt=95k.
Hole unloading and causing ditches to fill and splash fluid out, shut dwn pmps and reciprocate pipe, clear ditches while workin g pmps up 575gpm and back to bottom to
obtain survey.
Attempt to pump up survey @946', no good.
Cont. clean ditches and possum belly, so we can survey and drill 1 std dwn t/Pump out of the hole. Attempted to circulate with returns to 1 shaker. Opened up inspection
hatch and found return line to shaker 2 and mud cleaner packed off with gravel. Cleaned out and verified good circulation.
CBU @ 575 GPM, 1050 PSI, No rotation while slowly pulling piipe up. Heavy gravel at the start and tapered off to minimal towards the end of BU.
Ran Gyro, made a hook and attempted to achieve clean survey @ 940' Bit depth, 879' MWD depth with no success. Resumed drilling F/946' T/1415', (1379' TVD) 52 FPH
AROP, 600 GPM, 1150 PSI, 0-5K WOB Sliding, 600 GPM, 1180 PSI, 60 RPM, 3-4K TQ, 3-5K WOB Rotating.
Report Number
8
Report Start Date
7/22/2023
Report End Date
7/23/2023
Operation
Last Gyro survey Depth 1255', 22.21 INC, AZM with 131.26' separation F/A-13 and 107.68' F/B-03. Distance to plan= 11.73', High 10.79', Left 4.59'.
Cont. to drill/slide as per DD/MWD f/1409 t/1415, 650gpm, 1200psi, p/u=100k, s/o=90k, 3-4k=wob, survey-good.
Daily Discharge= 169 BBLS\nCumulative Discharge= 518 BBLS\nDaily Metal= 0 LBS\nCumulative Metal= 0 LBS
R/D Gyro/Data and AK E-line. Circ. B/U w/reciprocating, 650gpm, 1200psi, p/u=100k, s/o=90k.
Pump out of the hole w/full drilling rates f/1415 t/360, 650gpm, 1200psi, working casing f/boat.
Circ. conductor clean staging pumps up f/650-800gpm, 1500psi, 50rpm, 2k trq. Increase in cuttings and pea gravel at B/U, circ. until clean.
Monitor well and C/O break out cable.
POOH on elevators, racking back HWDP, Flex DC and work BHA as per Haliburton DD/MWD. L/D 12-1/4 mill tooth bit, P/U 12-1/4 Kymera bit, L/D UBHO, P/U 8EWR-P4
collar and down load same, while cleaning flow ditches.
Orient tool face and TIH f/90' t/369', Performed shallow hole test- good test. Ran pump 3 to verify functioning found stroke counter not working- fixed issue. RIH F/369
T/1355'. Wash down to 1415' tagging 3' of fill. Trouble shoot MWD stroke counter on pumps.
Bit Dull Grading = 0-0-WT-A-0-I-NO-BHA.
Cont. RIH F/369 T/1355'. Wash down F/1355' T/1415' tagging 3' of fill. Trouble shoot MWD stroke counter on pumps.
Drill 12 1/4" Surface hole F/1415; T/1670', ( 85' FPH Ave ROP ) 680 GPM, 1981 PSI, 21 PSI DIFF, 0-5K WOB sliding, Rotating 1965 PSI, 23 PSI Diff, 60 RPM, 4-5K TQ,
4K WOB rotating. PU 105K, SO 100K, ROT 102K.
Cont. Drilling 12 1/4" Surface hole F/1670; T/2095', (1918' TVD) ( 71' FPH Ave ROP ) 700 GPM, 2120 PSI, 90 PSI DIFF, 5-12K WOB sliding, Rotating 2130 PSI, 100 PSI
Diff, 60 RPM, 5-6K TQ, 5-12K WOB rotating. PU 110K, SO 100K, ROT 110K.
Report Number
9
Report Start Date
7/23/2023
Report End Date
7/24/2023
Operation
Cont. Drilling 12 1/4" Surface hole F/2095' T/2576' (2230' TVD) Total 481' (87' AROP) 704 GPM, 2250 PSI, 50-80 PSI Diff, 5-11k WOB while sliding, 60 RPM, 5-6K TQ,
5-10K WOB, PU 120K, SO 100K, ROT 110K.
Pumped 30 BBL hi-vis sweep at 1920' back with no increase in cuttings. At 2050' hole unloaded clay and sand running over shakers, backed pumps off to 550 GPM and
control drilled until shakers were able to handle full rate. Distance to Plan 12.21', Low .35', Left 12.21'.
Daily Discharge= 184 BBLS\nCumulative Discharge= 702 BBLS\nDaily Metal= 0 LBS\nCumulative Metal= 0 LBS
Circulated Hi-vis sweep STS @ 700 GPM, 2100 PSI, 60 RPM, 5K TQ working pipe F/2576' T/2482', Shut down and monitor well= static.
POOH on elevators F/2576' T/1795, had 30k over pull, Pumped OOH F/1796' T/1355' working through tight spots.
RIH on elevators F/1355' T/2576' washing down to bottom.
Drill 12.25" Surface Hole F/2576' -T/2750' Total 174' (AROP 116') 710 GPM= 2100/2060 psi on/off, 60 RPM= 7K/6K TQ on/off, WOB= 2-8k. MW in/out 9.0/9.1, ECD=
9.45ppg, P/U 122K, S/O 100K, ROTW 115K. Backreaming Full Stands prior to connections.
Drill 12.25" Surface Hole F/2750' -T/3239' (2612' TVD) Total 489' (AROP 82') 710 GPM= 2385/2330 psi on/off, 60 RPM= 9K/8K TQ on/off, WOB=3-10. MW in/out 9.1/9.3,
ECD= 9.53 ppg, P/U 130K, S/O 110K, ROTW 115K. Back reaming Full Stands prior to connections. Pumping sweeps every 500'.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 3/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
Drill 12.25" Surface Hole F/3239' -T/3611' (2827' TVD) Total 372' (AROP 93') 710 GPM= 2448/2410 psi on/off, 60 RPM= 9K/8K TQ on/off, WOB=3-7. MW in/out 9.2/9.4,
ECD= 9.66 ppg, P/U 140K, S/O 115K, ROTW 120K. Back reaming Full Stands prior to connections Pumping sweeps every 500 ft.
Pumped sweep at 3515' while drilling last std down. Distance to plan 24.53', Low 20.10', Left 14.07'.
CBU @ 700 GPM, 2475 PSI, 50 RPM, 8K TQ working pipe F/3611' T/3515', Sweep back on time with 30% increase in cuttings. Shut down and monitor well= static.
POOH on elevators F/3611' T/2570', RIH 1 std to 2673'. PU 142K, SO 110K. Observed calculated displacement during the trip out.
Report Number
10
Report Start Date
7/24/2023
Report End Date
7/25/2023
Operation
Service top drive at the top of short trip @2579'.
Daily Discharge= 230 BBLS\nCumulative Discharge= 932 BBLS\nDaily Metal= 0 LBS\nCumulative Metal= 0 LBS
TIH t/3520', monitoring displacement on TT. Wash down last std t/3610', @ 714gpm, 2400psi, 60rpm and 6-7k trq.
Drill/slide 12-1/4" surface hole f/3610' -t/4019', Total 409' (AROP 90fph) 714gpm, 2500psi, 70rpm, 9-10k trq, WOB=3-7. MW in/out 9.2, ECD= 9.53 ppg, P/U 145K, S/O
100K, ROTW 125K. Backream as needed, pumping sweeps every 500 ft or as needed.
Drill/slide 12-1/4" surface hole f/4019' -t/4580', Total 561' (AROP 93.5fph) 703gpm, 2680psi, 76rpm, 7-10k trq, WOB=3-7. MW in /out 9.2, ECD= 9.6 ppg, P/U 160K, S/O
110K, ROTW 130K. Backream as needed, pumping sweeps every 500 ft or as needed.
TD extended to 4720' and Geologist will call the depth as we get closer.
Drill 12.25" Surface Hole F/4580' -T/4750' (3453' TVD) Total 170' (AROP 85') 700 GPM= 2690/2625 psi on/off, 80 RPM= 9-11K TQ, WOB= 3-8K. MW in/out 9.3/9.4,
ECD= 9.6 ppg, P/U 160K, S/O 110K, ROTW 130K. Backreaming Full Stands prior to connections.
CBU @ 700 GPM, 2665 PSI, 60 RPM, 10K TQ, while recip. F/4750' T/4675', Monitor well= Static.
Distance to plan- 24.19', High 23.08', Right 7.24'.
POOH on elevators F/4750' T/3605' with no issues. PU 130K, SO 100k. Off BTM PU 170K.
RIH F/3605' T/4750' washing down last stds. Tagged no fill.
Circulate hole clean, Pumped Hi-vis sweep with beed marker at 720 GPM, 2675 PSI, 80 RPM, 10K TQ, while recip. F/4750' T/4675', Sweep back with little to no increase.
Monitor well= Static.
POOH on elevators F/4750' T/332', 10-15K drag first 30' with no issues after. PU 160K, SO 110k Off BTM.
Report Number
11
Report Start Date
7/25/2023
Report End Date
7/26/2023
Operation
Service Rig.
Daily Discharge= 254 BBLS\nCumulative Discharge= 1186 BBLS\nDaily Metal= 0 LBS\nCumulative Metal= 0 LBS
RIH F/334' T/4646' MD wash down to 4750' 700gpm 2550psi.
Pump 40BBL high vis sweep and circ hole clean @ 4750' 716gpm, 2600psi, 70rpm, 9-10K TQ. LD single and monitor well. PUW= 170K S OW=110K RTW=130K.
POOH F/4,740' T/696' no losses.
LD BHA#2 While LD BHA bails became stuck on elevators, CO to back up set of elevators. BIT GRADE PDC- 1-1-WT-A-X-I-NO-TD BIT GRADE ROLLERS-
1-1-WT-A-0-I-NO-TD.
Clean up rig floor, PU RU casing pipe handling equip, and volant tool, CO bails to 11' bails and installed bail extensions.
PU MU Shoe Track assy Baker Locking all connections. Filled the float collar jt half way and installed By Pass Adapter/TOP HAT as per Halliburton Rep. Checked Floats
by pumping with the Volant tool. Installed Baffle adapter as per Halliburton Rep and running tally.
RIH W/ 9 5/8'' casing as per running tally filling every 10jts. Current depth is at 581' PUW=85K SOW=85K.
Report Number
12
Report Start Date
7/26/2023
Report End Date
7/27/2023
Operation
RIH w/ 9 5/8'' casing F/581' T/ 2534' running centralizers as per tally every other jt.
Stage up pumps to 230GPM CIRC well clean 150PSI PUW= 185K SOW=120K.
RIH w/ 9 5/8'' casing F/2534' T/3721' running centralizers as per tally every other jt. 4 jts before ES cementer got centraliz ers.
PU MU ES cementer as per Halliburton rep checking all shear bolts, 6 at 3300psi and Baker Locking bottom and top connections.
RIH w/ 9 5/8'' casing F/2534' T/4670' running centralizers as per tally every other jt 4 jts after ES cementer got centralizers .Ran 65 9 5/8'' X 12'' centralizers. Had to fix 8 9
5/8'' pin threads due to poor cutting of the threads leaving burrs on the casing threads. LD one down due to bad threads.
PU MU hanger as per Vault rep. Landed hanger on depth with no fill put 30K down to ensure landed. PUW=340K SOW=135K.
Circ well while reciprocating pipe 10' @ GPM= 283 PSI=146.
Report Number
13
Report Start Date
7/27/2023
Report End Date
7/28/2023
Operation
Circ well while reciprocating pipe 10' @ GPM= 283 PSI=146. Circ & Condition mud to 20 YP. Clean.
PJSM surface cmt job. Land hanger, R/D volant tool, R/U Cmt head. Well head rep RILD & test void to 1000 psi for 15 min. Good. Drop bypass plug and load opening
plug in head. Line up to HES & pump 5 bbl fresh water to Test lines to 750/4250 psi. Good.
Mix & pump 60 bbl tuned spacer at 10.5 ppg. Mix & pump 248 bbl Lead Cmt 12 ppb Lead. ( 592 sx). Mix & Pump 48 bbl Tail Cmt at 15.8 ppg. (250 sx). Land hanger and
open 4'' valves. Drop shut off/ Opening Plug. HES pump 20 bbl H20. Saw good indication of plug leaving head.
Pressure up and saw tool open at 2650 psi. Gained returns. Circ btm up at 6 bpm with rig. Saw all spacer and 70 bbl cmt in returns. Got good mud back at btm up. Slow
pumps to 2 bpm while prepping for second stage.
Rig displace with 234.5 bbl 9.3 spud mud.Rig pump 65 bbl tuned spacer. Rig displace with 18.75 bbl & bump plug. Displaced at 6 bpm. Bumped plug .75 bbl early from
calc strokes.CIP at 1132. Final lift pressure 750 psi. Pressure up to 1250 & hold for 5 min. Bleed down. Bled back 1 bbl. Floats holding.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 4/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
PJSM, Second stage cmt job. Line up to HES & pump 5 bbl H20 Mix & pump 60 bbl tuned spacer at 10.5. Mix & pump 379 bbl 12 ppg lead cmt (898 sx). Drop closing
plug. Saw good indication of plug leaving head. HES pump 20 bbl H20.
R/D HES cmt head and flush out same. R/U Parker casing tongs. Back out landing joint as per wellhead Rep & L/D same.
Rig pump 54 bbls & bumped plug at 200 psi final lift. Pressure up to 2000 psi. Saw tool shift at 1000 psi. CIP at 1600. Bleed down and check flow. Dead both sides. Got
60 bbl mud push and 6 bbl of cmt to surface.
Removed master bushings and upper bell nipple. Removed hoses and securing lines from the lower bell nipple. removed lower bell nipple and spool from the top of the
21 1/4'' surface annular.
Sucked out the stack of the remaining spud mud left over from the inside of the LJ prior to installing the lifting device to the top of the surface annular.
Pick annular, diverter tee, knife valve and riser from off of A-17.
Install tree on A-17 as per wellhead rep and production foreman to ensure proper placement of annulus valves. Test bottom connection of the tbg head to 5000psi for
15mins good test.
Prep to skid to NCIU A-18.
Report Number
14
Report Start Date
7/28/2023
Report End Date
7/29/2023
Operation
Report Number
15
Report Start Date
10/2/2023
Report End Date
10/3/2023
Operation
Cont. N/U tree and adaptor, Move pipe and equipment on deck to make room to L/D DP
Complete torqueing tree and adaptor, PT hanger void and hanger neck seals to 5000 PSI for 15 min each- good test. Fill up tree and PT to 5000 PSI for 5 min- good test.
Pull TWC and secure well. Sim-ops start L/D 4.5" DP at 20:00 HRS.
Cont. L/D 4.5" DP for a total of 24 std L/D.
Cont. L/D 4.5" DP for a total of 52 stds L/D. L/D 4.5" HWDP and jar std for stds L/D.
Rigging up enerpac cylinders and brace plate on skid beams to straighten out cantilever on skid beams
Report Number
16
Report Start Date
10/3/2023
Report End Date
10/4/2023
Operation
Broke Aft of the rig package free utilizing enerpac. Transverse rig package over A-17. Install hand rails and safe out rig. Pre p and skid rig package to the bow and center
over well.
N/D production tree and L/D on platform deck
Lower stack onto well and tighten Quick connect drilling adapter testing to 5000 for 10 Min as per well head rep.
Remove old choke hose from rig side and install new choke hose, DSA and safety clamps.
Install lower bell nipple to annular, connect TT and bleeder lines. R/U BB winches and secure BOP's. Install upper trip nipple and tighten dresser sleeve and pollution pan
bolts.
Rig up test 4.5" test jt and testing equipment. Flood stack and lines with water and check for leaks. Found leak on flow box tightened bolts. Cont. flooding BOP equipment
and purging air from system. Sim-ops hang off blocks and prep drawworks for brake band equalizer work.
Perform shell test-good, Test BOP's as per well program/AOGCC regs with 4.5" test jt 250/3500 PSI for 5 min each. Witness waived by AOGCC rep Jim Regg 10-3 at
09:30. On test 4 of 9. Sim-ops remove equalizer bar and tensioning bolts. Change out tensioning bolts, bushings, springs and lo ck nuts.
Report Number
17
Report Start Date
10/4/2023
Report End Date
10/5/2023
Operation
Continue Test bop's as per regulations on 4-1/2" test jt 250L/3500H 5/5min on chart w/ 3 F/P one over pressure on low test bled off and retest good and two air purge
system and retest good. witness waived by Mr. Jim Regg. while while going through dwk brake linkage and chg/out wore items.
Install dwk covers and unhang blocks. R/dn test equipment and pull test /dn test jtand set wear ring and plow dn lines.
House cleaning finish rig acceptance check list and chk rig for drill ready and prep to p/up bha and dp.
PJSM. P/up and m/up triple combo drilling assy Bha #3 as per DD and MWD and upload tools. Shallow pulse test tools and Load source. RIH T/105'.
RIH 2 flex collars T/175' Single in the hole F/175' T/1008' with 20 jts of HWDP and jars, swap over to 4.5" DP. washing down tagging at 1008'.
Drill up ESCMTR F/1008' T/1011', 377 GPM, 700 PSI, 30 RPM, 2-3K TQ with 2-5K WOB.
Chase plug down hole F/1011' T/1270' at 350-200 GPM, 700 PSI, 20-30 RPM, 2-4K TQ.
Cont. to single in the hole with 4.5" DP F/1270' T/1660'.
Cont. to single in the hole with 4.5" DP F/1660' T/4555' filling pipe every 2500'. PU 140, SO 90.
Circulate old mud out the hole with see water @ 388 GPM, 1075 PSI, 30 RPM, 8K TQ while reciprocating 90'.
Report Number
18
Report Start Date
10/5/2023
Report End Date
10/6/2023
Operation
Continue circ well clean to FIW while rotating and reciprocating full stand @ 388 gpm @ 1075 psi 30 rpm @ 8k TQ.
R/up and test csg t/ 3750 psi w/ 5.8 bbls on chart for 30 min good test.
Drill cement , shoe track and rat hole f/ 4555' t/ 4750'. float collar @ 4622' shoe @ 4742' w/ 350 gpm @ 870 psi and 30 rpm @ 9 k TQ up/dn /rot 160/100/120k.
Drill new formation f/ 4750' t/ 4775' while displacing well t/ 9.2 ppg 2% KCL mud.
R/up and Preform F.I.T t/ 14.7 ppg EMW w/ 992psi applied pressure on chart and graphed.
Drill 8.5" Hole F/4775' -T/5365' Total 590' (AROP 59') 475 GPM= 1430 PSI, 50 RPM= 9-10K TQ, WOB= 3-6K. MW in 9.2 Vis 50, ECD= 9.73 PPG. Max Gas= 163 units,
P/U 160K, S/O 110K, ROT 120K. Double backream prior to connections. Lost RES tool right outside the shoe.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 5/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
Cont. Drilling 8.5" Hole F/5365' -T/5734' (4020' TVD) Total 369' (AROP 62') 450 GPM= 1420 PSI, 50 RPM= 9-10K TQ, WOB= 3-7K. MW in 9.2 Vis 50, ECD= 9.78 PPG.
Max Gas= 263 units, P/U 160K, S/O 110K, ROT 130K. Double backream prior to connections. Distance to Plan 17.88', High 17.34', Left 4.35'.
Pumped 20 BBL Hi-vis sweep at 5345' back on time with 30% increase in cuttings.
Report Number
19
Report Start Date
10/6/2023
Report End Date
10/7/2023
Operation
Cont. Drilling 8.5" Hole F/5734' -T/5827' Total 93' (AROP 62') 450 GPM= 1480 PSI, 75 RPM= 9-10K TQ, WOB= 3-7K. MW in 9.2 Vis 50, ECD= 9.78 PPG. Max Gas= 37
units, P/U 160K, S/O 110K, ROT 130K. Double back ream prior to connections.
ADEC inspectors accompanied by Jessica Fisher arrived and performed a records review and facility walk through on Spartan 151.
Circ shakers clean @ 450 gpm @ 1480 psi 75 rpm 8-10k TQ rotating and reciprocating full std. Take TD survey and SPR.
Flow chk static Short trip Pooh on elevators f/ 5827' t/ inside shoe @ 4710' w/ no issues.
Slip and cut 70' drill line and monitor well on trip tank w/ < 1/2 bph seepage rate and service rig.
Short trip RIH on elevators f/ 4710' t/ 5720' fill pipe brk circ warm and stage up pump rate wash ream last std t/ btm @ 5827' w/ no fill and just couple 10k bobbles.
Resume Drilling 8.5" directional Hole F/5827' and pump 25 bbl high vis sweep around while drilling Back on time w/30% increa se.
Drilling 8.5" Hole F/5827' -T/6012' Total 185' (AROP 53') 400 GPM= 1250 PSI, 50 RPM= 9-10K TQ, WOB= 2-4K. MW in 9.2 Vis 49, ECD= 9.6 PPG. Max Gas= 263 units,
P/U 170K, S/O 115K, ROT 135K. Double backream prior to connections.
Drilling 8.5" Hole F/6012' -T/6312' Total 300' (AROP 50') 450 GPM= 1540 PSI, 50 RPM= 9-10K TQ, WOB= 2-5K. MW in 9.2 Vis 47, ECD= 9.68 PPG. Max Gas= 218
units, P/U 170K, S/O 115K, ROT 135K. Double backream prior to connections.
Started to see 140-180 unit of connection gas at 6100'. Started to increase MW to a 9.3 PPG.
Drilling 8.5" Hole F/312' -T/6530' (4509' TVD)Total 218' (AROP 36') 450 GPM= 1570 PSI, 50 RPM= 9-10K TQ, WOB= 2-5K. MW in 9.3 Vis 50, ECD= 9.9 PPG. Max
Gas= 84 units, P/U 175K, S/O 115K, ROT 140K. Double backream prior to connections.
Report Number
20
Report Start Date
10/7/2023
Report End Date
10/8/2023
Operation
Achieved a 9.3 PPG at 6330' connection gas stop holding a 12-25 unit BGG. Started our directional work with 3.5/2.5 deg/100' at 6300'. Halliburton cementers arrived on
rig @ 01:00 hrs and began to off load CMT into rig silos.
Continue Drilling 8.5" directional Hole F/6530' -T/6830' Total 300' (AROP 42.8') 450 GPM= 1570 PSI, 50 RPM= 9-10K TQ, WOB= 2-5K. MW in 9.4 Vis 50, ECD= 9.9
PPG. Max Gas= 119 units, P/U 175K, S/O 115K, ROT 140K.
Encountered complete losses @ 6830' Spot 40 bbl 40ppb lcm pill and over displace 5 bbls w/ no returns @ 200 gpm in place @ 13:33 hrs. Pull 5 std slow and let pill
soak t/ 6349' and preformed static loss rate on trip tank @ 40 bph. Discussed options w/ town.
Pump 24 bbls Lcm pill @ 50 PPB and over displace 5 bbls and pull 7 more std slow t/ 5737' and let pill soak. Preform static loss rate on trip tank @ 12 BPH loss rate.
Attempt circ dn pipe @ 50 gpm total 3.8 bbls w/ no returns dn pump and Monitor losses on trip tank.
Mointor static loss rate on trip tank and let pills soak while Building volume and LCM pill off load csg and tubing from boat, Static loss rate down to 7 BPH dropping down
to 2 BPH, Rolled pumps to verify BHA still clear 50 gpm, 200 psi, 3.6% return flow.
Cont. Building mud monitoring static loss rate on trip tank- no gains no losses up to 04:00 hrs, pump at minimal rate to see dynamic loss rate 50 gpm, 199 psi, 3.9% return
flow observing no losses.
Report Number
21
Report Start Date
10/8/2023
Report End Date
10/9/2023
Operation
Cont. Building mud volume. Continue stage up pump rate to check dynamic loss rate 50, 100 and 152 gpm, @ 371 psi w/ no losses.
RIH f/ 5737' slowly L/dn single wash last std t/ 6814' @ 100 gpm w/ 7.7 % flow minimal losses.
Make connection up pump rate t/ 340 gpm finish washing and reaming t/ btm @ 6830' w/ no fill. Rotary drill 8-1/2" hole f/ 6830' t/ 6886' total 56' w/ intermittent returns for
first 15' then total losses w/ hole only dn +- 8" to fluid level w/ 130 bbls lost @ 6866' Launch 40 bbl.
Pooh slow f/ 6886' t/ 6355' and preform static visual flow check w/ slight losses. and 6 bbls over calculated displacement.
LCM pill @ +50ppb and over displace 5 bbls while drilling and dn pump @ 6886'.
Continue pooh slow 6350' t/ 5427' and chk static loss rate on trip tank static well taking proper fill.
Continue pooh slow and into shoe @ 4727' wiped clean tight 25k over pull spots @ 5023' and 4904'.
Attempt circ. @ 100 gpm w/ 10% flow up rate to 200 gpm and lost all returns dn pump and monitored well 30 min w/ initial loss rate of 1bpm and finial @ 1/2 bpm loss
rate. total 23 bbls lost.
Pump and spotted 50 bbls of 50ppb LCM pill and chased w/ 15 bbl dry job w/ full returns @ 100 gpm.
Monitor well on trip tank and service rig w/ no losses.
POOH F/4725' T/827', monitor well for 15 min- static. POOH racking back 7 stds of HWDP T/175'. Observed proper fill. M/U single to Flex collars and flushed BHA with 30
BBLS of sea water.
Racked back std of flex collars, Removed source from BHA and download tools as per MWD.
POOH to bit, close blinds and drain BHA. Break bit. Bit grade 1-1. Run back in hole L/D TM, CNT and ADL assemblies. B/D EWR and PWD for res tool work. L/D DM and
Mud motor.
Clear and clean floor, Make up cementing assembly and L/D on V-Door.
Make up Rock bit, bit sub and XO to BTM of first std of HWDP. RIH with cementing BHA F/surface T/3708', Observing proper displacement.
Report Number
22
Report Start Date
10/9/2023
Report End Date
10/10/2023
Operation
Continue RIH with cementing BHA F/3708' T/4728', Observing proper displacement.
Kelly up and brk circ and stage up pump rate and warm mud f/ 50 gpm t/ 250 gpm @ 297 psi w/ no losses while wait on weather and cmters.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 6/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
Cemters on board continue rih f/ 4728' t/ tag @ 6806' and c/out fill t/ 6866' w/ full returns made connection and when we brought pump back on line lost all returns
finished c/out t/ 6886' w/ no returns. L/dn single and m/up cmt head.
PJSM Batch up spacer and brk circ w/ cmt unit and pressure test lines 717 psi low and 4050 psi high good. pump 10 bbls water ahead pump 23.5 bbls of 11.0 ppg spacer
@3bpm @125 psi w/ 5.7 bbl in losses. mix and pump 35 bbls of 15.8 ppg cmt w/ 3 ppb bridge maker.
Pooh slow 5 stds @ 10 min std t/ 6392' and out of est TOC w/ CIP @ 1719 hrs continue pulling 5 more std slow t/ 5841' monitor well on trip tank well taking proper
displacement.
@ 2.5 bpm @ 230 psi followed by 6.5 bbls of 11.0 ppg spacer fallowed by 10 bbls water. swap to rig and pumped 69 bbls of 9.4 ppg mud displacement @ 258 gpm @
150 psi initial pressure and finial pressure of 600 psi w/ 136 bbls lost during job.
Pump wiper ball and circ btm up while rotating and reciprocating pipe at 233 GPM, 530 PSI dumping 36 BBLS @ BU due to heavy mud/spacer returns. Monitored
well-static.
POOH F/5841' T/4728', observing proper displacement. Flow check well-static.
Break circulation at shoe to check on dynamic losses, 268 GPM, 423 PSI no losses. Pumped dry job.
Cont. POOH F/4728' T/surface. Break off and L/D bit, bit sub and XO.
Clear and clean rig floor, B/D cementing assembly.
P/U drilling BHA #5- P/U motor and M/U bit, M/U DM, DGR, PWD, ARD and ALD collars. Scribe motor to MWD tools. M/U CTN and TM. Plug in and upload tools as per
MWD. Shallow pulse tools, Install Sources, M/U flex collar std and RIH T/181'. Cont. RIH with 4.5" HWDP T/832'.
Report Number
23
Report Start Date
10/10/2023
Report End Date
10/11/2023
Operation
Continue rih w/ Bha #5 f/ 827' t/ 4714' monitoring well on trip tank w/ proper displacement.
Service rig while monitoring static hole no losses.
RIOH f/ 4714' t/ 6281' w/ no issues and proper displacement.
Kelly up, Fill pipe, Establish parameters wash and ream staging up pump rate t/ 350 gpm @ 1125psi up/dn/rot 170/110/130k f/ 6276' t/ tag of cmt @ 6820' (10' above loss
zone) drill cmt t/ TD @ 6886'.
Orientate and preform 14' slide f/ 6886 t/ 6900' w/ loss rate increasing to 1bpm. Rotary drill f/ 6900' t/ 6935' w/ 52 bbl totals losses pump 12 bbl 50 ppb LCM pill while
drilling.
Spotted 40bbl / 50ppb LCM pill on backside, (total 261bbls of mud lost).
Pooh f/6973' t/6573', monitoring fill on the TT. (13bbls lost over calculated fill).
Working pipe f/6576' t/6484', while crew builds volume of 9.7ppg/20ppb LCM mud. monitoring well on the TT-well static.
Report Number
24
Report Start Date
10/11/2023
Report End Date
10/12/2023
Operation
Rih f/ 6576' t/ 6973' washing last stand to btm w/ no fill @ 290 gpm @ 900 psi.
Distance to plan: 13.31', 13.23' High, 1.38' Left.
Resume control drilling 8-1/2" directional hole at minimal rates @ 322 gpm @ 1069 psi, RPM @ 50 and max ROP@ 30 fph f/ 6973' t/ 7063' where we started losing
returns pump 15 bbl / 75ppb LCM pill while drilling and reduced ROP to 20 fph lost complete returns @ 7067' with hole
staying full continued drilling and launched 35 bbl / 75ppb LCM pill and cleared bit w/ 5 bbls. stop drilling @ 7072' w/ pill in place and total 345 bbls lost.
Pooh 5 std slow t/ 6572' w/ no issues w/ MW @ 9.8 ppg.
Work full std and pump 152 gpm @ 426 psi. Monitoring well for losses and let pill soak and build back mud volume and property's w/ 7 bbls lost total.
Rih f/ 6572' wash last std to btm w/ no fill establish parameters.
Resume Control drilling 8-1/2" directional hole at minimal rates @ 322gpm, 1069psi, 50rpm, 2-4k wob, 11k trq and max ROP@ 20fph f/7072' t/7200', pumping 15bbl LCM
pill every 20ft drilled. p/u=200k, s/o=115k, rot=150k.
Control drilling 8-1/2" directional hole at minimal rates @ 318gpm, 1065psi, 2-4k wob, 12k trq and max ROP@ 30-40fph f/7200' t/7264', pumping 15bbl LCM pill every 40ft
drilled. p/u=200k, s/o=115k, rot=150k. Lost circulation. spot 35bbl 50ppb pill on backside.
Reduce pumps to 150gpm and use TT pump to fill hole.Pooh 6 std slow t/ 6763' w/ no issues w/ MW @ 9.8 ppg. Total mud lost 274bbls.
Work pipe and build 9.8ppg mud volume, let pill soak for 30min. and start to stage up mud pumps t/150gpm, 367psi.
Report Number
25
Report Start Date
10/12/2023
Report End Date
10/13/2023
Operation
Continue work full std and pump 150 gpm @ 367 psi. Monitoring well for losses and let pill soak and build back mud volume and p roperty's w/ no losses.
Distance to plan: 16.07', 16.07' high, .41 right.\nTotal bit Krevs=13
Attempt brk/out TDS to Rih unable to get TDS to rotate Trouble shoot issue and resume work pipe (rig on dn time).
Continue trouble shooting Top drive PLC electrical system load latch. keeping top drive from rotating. Spot 50bbl/100ppb LCM pill @ 6763' on backside.
Pooh f/6763' t/4719', (shoe@4742'). Monitor fill on the TT, well took 9.4bbl over calculated fill.
Service top drive, traveling block and drawworks. Monitor well on the TT-static. Top drive fixed and functioning properly.
Circ. well @150gpm, 400psi, 25rpm applying pressure to LCM pill while working pipe.
Rih on elevators f/4719' t/6991', started to push mud away @4min. std. Monitoring displacement on the TT-hole was taking proper fill.
Kelly up and wash and ream f/6991' t/7264', stage up pumps t/100gpm, 460psi, 3-7% flow, 10-30rpm. Pump 15bbl/100ppb LCM pill on kelly stand.
Drill f/7264' t/7269', @150gpm, 20-40rpm, 400-465psi,0-8.9% flow, pull off btm trying to heal up loss zone and spot LCM pill. T otal loss for tour 295bbls.
Report Number
26
Report Start Date
10/13/2023
Report End Date
10/14/2023
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 7/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
While attempting spot 35 bbl LCM pill experienced total losses w/no fluid in sight, slow pump rate and top fill w/ trip tank. a nd started pooh depleted surface mud volume
and started top fill w/ sea water @ 07:07 hrs caught returns at 142 bbls sea water pumped.
Distance to plan: 16.07', 16.07' High, .41' Right\nTotal bit Krevs=99
Continued pooh keeping hole full w/kill line t/shoe @ 4706' w/total loss of 1168 bbls hole mud and 206bbls of sea water for total of 1370bbls.
Monitor loss rate on trip tank started out at 1 bpm and discuss options w/town and decreasing t/1.2 bph w/total lost of 51.1bbls since we got returns back. While cleaning
pits and lines an building new mud volume.
Continue monitor well on trip tank while building mud volume. Work boat.
POOH f/4705' t/surface.
Work BHA as per DD/MWD, dwn load mwd data, drain motor and break out bit.
Distance to plan: 16.07', 16.07' high, .41' right.
Report Number
27
Report Start Date
10/14/2023
Report End Date
10/15/2023
Operation
M/up Cmt bha #5 w/RR PDC bit no jets.
Rih t/shoe 4634' w/ proper displacement.
Rig service & m/up cmt head.
RIOH f/shoe p/up cmt head and place bit @ 6812' and m/up lines.
PJSM cementers brk circ w/20 bbls water and test lines 596psi low / 4170psi high good. Batch up 15.8ppg LCM cmt w/1pps bridge maker and scale cmt good. Pump
35bbls cmt @ 2.5bpm @ 213psi fallowed by 20bbls sea water @ 3bpm 60psi. Rig pumped and displaced.
69bbls of 9.2ppg mud @ 5.9bpm 116psi w/16.4 bbls lost during job.
L/dn cmt head and single and pull 10 std slow t/5836'.
Load wiper ball and displace well t/ 9.2 ppg mud @250gpm, 600psi, dumping sea water until good mud returns @310bbls pumped.
Work full std and circ 5.8bpm @ 347psi and wait on cmt, 9.2ppg in/out.
TIH f/5841' t/6491', monitoring displacement on the TT. Took weight and kelly-up and wash/ream f/6491' tagged @ 6543'+- w/5-10k wob, 250gpm, 500psi, 63rpm, 7-11k
trq and reamed t/6581'. Cement returns on B/U.
Circ. condition mud / WOC, 208gpm, 307psi, 8.5trq, 53 rpm, 16.9% flow w/working std.
Drill cement f/6581' t/6650', 342gpm, 478ps, 23.9% flow, 124rpm, 5-10ktrq, 7-9k wob.
Report Number
28
Report Start Date
10/15/2023
Report End Date
10/16/2023
Operation
Distance to plan: 16.07', 16.07' High, .41' Right.
Continue Drill cement f/6650' t/6917', 342gpm, 478ps, 23.9% flow, 125rpm, 9-10ktrq, 0-5k wob. up/dn/rot 160/115/130k (bit weigh t fell to zero @ 6818' but unable rih ).
Continue c/out cmt stringer w/ no weight t/ 6964' wash in hole no rotation t/ 7204' w/ 5% cmt and 95% LCM in returns and working std twice. Lost complete returns @
7200' w/ fluid column in sight and started experiencing differential sticking. Reduce pump rate and top fill w/ trip tank.
Rack back 1 std w/58 bbls lost. M/up cmt head and lines placing bit @ 7141'.
PJSM. Pump 15 bbls sea water ahead @ 2bpm @ 220 psi. test lines t/ 2500 ok. Mix and pump 33 bbls of 15.8 ppg cmt and added 100# of bridge maker on the fly @ 2.5
bpm @ 400 psi fallowed by 20 bbls sea water @ 4 bpm @ 170 psi. Rig displaced w/ 69 bbls of 9.2 mud @ 4.5 bpm
and caught pressure @ 398 stk 150 psi finial pressure 355 psi w/ no returns during job top filling back side lost total of 184.7 bbls during job. CIP @ 15:02 hrs.
L/dn cmt head on vacuum and pull 10 std slow f/ 7141' t/ 6212' had kelly up and pump and work through tight spot @ 6463' - 6453' w/ 50k over and 20k under.
Load wiper ball and circ pipe clean @ 6212', 176gpm, 304psi, 14.1% flow, work full std, monitoring well for losses.
Rih f/6212' t/6583' on elevators, monitoring displacement on the TT-proper displacement.
Wash and ream f/6583' t/7012' tagged cement X2 w/6k down wt., 141gpm, 480psi, 12.3% flow.
Drill cement f/7012' t/7183', 254gpm, 695psi, 19.7% flow, 51rpm, 8-10k trq, 0-2.5k wob. Lost return @7183', backed off pump and rotary still no flow, shut down pump and
rotary. Racked back 1 std t/7141'.
Pumped 35bbl 50ppb LCM pill, staged up pumps to 324gpm, 717psi, 22.9% flow, 25rpm, 8-10k trq. Spotted @7141'.
Pooh f/7141' t/6665', monitoring fill on the TT. Hole took proper fill.
Circulate b/u @ 425gpm, 890psi, 29.9% flow, 20rpm, 8.5k trq, while working std.
Rih f/6665' t/7141', monitoring displacement on the TT. Hole gave proper displacement.
Wash/ream f/7141' t/7269', 150gpm, 270psi, 12.2% flow, 20rpm, 9.5k trq, 0 wob. Start losing partial flow @7180' t/5-8% flow. Co ntinue reaming trying to heal up losses
w/20ppb background LCM and slow pump rate. Losses started @1bpm now down to .5bpm.
Report Number
29
Report Start Date
10/16/2023
Report End Date
10/17/2023
Operation
Drill new 8-1/2" hole blind f/ 7269' t/ 7281' @ minimum flow rate 148 gpm @ 358 psi and 20 rpm pumping 15 bbls LCM pills as needed while drilling.
Continue drilling new 8-1/2" hole blind f/ 7281' t/7297'. Staging up flow rate slowy f/ 148 gpm t/ 275 gpm 124 rpm and pumping 15 bbl LCM pills as needed while drilling to
control losses. any thing over 210 gpm we was losing 1bpm.
Reduce flow rate back to minimum 155gpm and discuss options w/town continue drilling blind to get below losses f/7297' t/7326' pumping 15bbl LCM pills to control
losses and still trying to get to drilling rate w/controllable losses and still experiencing poor ROP.(276bbls losses since 00:00hrs).
Mobilize cmt crew, continue drilling f/7326' t/7345', 174gpm, 475psi, 14.7% flow, 140rpm,9-10k trq, p/u=180k, s/o=115k, rot=145k. Losses 73bbld @4bph.
Circ. hole clean w/ working pipe f/7345' t/7312', 174gpm, 475psi, 14.7% flow, 140rpm,9-10k trq, p/u=180k, s/o=115k, rot=145k. Lost 6bbls.
Std back kelly std, p/u cement head and set @7338', r/u cement hose and blow dwn. Hold pre-job w/crew and Haliburton cementers on cementing.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 8/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
Pump cement job as per Haliburton Rep., Haliburton pumped- 20bbls H2O, 35bbls 15.8# cement @3bpm/400psi, 7.5bbls H2O, shut down and swap to rig pump and
chase w/84.5bbl @7.3bpm/1200psi, 0 losses during job.
Pooh f/7338' t/6386' on elevators, sticky @ 7200' w/90k overpull x2, kelly up and try rotate thru w/no luck, pull 120k over and jars fired and pulled thru w/ no other issues.
Circ. wiper ball thru string @296gpm, 553psi, 23.9% flow.
Pooh f/6386' t/5400' on elevators at report time.
Report Number
30
Report Start Date
10/17/2023
Report End Date
10/18/2023
Operation
(CIP@ 03:33hrs)\ndaily losses 417bbls.
Continue Pooh f/5400' t/4727' on elevators w/ proper hole fill.
Flow chk and pump dry job.
Continue pooh f/ 4727' to surface , rack back HWDP and jars, break off bit and xo. Bit was balled up and had 4 out of 6 jets plugged w/cement and wiper ball material. (bit
grate out: 1-1-BU-A-X-I-PN-BHA).
Break down cement head and jt., l/d same.
M/u wear ring running tool and pull same.
R/u drain hose f/wellhead to overboard and drain stack, choke man., and top drive of mud. Flush thru and fill same w/sea water. R/u test equipment, floor valves and
4.5"test jt.
Test 13-5/8" 5M BOPE w/4.5" test jt and sea water, to 250-350psi/low and 3500psi/high for 5min. ea. charted as per AOGCC/Hilcorp procedure. Test all H2S/LEL gas
alarms/system. Perform Koomey draw down.
R/d test equipment, drain stack, choke man. and top drive of sea water and fill same w/mud.
Koomey Draw Down: systempress-3100psi , pressure after closure-1900psi , 200 attained-67sec., full pressure attained-182 , blind switch cover- yes, Nitrogen bottle
average- 16 @ 2200psi.
. P/u BHA #7 as per DD/MWD, Triple combo and 8.5" kymera bit w/new jars.
Report Number
31
Report Start Date
10/18/2023
Report End Date
10/19/2023
Operation
Upload MWD, Shallow pulse test & Load Radioactive sources.
Change out jars & RIH with HWDP. RIH to shoe at 4721'.
Rig service, Warm up mud at 300 GPM.
RIH on elevators F/ 4721' T/ 4770'. Tag. Set down. \n Wash & Ream from 4770' T/ 5258'. 350 GPM, 60 RPM\n Saw slight Pack offs while reaming. Let clean up as
needed. Shakers getting lots of fines & cmt/ Silts.
RIH on elevators F/ 5258' T/ 6375'. Tag and set down.
Wash & Ream F/ 6375' T/ 6857' Tag TOC, 4-6 WOB. 75 RPM, 400 GPM. \nGetting fines in returns.
Drill side track off top of cement f/6857' t/7345', 490gpm, 2200psi, 75rpm, 8-10k trq, 5-10k wob, p/u=200k, s/o=11ok, rot=145k.
Report Number
32
Report Start Date
10/19/2023
Report End Date
10/20/2023
Operation
Drilling 8.5 Hole F/ 7293' T/ 7395' staging up pumps to 400 GPM, 50-75 RPM. 12-24 WOB. Hard driling. Work perametors tryin g to get good ROP.
Backream out of the hole at 300 FPH F/ 7409' T/ 7350'. Continue backreaming out up above 6857'. TOC. Shoot 30' Surveys as per directinal driller to get new drilling
plan. Circ & Condition at 300 gpm while making plan. No losses to report.
RIH taking surveys every 30' as per DD F/ 6857' T/ 7409'.
Drill/slide/survey f/7409' t/7700', 400gpm, 1900psi, 50rpm, 11-12k trq, 10-15k wob, backream std X2 and mad pass slide @300fph.
Distance to plan: 85.52', 85.02'high, 9.26'left.
Total Bit Krevs=199.0
Total Gas Units=51
Total Losses=260bbls
Report Number
33
Report Start Date
10/20/2023
Report End Date
10/21/2023
Operation
Drilling 8.5 Directional hole F/ 7700' T/ 7748'. 10-24 WOB, 12-13K TQ.
400 GPM, 1950 PSi, 50 RPM, Backreming stands twice. MW 9.2, Vis 52,
Mad pass slides at 300 FPH.
CIrc btm up until shakers are clean. 490 GPM, 50 RPM, . Monitor well. Static.
Short trip F/ 7747' T/ 6763'. No issues. Hole took prper fill. RIH to 7700' & Wash last joint down. Prep for wt up to 10.2 ppg.
Circ STS adding 13.8 PPG spike fluid to active system. Bring MW in and out to 10.2 PPG. No losses. 380 GPM, 50 RPM.
Drilling 8.5 hole F/ 7747' T/ 7800', 400gpm, 2250psi, 28.6% flow, 50rpm, 12-13k trq, 10-20k wob. Backream std x2, sweeps hole every 500' or as needed.
Shut down pumps and pull off bottom and reciprocate. Mud system -shaker tanks/sand traps and pit #2 all found to have a jelly like layer of mud in the bottoms that floats
if broke loose, it has a PH of 12 and turns bright red with phenolphalene. Dump shaker tanks and pit #2, clean same, wt. up pit #1. Make pit #3 active pit and get shaker
tank five isolated after cleanning.
Circ./reciprocate using pit #3 and shaker tank #5 @ 150gpm, 590psi, 25rpm, 11k trq, 13% flow.
Slide drilling f/7800' t/7854', 314gpm, 1460psi, 24.4% flow, 12-20k wob.
drilling f/7854' t/7883', 350gpm, 1675psi, 55rpm, 10-11k trq, 27% flow, 20k wob. Back ream std and mad pass slides @300fph, swe ep hole every 500' or as needed.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 9/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
Slide f/7883' t/7920', 390gpm, 22100psi, 28.4% flow, 20.3k wob. Back ream std and mad pass @300fph. sweep every 500' or as needed.
Drilling f/7920' t/7969', 399gpm, 2125psi, 28.6% flow, 70rpm, 10-12k trq, 10-24k wob. Back ream std and mad pass slides @300fph .
Report Number
34
Report Start Date
10/21/2023
Report End Date
10/22/2023
Operation
Drill/slide/survey f/7969' t/8065', 320gpm, 2000psi, 12-13k trq, 27% flow, backream stds x2, mad pass slides and sweep hole every 500'.
Drill/slide/survey f/8065' t/8524', 441gpm, 2809psi, 78rpm, 11k trq, 30.8% flow, 16-24k wob. Backream stds x2, mad pass slides, pump sweeps every 500'.
Circ. B/U until clean, 445gpm, 2681psi, 31.5% flow, 75rpm, 11.5k trq, p/u=230k, s/o=130k, rot=165k. Monitor well/flow check-static.
Attempt to pull off bottom on elevators-getting 70-90k overpull and not breaking over. BROOH f/8524' t/7697', 320gpm, 1665psi, 24.5% flow, 47rpm, 11-12.5k trq. Stahling
@7960'-7898'.
RIH on elevators f/7697' t/8524', hole gave proper displacement.
Drill f/5824' t/8616', 441gpm, 2990psi, 31.9% flow, 76rpm, 11.5k trq, bachream std x2, pump sweep every 500'.
Report Number
35
Report Start Date
10/22/2023
Report End Date
10/23/2023
Operation
Drill F/ 8616' T/ 8900 (284' @ 47 FPH AV. ROP Limit Set at 80)
480gpm, 3300psi, 31.9% flow, 80rpm, 11.5k trq, backream std x2, pump sweep eat 8700'. Came back on time with 20% increase.
Drill F/ 8900' T/ 9290'MD-7000.3'TVD' 390 @ 52 FPH AV. ROP Limit Set at 100)
480gpm, 3300psi, 31.9% flow, 80rpm, 11.5k trq, 24k wob, backream std x2,
MW 10.2 PPG, ECDs 11 PPG.
Circ. 20bbl hi-vis sweep, 469gpm, 3039psi, 32% flow, 71rpm, 12k trq, while reciprocating std. Sweep back on time with 10% increase in cuttings.
BROOH f/9290' t/6851', 455gpm, 2835psi, 31.7% flow, 80rpm, 12.7k trq. tried to stall @ 8810', 8795', 8603', wipe area's no more issues.
Mad pass f/6851' t/6249', @300fph, 400gpm, 2170psi, 29.3% flow, 75rpm, 9-11k trq.
Report Number
36
Report Start Date
10/23/2023
Report End Date
10/24/2023
Operation
Loss return while back reaming at 400 GPM 80 RPM for the mad pass @6249'. Slow pumps to 100 GPM, Pump 45 BBL 100 PPB LCM pill and spot out of the pipe. NO
returns while pumping. Put TT on back side to keep full. Lost total of 200 BBL>
Started to Gain returns after pill came out of the pipe. Shut down pumps and Monitor back side. Static.
POOH at 300 FPH madpassing as per DD. No pumps or ROT.
Pulled tight at 4900' - 4830'. , 30-40K Over,
Pull in to Shoe & Monitored well Static.
Pump High vis sweep staging pumps up to 5 BPM, 600 PSI. No losses. MW out 10.4. Circ until good 10.1+ in and out.
Monitor well. Static, Pump Slug, Drop 1.92 Drift on wire. POOH F/ 4710 T/ BHA.
Stand back HWDP & NMFC, Unload Nuclear sources, Down Load MWD, L/D BHA #7. Bit Grade- 1-1-A-E-1/16-NO-TD
Clean and clear rig floor, R/U to run 4.5 Liner. Count pipe. PJSM
Monitor well. Well static no losses.
P/U Shoe track and check floats. Good. Had to change out the parker well bore Power tongs to the back ups.
Run 4.5 liner as per tally T/ 969'. Filling pipe on the fly keeping topped off every 10 Joints.
Report Number
37
Report Start Date
10/24/2023
Report End Date
10/25/2023
Operation
Run 4.5 TXP Liner to 4685' as per Tally. Torque each conection to 6400#. Monitor well on trip tank. Well took 8 bbl while runn ing liner.
Change handline equipment to 7'' & P/U Seal bore extension. Change handline equipment to and P/U SLZXP. M/U 2 3/8 Pups & Liner wiper. M/U to 9400#. Check pins.
Good. Mix pal mix & add to LT. Break down NMFDC to retreave drilling XO to run liner.
M/U First stand of 4.5 DP & Break circulation. Stage up pumps to 5 BPM at 220 PSI. Circ 1.5 Liner volumes. 10.2 MW in and ou t.
RIH on 4.5 DP at 60 FPM filling on the fly. Circ two OH Volumes at 6000' staging up punmps to 5 BPM, 450 PSI. No losses.
Continue running 4.5 DP F/ 6000' T/ 8030'. Stage pumps to 5 BPM.
Circulate 1 OH volume 5 BPM, 450 PSI
Cont. RIH on 4.5" DP at 60 FPM F/8030' T/9179' setting down 30K, worked pipe with 30-50K overpull and set down. Filled pipe packed off pipe broke free with 35K
overpull. Cont RIH T/9198' with same issue. Circ OH volume staging pupmps to 5 BPM, 500 PSI washing down T/9160'. M/U CMT head and 1 single washing down to
bottom with no fill.
Circulate and condition mud for CMT job at 5 BPM, 600 PSI, working pipe 15-20'. Held PJSM with CMTR's. .
Line up to HES, Pump 10 BBL H20 & test lines . Had leak on rigs hard line. Bleed down and tighten same. Pressue test to 500-4500 psi. Good. Try and work pipe.
Unable to get pipe moving pulling 60K over to 250K. Park pipe at 9289'.
Pump 30 bbl Mud push, Pump 292 bbl 12 ppg lead cmt, ( 695sx), Pump 37 bbl 15.3 ppg Tail cmt ( 185 sx) Wash up lines to RF with 20 BBL H2o. Drop Dart & launch
with 10 BBL H20. Swap to rig & displace with 10.2 ppg mud at 5 BPM . Saw latch early & Bumped plug 5.45 bbl early. Final lift pressure at 1100 pis. Hold 900 over.
Bleed down. Check floats. Good. Pressure up & set packer at 2300 is. Hold at 2500. Pressure up & saw nuetralizer tool sear at 3350. Hold 3500 psi. Bleed down &
P/U to verify free. Good. Line up both pumps. Hold 500 psi Pull out of pack off bringing pumps up to 11.6 BPM 1500 psi. Cir c out spacer & cmt dumping cmt out the
casing valves. Saw spacer on strokes . Got 30 bbl spacer & 100 bbl cmt back at surface. No losses during job. CIP 04:56.
Report Number
38
Report Start Date
10/25/2023
Report End Date
10/26/2023
Operation
Circ cmt out dumping returns. Circ an aditional 250 bbl to clear at 500 gpm Good. L/D double and break down cmt head. Blow down TD, Cmt line & prep for trip out.
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Page 10/10
Well Name: NCIU A-17
Report Printed: 1/4/2024www.peloton.com
Well Operations Summary
Operation
POOH & L/D LRT. Pack off still in tact looked good. Chagne elevators & bales due to elevators hanging up. Well took proper hole fill for trip. Performed BOP function
test.
P/U Cmt head and break out XOs & Pup. L/D Same. M/U Stack wash tool and flush out stack .
P/U Baker Polish mill & RIH to LT at 4575'. M/U 4.5 Pipe with ST-80 and check torque with rig tongs. St-80 still not torquing properly.
Wash down to seal bore extension tagging @ 4621'. Polish bore as per baker pulled up to 4575' above LTP CBU at 10 BPM, 1000 PSI
Cut and slip 105' of Drill line, Check brakes and reset crown saver
Adjust top drive grabber box wrench and torque cycles
Displace well over from 10.2 PPG 2% KCL mud to FIW at 520 GPM, 1180 PSI. Over displaced with 200 BBLS
Monitor well for 15 min-static. Flush through choke and kill lines and blow down same. Clean out and flush trip tanks. Blow down top drive
POOH with LRT to 1800'. L/D 4.5 DP F/ 1800' T/ 963'. L/D Unneeded DP for A-12B.
Report Number
39
Report Start Date
10/26/2023
Report End Date
10/27/2023
Operation
L/D 4.5 DP F/ 963' T/ Polish mill. Pull wear bushing. Test liner lap to 2000 psi for 10 min. Good. Blow down all surface equipment.
M/U stack wash tool & wash wealhead profile as per well head rep. Blow all surfae lines down. R/U 4.5 Tubing equipment. M/U well control XO. PJSM.
P/U 4.5 12.6# Hydrill 533 Gaslift comletion as per Tally T/ 2300'.
Off Line P/U Tree with cellar winch & Oreantate for production. Prep for install.
Cont. P/U 4.5 12.6# Hydrill 533 Gaslift comletion as per Tally F/ 2300' T/4153'. P/U SSSV and installed control line and PT to 5000 PSI for 10 min. Cont RIH F/4153'
T/4520 installing SSB on every jt. P/U 105K, S/O 85K
Changed out elevators and M/U crossovers to 4.5" DP and RIH with 1 single and a std washing down at 1 BPM observing seals ingauged at 4614'. Bled off pressure and
cont. RIH to seal extension depth of 4620.89' tagging no-go w/10K down. POOH T/4520' racking back std and L/D single of DP.
Swap elevator. L/D 1 jt and M/U pups ( 7.82', 7.82', 9.79' ) Picked single back up and RIH. M/U hanger, terminate condtrol line and M/U to hanger as per well head rep.
Installed Check valve and trapped 5000 PSI on control line. P/U landing joints and land out .95' off No-go ( seal extention depth of 4619.94' ). 30K hanging off hanger and
19 SS bands ran.
Well head rep pressued up and verified hanger seals holding. Set hanger with 6 turns to the left, rotated 3 truns right and pulled 40K on hanger to verify set. Turn
remaining 13 turns right, pull and L/D landing jts and hanger running tool. PT hanger seals to 5000 PSI for 15 min- good test. Sim-ops remove casing tong from rig floor
and R/U for MIT/MIT-IA
PT tubing to 3740 PSI and held for 30 charted min-good test. Trapped 3700 PSI in TBG and pressured up on I/A to 3200 PSI and holding at 0600.
Report Number
40
Report Start Date
10/27/2023
Report End Date
10/28/2023
Operation
Retest IA & Tubing combo test to 3000 psi. 30 Min Good. R/D Testing equipment and blow down lines and stack. Set BPV.
N/D Upper section of bell nipple & L/D Same. Break Bop conection at top deck and pick out of the way. Break conections at well head and pull riser from well bay. L/D
Same. Break off DSA & Speed head. Dress well head threads for tree flange. Having to file starting thread. P/U Tree and prep for install. Prep scafolding for rig move.
Cont. filing starter thread adapter flange. P/U and N/U tree. PT hanger void and hanger neck seals to 5000 PSI for 15 min each. Lowered down and installed SSV on
tree. Sim-ops prep rig for skidding and attempt to break free on skid rails. We were able to straighten and free up on skid beams to transverse but wasn't able to move the
rig. Preped rig floor to L/D DP
Cont. installing and torquing up SSV. R/U and pressure test tree to 5000 PSI-good test. Pull TWC from A-17 and secure well. Installed BPV in A-12B, L/D 7 stds of HWDP
and attempted to to skid with no success.
L/D 10 stds of 4.5" DP and attempt to skid again with no success. Trouble shooting hydraulics. Rig released at 06:00 hrs
API: 5088320188 Field: North Cook Inlet Unit
Sundry #: 223-031
State: Alaska
Rig/Service: 151
Well Name:NCIU A-17
API #:50883201880000 Field:North Cook Inlet Unit Start Date:11/23/2023
Permit #:223031 Sundry #:323-603 End Date:12/17/2023
11/23/2023
11/24/2023
11/25/2023
11/26/2023
11/27/2023
11/28/2023
Activity Report
R/U blow down IA with N2,
Stab pipe, P/U injector, M/U connector & test same, plumb in reverse lines & return lines to mud tank.
Mobe crews to platform, spot Eq for job, R/u control lines to reel & ops cab, run circulating lines, unload boat spot N2 Eq. SDFN
FInish R/U circulating lines, & N/U BOPE, function test same. Test BOPE 250/3500 good,SDFN
RIH w/cleanout assy. tagged @ 9170'CTM, displaced well to Drill water, POOH lost coil counter, mobed out new & replaced.
Daily Operations:
Run CBL memory log on coil, RIH blow down wellfrom IA reversing out through coil. pressured up to 1630psi, recovered 101bbls. POOH
secure well for night.
Page 1 of 3
Well Name:NCIU A-17
API #:50883201880000 Field:North Cook Inlet Unit Start Date:11/23/2023
Permit #:223031 Sundry #:323-603 End Date:12/17/2023
11/29/2023
12/10/2023
12/11/2023
12/12/2023
12/13/2023
12/16/2023
Activity Report
Daily Operations:
Moved e-line surface gear from A-18 to A-17 to flow test (A-18) and perforate (A-17). M/U 10' HSC gun and perforate the Q-1 zone
(8568'-8578'). No change in pressure. Perforate the P-2 zone (8506'-8520'), pressure slowly building. Perforate the P-1 zone (8462'-
8468')pressure continues to build. 300 psi in 7 hours. All three guns dry. Secure well and SDFN.
Rig AK E-line back on well, (SITP 3350 psi), RIH w/ GPT, locate fluid level at 8810'. M/U 3.71"OD CIBP, RIH and set at 8665' (SITP - 2950
psi). Secure well, M/U GPT tools / lubricator and move to A-18.
RIH w/ Coil t/9170', WHP 1,550psi, pressure up w/ N2 down IA to 2100psi. Swap to pumping N2 down the TxCT annulus. Reverse
circulate out 49bbls of water and trap 2,500psi of N2 on the well. POOH. All fluid recovered.
Pressure test N2 iron and lubricator to 250psi/4000psi. RIH with GPT, Fluid @ 8062ft with 2000psi of N2, pressure up to 4,000psi. Fluid
depressed to 8,230'. Swap to pumping N2 in A-18. Swap back to A-17 and pressure up from 3900psi to 4000psi. Secure well and SDFN
RU AK E-line, PT lubricator 250/3500psi. RIH and perforate Beluga S3 (8966-8980) and Beluga Q6 (8706-8716) No significant pressure
increases seen.
Perforate Beluga Q5, +3psi pressure change. Run gamma/pressure/temp and found fluid 446ft above our perfs. Pressured up well with
1590psi of gas. Fluid still rising. Secure well and wait on N2.
Page 2 of 3
Well Name:NCIU A-17
API #:50883201880000 Field:North Cook Inlet Unit Start Date:11/23/2023
Permit #:223031 Sundry #:323-603 End Date:12/17/2023
12/17/2023
Daily Operations:
Rig E-line back on well, RIH w/ GPT. Locate fluid level at 8530' (10' below P-2 perfs). PU tools to 8200' and draw well down from 2350 psi
to 2050 psi. Run log
survey, fluid level unchanged. M/U 10' perf gun, RIH, correlate and draw well down to 1600 psi. (Detected LEL at 2100 psi). Positioned
gun and shot M-2 zone at
8299' - 8309'. Secured well. Moved surface PCE to A-18 to perforate S-1 zone
Activity Report
Page 3 of 3
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%" A %" A
A
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.10.24 13:36:15 -08'00'Chelsea Wright Digitally signed by Chelsea Wright
Date: 2023.10.24 14:24:47 -08'00'
TD Shoe Depth: PBTD:
Jts.
2
1
90
22
1
Yes X No X Yes No 40
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes X No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?x Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
7/27/2023 Surface
spud mud
592 2.38
250 1.16
4
998.46
jts 9 5/8 47.0 L-80 TXP 865.71 998.46 132.75
1,011.46 1,008.61
pup 9 5/8 47.0 L-80 BTC 10.15 1,008.61
10.15 1,021.61 1,011.46
ES cementer 10 3/4 TXP 2.85
pup 9 5/8 L-80 TXP
4,623.60
jt 9 5/8 L-80 TXP 3,601.99 4,623.60 1,021.61
4,663.48 4,626.00
baffle adapter 10 3/4 TXP 2.40 4,626.00
1.38 4,664.86 4,663.48
Joint 9 5/8 L-80 TXP 37.48
float 10 3/4 TXP Summit
2 on the shoe jt, 1 on the float jt, 1 on the baffle adapter jt, 1 on every other to jt 90. 1 on 90-93. 1 on the pup above and
below ES Cementer, 1 on 94-97, every other jt till 115. for a total of 65 centralizers.
Joints 9 5/8 47.0 L-80 txp 76.32 4,741.18 4,664.86
www.wellez.net WellEz Information Management LLC ver_04818br
6659.6GL tuned prime spacer
2.5
Type of Shoe:Summit Casing Crew:Parker
12 251
Closure OKType
898 2.38
Stage Collar @
60
Bump press
6
4,742.994,750.00 4,623.60
CEMENTING REPORT
Csg Wt. On Slips:84,000
Spud mud
1,009
1011.46
15.8 51
Bump press
ES Cementer
Bump Plug?
9.2 6 54/0
0/0
70
HES
FI
R
S
T
S
T
A
G
E
10.5 62
1250
10.5
12 380 4.5
Bump Plug?
Csg Wt. On Hook:135,000 Type Float Collar:Summit No. Hrs to Run:26
1.63
72.66
30 TXP
9 5/8 L-80 BTC
112.489 5/8 L-80 TXP 39.82
TXP Summit 1.81 4,742.99 4,741.18
72.66 71.03
20.27 132.75 112.48
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.NCIU A-17 Date Run 26-Jul-23
CASING RECORD
County State Alaska Supv.Sloan Sunderland
4,664.86
Floats Held1000
Rotate Csg Recip Csg Ft. Min. PPG9.3
Shoe @ 4742.96 FC @ Top of Liner #N/A
SE
C
O
N
D
S
T
A
G
E
rig
16:00
Visual
Hanger
Casing (Or Liner) Detail
shoe
pup
jt
10 3/4
Page 1/1
Well Name: NCIU A-17
Report Printed: 1/4/2024
www.peloton.com
Casing
Liner 1
Wellbore
Wellbore Name:
Sidetrack 1 Total Depth of Wellbore (ftKB):
9,290.00 Original KB/RT Elevation (ft):
0.00
RKB to GL (ft):
0.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
Casing
Casing Description:
Liner 1 Run Date:
10/24/2023 Set Depth (ftKB):
9,289.00
Casing Weight on Slips (1000lbf):
135,000.0 Pick Up Weight (1000lbf):
190,000.0 Block Weight (1000lbf):
55,000.0
Make-Up Contractor:
Parker Number Hrs to Run (hr):
21.50 Ft/Min (ft/min):
7.20
Run Job: Set Depth (ftKB):
9,289.00 Set Depth (TVD) (ftKB):
6,999.3
Centralizer Detail:
1 on every jt to 6234' and every other jt to 4867'
Attribute Subtype: Value:
Pipe Reciprocated?:
No Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Liner Hanger 8 5/8 7.00 BTC 26.79 4,603.94 4,577.15
1 Sealing Nipple 7 3.93 BTC 25.18 4,629.12 4,603.94
24 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 949.92 5,579.04 4,629.12
1 Casing Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 20.04 5,599.08 5,579.04
25 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 990.50 6,589.58 5,599.08
1 Casing Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 10.29 6,599.87 6,589.58
17 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 674.73 7,274.60 6,599.87
1 Marker Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 39.69 7,314.29 7,274.60
7 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 278.74 7,593.03 7,314.29
1 Casing Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 10.27 7,603.30 7,593.03
17 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 676.94 8,280.24 7,603.30
1 Marker Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 39.63 8,319.87 8,280.24
7 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 279.16 8,599.03 8,319.87
1 Casing Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 10.25 8,609.28 8,599.03
15 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 596.40 9,205.68 8,609.28
1 Collar 5 2.40 1.15 9,206.83 9,205.68
1 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 39.74 9,246.57 9,206.83
1 Float Collar 5 1/2 1.88 1.27 9,247.84 9,246.57
1 Casing Joints 4 1/2 3.96 12.60 L-80 TXP-BTC 39.71 9,287.55 9,247.84
1 Float Shoe 5 1/2 1.63 1.45 9,289.00 9,287.55
Page 1/1
Well Name: NCIU A-17
Report Printed: 1/4/2024
www.peloton.com
Cement
Production Casing Cement
Type
Casing
Description
Production Casing Cement
Cemented String
Liner 1, 9,289.00ftKB
Wellbore
Sidetrack 1
Job
231-00077 NCIU A-17 Drilling, Drilling -
Drilling, 6/29/2023 00:00
Cementing Start Date
10/25/2023
Cementing End Date
10/25/2023
Top Depth (ftKB)
4,577.0
Cement Stages
Stage Number: <Stage Number?>
Description
Production Casing Cement
Top Depth (ftKB)
4,577.0
Bottom Depth (ftKB)
9,289.0
Top Measurement Method
Returns to Surface
Pump Start Date
10/25/2023
Cement in Place At
10/25/2023
Final Circulating Pressure (psi)
1,000.0
Plug Bump Pressure (psi)
2,000.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
100.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
No
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) A 11.00 30.0 30.0 5
Lead Slurry A 695 2.39 12.00 292.0 292.0 5
Tail Slurry A 185 5.58 15.30 37.0 37.0 3
Post Job Calculations
Subtype Value
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/06/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20231206
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
KBU 13-8 50133203040000 177029 11/15/2023 HALLIBURTON EPX
NCIU A-17 50883201880000 223031 11/28/2023 HALLIBURTON RBT
PBU 04-46A 50029224340100 223082 11/1/2023 HALLIBURTON RBT
PBU 05-26A 50029219840100 201221 11/24/2023 HALLIBURTON PPROF
PBU 06-20B 50029207990200 223075 10/18/2023 BAKER MRPM
PBU D-01A 50029200540100 197078 10/31/2023 HALLIBURTON RBT
PBU N-07A 50029201370100 204105 10/7/2023 BAKER SPN
PBU P1-08A 50029223840100 202199 9/22/2023 BAKER SPN
PBU P2-56 50029226100000 195162 11/14/2023 BAKER SPN
PBU P2-57A 50029221830100 202214 11/1/2023 BAKER SPN
Please include current contact information if different from above.
T38205
T38206
T38207
T38208
T38209
T38210
T38211
T38212
T38213
T38214
12/6/2023
NCIU A-17 50883201880000 223031 11/28/2023 HALLIBURTON RBT
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.06
14:25:58 -09'00'
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From:McLellan, Bryan J (OGC)
To:Ryan Rupert
Cc:Juanita Lovett; Karson Kozub
Subject:RE: [EXTERNAL] RE: NCIU A-17 CBL (PTD#223-031)
Date:Wednesday, November 29, 2023 10:46:00 AM
Ryan,
Hilcorp has approval to proceed with perforating per the approved sundry.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Wednesday, November 29, 2023 10:07 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub <kkozub@hilcorp.com>
Subject: RE: [EXTERNAL] RE: NCIU A-17 CBL (PTD#223-031)
Ryan Rupert
CIO Ops Engineer (#13088)
907-301-1736 (Cell)
907-777-8503 (Office)
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Wednesday, November 29, 2023 10:06 AM
To: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Cc: Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub <kkozub@hilcorp.com>
Subject: [EXTERNAL] RE: NCIU A-17 CBL (PTD#223-031)
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.
I think you forgot to attach the CBL
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Wednesday, November 29, 2023 10:02 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub <kkozub@hilcorp.com>
Subject: NCIU A-17 CBL (PTD#223-031)
Bryan-
Here’s the CBL for NCIU A-17. Please let us know if we have approval to perforate per attached
sundry. Thanks,
Ryan Rupert
CIO Ops Engineer (#13088)
907-301-1736 (Cell)
907-777-8503 (Office)
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis 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.
1
Regg, James B (OGC)
From:Regg, James B (OGC)
Sent:Wednesday, November 22, 2023 12:17 PM
To:Ryan Rupert
Cc:Harold Soule - (C); Juanita Lovett; Dan Marlowe; McLellan, Bryan J (OGC)
Subject:RE: Tyonek post-drill CT work
Attachments:Hilcorp Kenai Service CTU BOPE Test frequency 1-2021 final.pdf
AOGCC approves Hilcorp’s request to test SLB CT1 BOPE weekly instead of on each well for NCIU “Tyonek” wells A‐12B
(PTD 2230530), A‐17 (PTD 2230310) and A‐18 (PTD 2230330). Our approval applies only to this parƟcular request based
on the jusƟficaƟon provided (SLB CTU; all wells on same leg; 3‐well campaign). TesƟng specifics are to be as outlined in
the 1/25/2021 leƩer that addresses an alternate test interval for service coil tubing BOPE.
Jim Regg
Supervisor, Inspections
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907‐793‐1236
From: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Wednesday, November 22, 2023 10:24 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>
Cc: Harold Soule ‐ (C) <hsoule@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe
<dmarlowe@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Ryan Rupert
<Ryan.Rupert@hilcorp.com>
Subject: Tyonek post‐drill CT work
Mr. Regg‐
We have 3 new drill wells all located on Leg #1 of the Tyonek Plaƞorm. The jack‐up rig skidded back yesterday, and we
anƟcipate starƟng CT operaƟons as soon as Thu 11/23. (Harold has already put in the 48hr noƟficaƟon for BOP
test). The work will be executed campaign style unƟl all 3 wells CT scopes have been completed.. Given that the work
will be performed by Schlumberger, and all 3 wells are on the same leg, Hilcorp would like to request a variance to the
BOP tesƟng requirements. Hilcorp requests to test CT BOP’s weekly instead of on each well for this campaign. Please
advise if this is acceptable. Thank you.
Ryan Rupert
CIO Ops Engineer (#13088)
907-301-1736 (Cell)
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.
N. Cook Inlet A-17PTD 2230310
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 11/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-17 + PB1
PTD: 223-031
API: 50-883-20188-00-00 (NCIU A-17)
API: 50-883-20188-70-00 (NCIU A-17PB1)
FINAL LWD FORMATION EVALUATION LOGS (07/20/2023 to 10/23/2023)
x EWR-P4, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer – Data Main Folders:
SFTP Transfer - Data Sub-Folders:
Please include current contact information if different from above.
PTD: 223-031
NCIU A-17: T38126
NCIU A-17 PB1: T38127
11/15/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.11.15
15:04:48 -09'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2.Operator Name: 4.Current Well Class:5.Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9,290 N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Ryan Rupert
Contact Email:Ryan.Rupert@hilcorp.com
Contact Phone:(907) 777-8503
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Other: CT Operations / N2
11/20/2023
4-1/2"
LTP & SSSV 4,577 (MD) 3,354 (TVD) & 452 (MD) 452 (TVD)
9,289
Perforation Depth MD (ft):
±6,546 - ±9,206 (proposed)
4,712
±4,523 - ±6,919
6,9994-1/2"
30"
9-5/8"
384
4,743
MD
1,630psi
6,870psi
384
3,449
384
4,743
Length Size
Proposed Pools:
12.6
TVD Burst
4,620
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-031
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20188-00-00
Hilcorp Alaska, LLC
CO 68A
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
N Cook Inlet Unit A-17
N Cook Inlet N/A Tertiary System Gas
7,000 9,206 6,918 2,906psi N/A
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 7:47 am, Nov 07, 2023
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2023.11.06 16:32:18 -
09'00'
Dan Marlowe
(1267)
323-603
Perforate New Pool
BJM 11/14/23
SFD 11/8/2023 DSR-11/15/23
X
10-407
CT BOP test to 3000 psi
Submit CBL to AOGCC and obtain approval before perforating.
*&:
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.11.15 14:59:29
-09'00'11/15/23
RBDMS JSB 111623
Initial Completion
Well: NCIU A-17
Well Name:NCIU A-17 API Number:50-883-20188-00-00
Current Status:New drill gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:223-031
First Call Engineer:Ryan Rupert (907) 301-1736 (c)
Second Call Engineer:Dan Marlowe (907) 398-9904 (c)
Maximum Expected BHP:3,598 psi @ 6,919’ TVD 0.52psi/ft to deepest perf
Max. Potential Surface Pressure: 2906 psi Using 0.1 psi/ft
Brief Well Summary
Spartan 151 has successfully drilled and cased Tyonek well A-17 as part of the 2023 drilling campaign. Once
complete with the 3rd drill well on this leg, the jackup rig will leave the platform, and all 3 wells (A-17, A-18, A-
12B) will be ready for post-rig completion. The post-rig work will be executed campaign style. All proposed
perforations below are within the Tertiary System Gas Pool.
The goal of this project is to complete the well after the drilling rig leaves.
Pertinent wellbore information:
- TRSSSV installed
-Live GLV’s currently installed
- Fluids from 10/25/23
o Rig displaced 4-1/2” liner wiper plug with 10.2ppg mud
o Upper completion tubing and IA circ’d to FIW
- MIT’s on 10/27/23
o 4-1/2” liner, LTP, and 9-5/8” casing passed a 2000psi MIT
o MIT-IA passed to 3200psi
o MIT-T passed to 3700psi
All proposed
perforations below are within the Tertiary System Gas Pool.
Initial Completion
Well: NCIU A-17
Coiled Tubing Procedure
1. MIRU Coiled Tubing and pressure control equipment
2. PT lubricator to 250psi low / 3500psi high if necessary
a. SLB Coiled Tubing
b. Weekly BOP test requirement
c. All 3 wells of this CT campaign are on same leg
3. MU cleanout BHA
4. RIH to PBTD and swap well over to water
5. Obtain CBL (may be executed on EL. TBD) Submit CBL to AOOGCC
6. RIH and blow well dry with nitrogen
a. Reverse circulate water out of wellbore (no perforations, passing MIT’s)
b. Target recovery = 381bbls
i. IA Volume to bottom GLV: 241bbls
ii. Tubing Volume: 71bbls
iii. Liner volume: 70 bbls
c. Want to evacuate IA fluid through live GLV’s as well
7. RDMO CT
Beluga E-Line Perf procedure
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250psi low / 3500psi high
3. Ensure CBL approval from AOGCC before perforating
4. RIH and perforate Beluga gas sands from ±6,546 - ±9,206’ MD (±4,523’ - ±6,919’ TVD) per RE/Geo
5. RDMO EL
CONTINGENCY: (if any zone makes unwanted solids or water)
1. RU nitrogen to tubing and PT lines to 4000psi
2. Pressure up on tubing and displace water back into formation
3. MIRU E-line and pressure control equipment
4. PT lubricator to 250psi low / 3500psi high
5. Set 4-1/2” CIBP or patch per OE
6. RDMO Nitrogen and EL
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. CT BOP Drawing
4. Nitrogen procedure
±6,546 - ±9,206’ MD (±4,523’ - ±6,919’ TVD) p
_____________________________________________________________________________________
Updated By: JLL 11/3/2023
SCHEMATIC
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
4/5
1
2
3
RKB = 126.6’
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ SSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” Est. TOC @ TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ Dome
2 4,508’ 3,315’ Orifice
NOTE
7,275 RA Marker
8,280’ RA Marker
_____________________________________________________________________________________
Updated By: JLL 11/3/2023
PROPOSED
North Cook Inlet Unit
NCIU A-17
PTD: 223-031
API: 50-883-20188-00-00
PBTD =9,206’ MD / 6,918’ TVD
TD = 9,290’ MD / 7,000’ TVD
4/5
1
2
3
RKB = 126.6’
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,743’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,577’ 9,289’
4-1/2" Prod Tieback 12.6 L-80 HYD 533 3.958” Surf 4,620’
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)Item
1 452’ 452’ SSSV
2 1,009’ 1,000’ ES Cementer
3 4,562’ 3,346’ X Nipple 3.813” Profile
4 4,577’ 3,354’ Liner hanger / LTP Assembly
5 4,620’ 3,379’ Seal Stem
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 898 sx
4-1/2” Est. TOC @ TOL (50% excess) L – 695 sx / T – 185 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
BEL ±6,546 ±9,206 ±4,523 ±6,919 ±2,660 Future Proposed
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,010’ 1,864’ Dome
2 4,508’ 3,315’ Orifice
NOTE
7,275 RA Marker
8,280’ RA Marker
SLB Stack Drawing
Not Drawn To Scale--- For Reference Only
2 1/16 10M
Flanged
Plug Valve
(Manual)
from KP
Well Floor
HR 580 Injector Head with 72" Gooseneck
4.06" 10K Conventional Stripper – 1.75"
C062 Pin Connection
Manual
2 1/16 10M
Provided by client
Blind/Shear
Pipe/Slip
4 1/16 10M
Combi BOP
Lubricator to
Injector Head
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
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:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Subject:RE: Live GLMs in the tie-back on Tyonek A-17 and A-12B wells
Date:Friday, October 6, 2023 3:57:00 PM
Sean,
Hilcorp has approval to make the proposed changes to the approved PTD’s for A-17 (PTD 223-031)
and A-12B (PTD 223-053).
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Friday, October 6, 2023 2:12 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Live GLMs in the tie-back on Tyonek A-17 and A-12B wells
Bryan,
The tie-back plan on Tyonek wells A-17 and A-12B has changed to include running live GLMs instead
of GLMs with dummy valves. Instead of a tubing and IA test, a CMIT will be performed followed by a
MIT-T. I view this as a minor change but wanted to ensure no agency approval is required.
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
1
Regg, James B (OGC)
From:Regg, James B (OGC)
Sent:Thursday, July 20, 2023 10:57 AM
To:Sean McLaughlin
Cc:McLellan, Bryan J (OGC)
Subject:RE: [EXTERNAL] RE: A-17 exhaust manifold
API 64 is silent on what constitutes an ignition source and also the required separation distance between diverter vent
line outlet and ignition source. AOGCC regs don’t define ignition source but we have always considered it to include
electrical equipment, fired equipment, exhaust points, and mobile sources (e.g, fork lift) excluding potential sources that
are contained in explosion proof enclosures. Regulation says separation must extend at least 75 ft from potential
ignition source. We will accept adding one 20‐foot pipe section to get to 73 feet of separation (leaves you with 25‐foot
overhanging pipe according your note below). If that is still objectionable to the rig and Hilcorp, we need to see load
calculations for the vent line with the extra 20‐foot pipe section identifying the concern.
Jim Regg
Supervisor, Inspections
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907‐793‐1236
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, July 20, 2023 4:20 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Re: [EXTERNAL] RE: A‐17 exhaust manifold
Jim,
I’d also like some confirmation of what an ignition source is. Does the AOGCC have some guidance or reference a
particular publication? I’ve read in OSHA that a muffler can be a source and a hot surface can certainly be a source. If
the auto ignition temperature of Methane is 1050F, what does the AOGCC consider a safe exhaust temperature?
Regards,
Sean
On Jul 19, 2023, at 6:45 PM, Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> wrote:
Jim,
The concern was if adding unsupported pipe was the right thing to do in this scenario and how much is
to much unsupported 16” pipe. There is no option on a Texas deck and I’m unsure of the length of
unsupported pipe used. Also, in that case the rig is the ignition source and shouldn’t be shut down.
2
The exhaust in question is coming from the reboiler on the second level. It is a good 20’ run. The
exhaust is warm but not hot like a generator exhaust. I didn’t look at it as a source during diverter
operations because of the planned platform shut down and abandonment.
We only have 20’ sections of 16” diverter available. Adding one section would get us out to 73’
separation and make 25’ of overhanging pipe. But the rig was told to ensure the distance is more than
75’.
If 35’ is added (we have a 5’ that would be removed) then we would be at 88’ for the exhaust stack and
there would be 40’ of unsupported pipe. That is when the rig stopped the job and questioned what they
were doing and why. I agreed that 40’ of unsupported 16” felt wrong.
As far a communications from the rig to the platform go there are three modes currently. 1) Gaitronics
to the whole platform and the control room. 2) the general rig alarms sound in the control room. 3) the
driller has a hand held radio to talk to the controller room. The production team on the platform
controls ESD of the platform.
I couldn’t find any guidance in API with respect to unsupported pipe so figured I’d ask.
Regards,
Sean
On Jul 19, 2023, at 5:55 PM, Regg, James B (OGC) <jim.regg@alaska.gov> wrote:
Sean – Please describe
1.Concern about lengthening the diverter vent line to achieve the regulatory
requirement; how is this concern different if the rig were drilling a grass roots
well with diverter on Texas deck? Refer to attached photos.
2.Describe reliance on ESD – communications, who controls platform shutdown,
who makes notification if well is flowing (what if Driller is not at Drilling Station)
Understood is the restriction regarding drilling limited to favorable wind direction.
Jim Regg
Supervisor, Inspections
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907‐793‐1236
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Wednesday, July 19, 2023 4:36 PM
To: Regg, James B (OGC) <jim.regg@alaska.gov>
Subject: A‐17 exhaust manifold
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
3
Jim this is what the diverter and rig up looks like and the exhaust vents.
The request would be to leave as rigged up with 53’ between exhaust and vent. The
concern is hanging 20’ of 16” pipe off the side of the platform.
1.Only drill ahead if favorable wind direction.
2.ESD platform if on divert operation
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907‐223‐6784
The information contained in this email message is confidential and may be legally privileged and is intended only for
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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
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
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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,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Enterprise 151 Diverter - NCIU A-17; Tyonek Platform
Enterprise 151 Diverter - NCIU A-17; Tyonek Platform
Vent line outlet
Enterprise 151 Diverter - NCIU A-17; Tyonek Platform
Enterprise 151 Diverter - NCIU A-17; Tyonek Platform
Enterprise 151 Diverter - NCIU A-17; Tyonek Platform
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________N COOK INLET UNIT A-17
JBR 09/05/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:1
Remarks:5" joint. Operator was to extend vent line to be at least 75' from ignition source (exhaust stack) post me leaving the platform.
TEST DATA
Rig Rep:Dave HebertOperator:Hilcorp Alaska, LLC Operator Rep:Steve Dambacher
Contractor/Rig No.:Enterprise 151 PTD#:2230310 DATE:7/19/2023
Well Class:DEV Inspection No:divSAM230725075358
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
Test Time:2
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:NA NA
Designed to Avoid Freeze-up?NA
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:100 P
Closest Ignition Source:53 F
Outlet from Rig Substructure:80 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:NA
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:21 P
Knife Valve Open Time:7 P
Diverter Misc:0 NA
Systems Pressure:P3100
Pressure After Closure:P2100
200 psi Recharge Time:P22
Full Recharge Time:P107
Nitrogen Bottles (Number of):P16
Avg. Pressure:P2400
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
NA NAMud System Misc:
9
9 9
9
9
9
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Operator was to extend vent line to be at least 75' from ignition source
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CAUTION: This email originated from outside the State of Alaska mail system.
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the content is safe.
From:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Cc:Regg, James B (OGC); Rixse, Melvin G (OGC)
Subject:RE: A-17 PTD questions (223-031)
Date:Wednesday, June 28, 2023 3:20:00 PM
Sean,
The Spartan 151 rig will have completed BOP testing on the subsea P&A prior to starting work on
NCIU A-17, therefore the BOP test frequency can be increased from once per week to once every 14
days, assuming reasonably good performance of the BOP stack on the subsea P&A.
The other conditions of approval on the PTD are necessary to reduce the uncertainty of the wellbore
position given close approach and elevated wellbore collision risk with the nearby wellbores.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Tuesday, June 27, 2023 9:23 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: A-17 PTD questions (223-031)
Bryan,
Just following up on the questions below.
Regards,
sean
From: Sean McLaughlin
Sent: Thursday, June 15, 2023 11:01 AM
To: Bryan J McLellan (CED) <bryan.mclellan@alaska.gov>
Subject: A-17 PTD questions (223-031)
Bryan,
I have a few questions/concerns about several of the COA’s in the recently issued A-17 PTD.
Could a standard 14 day BOPE test be considered? The rig and BOP system is currently
working, the rig has not been shut down more than a year, rig leadership has not changed,
the majority of the Spartan crew is not new to Alaska operations and most were recently
working on the Monopod 56 rig, and it is summer time so cold weather issues are not
present.
I’ve attached the current surveys for B-03A and A-13. We believe the surveys (gyro based)
give a clear position and trajectory. B-03A has good data points in the area of concern. A-13
has clean surveys to 300’ then from 500’ on. The trajectory is consistent between the two
points. Do you agree the existing surveys give a good trajectory of the offsets to plan a
divergent course? The directional experts we work with believe they do.
Could the requirement for 30’ eline surveys to 600’ be re-written to be based on need?
Frequent gyro surveys are an absolute necessity getting started. Within 100’ there is
expected to be gravity tool face and NBI available. This would reduce the need for 30’ drop
surveys. Also, magnetics may clean up much sooner than the 600’ requirement which will
make 30’ gyro data not very useful. Also, when drilling a known divergent course (as opposed
to a collision course) the distance to the offset is increasing which typically reduces the
required survey spacing. Also, please note that directional tools are often swapped to
increase certainty.
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: North Cook Inlet Unit, Tertiary System Gas Pool, NCIU A-17
Hilcorp
Permit to Drill Number: 223-031
Surface Location: 1249’ FNL, 973’ FWL, Sec 6, T11N, R9W, SM, AK
Bottomhole Location: 1098’ FNL, 1083’ FWL, Sec 1, T11N, R10W, SM, 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 June, 2023. 14
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.06.14
14:14:15 -08'00'
SFD 6/12/2023 DSR-4/4/23
50-883-20188-00-00223-031
Initial BOP test to 5000 psi if the first well drilled in the 2023 campaign.
Subsequent BOP tests to 3500 psi, subsequent annular tests to 2500 psi.
BOP test frequency is weekly if this is the first well drilled in the 2023 campaign.MITIA to 3000 psi.
BJM 6/13/23
Perform Gyro surveys in Wells NCIU B-03, NCIU A-13 and NCIU A-17 every 30 ft MD from 300'-600' MD, using the same gyro tool to reduce anticollision uncertainty.
Submit FIT/LOT data within 48 hrs of obtaining data.
GCW 06/14/2023
JLC 6/14/2023
06/14/23
06/14/23
Brett W. Huber, Sr.Digitally signed by Brett W.
Huber, Sr.
Date: 2023.06.14 14:15:14 -08'00'
Will any valves be left on the wellhead? Kill string?
See attached diagram.
BOP test frequency is weekly for the first well in the 2023 drilling campaign. -bjm
Initial BOP test to RWP for the first well in the 2023 drilling campaign. -bjm
Verify with Jim Regg that only one diverter line is acceptable.
Close approach failed. Shut-in these wells and set plugs while drilling these close approaches. -bjm
Shut-in A-13 while drilling from
conductor to 600' MD. bjm
Perform gyro surveys every 30 ft MD minimum in wells A-13, B-03A and A-17 from 300' - 600' MD. Use the same tool for all wells to reduce error.
Also, see attached email with additional anti-collision discussion -bjm
Typo?
Verified cement calcs. -bjm
Verified cement calcs. -bjm
50% of 9-5/8" 47# L-80 burst = 6870 psi x 0.5 = 3435 psi. - bjm
Initial BOP test to 5000 psi.
Cement calc discrepency between 1.4 x vs. 1.5 x excess stated above.
What is justification for 2000 psi MITIA with a 2940 psi MPSP?
MITIA to 3000 psi, per attached email.
A-13 to remain shut-in while drilling
though close-approach from conductor
to 600' MD. -bjm
Perform gyro surveys every 30 ft MD minimum in wells A-13, B-03A and A-17 from 300' - 600' MD. Use the same tool for all wells to reduce error. -bjm
1
Davies, Stephen F (OGC)
From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent:Tuesday, May 23, 2023 9:35 AM
To:Davies, Stephen F (OGC)
Cc:McLellan, Bryan J (OGC); Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] NCIU_A-17 (PTD #223-031) - Questions
Steve,
Answerstoquestionsareinredbelow.
Regards,
sean
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Monday,May22,202312:45PM
To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>
Subject:[EXTERNAL]NCIU_AͲ17(PTD#223Ͳ031)ͲQuestions
Sean,
I’mreviewingHilcorp’sPermittoDrillapplicationforNCIUAͲ17.Hilcorpisplanningtodrillsurfaceholeinthiswellto
4677’md(3430’TVD),which—accordingtomywelllogcorrelations—isabout300trueverticalfeetdeeperthanthetop
oftheTertiarySystemGasPoolinthisarea.Alsoaccordingtomycorrelations,Hilcorp’splannedcasingpointappearsto
beonlyabout30’TVDshallowerthanthetopoftheSterlingXsand,whichisperforatedinnearbywellNCIUAͲ03.
Questions:
x Isthiscorrect?
Yes,yourcorrelationiscorrect.
x Ifso,sincethisplannedgapbetweenthecasingpointandthetopoftheSterlingXsandissonarrow,what
measureswillHilcorptaketopreventinadvertentlydrillingintotheSterlingXsand?
WeplantouserealͲtimelogs(GR/RES)inconcertwithournearbywellcontrol(AͲ03:~1,500’awayandAͲ13:~
1,200’away)toaccuratelypickthesurfacecasingpoint.
GiventhenearbywellsandpredictablestructureGR/RESlogcorrelationwillbesufficienttoplacecasingas
planned.
x Ifso,whatmitigationmeasuresareinplaceshouldHilcorpinadvertentlydrillintotheSterlingXsandand
encountersignificantgas?
TheSterlingXisadepletedgassandwhichhasbeendrilledthrough8timesinthelasttwoyears.Therehas
beennoLCeventsinthosepenetrations.Intheeventoflostcirculationinletwaterissufficienttokeepthehole
full.
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2
x Ifnot,howfarabovetheshallowestknownorsuspectedgasͲbearingsandwillsurfacecasingbeset?
30’TVDor~50’MD
x TheperforationsintheSterlingXsandwithinNCIUAͲ03arecurrentlyisolated.WasthissandgasͲbearing?Ifso,
howmuchgaswasrecoveredfromthesand?
Correct,itwasgasbearing.Unfortunately,thissandwascomingledwithUpperBelugasandsandwedonot
haveanaccuratehistoricalpictureofindividualsandcontribution(noproductionlogdata).
x AreanysandsonthisstructureshallowerthantheSterlingXsandknownorsuspectedtobegasͲbearingonthis
structure?
No,basedonreviewofAͲ13,BͲ01,andBͲ03mudlogs.
x Ifso,whywastheplannedcasingpointchosenandwhatmeasuresdoesHilcorpplantomitigateriskof
unexpectedlydrillingintoshallowgas?
Thesurfacecasingsetpointwaschosenbasedonthereviewofmudlogsandoffsetwellhistoricaldata.There
arenoknownshallowgashazardsabovethecasingsetpoint.ConocoandtheAOGCCcameupwiththesame
assessmentin2009whenAͲ14,15,16weredrilled.Hilcorpisusingthesamecasingsetpointasthatcampaign.
Thankyouforyourhelp.InoticethattheestimatedspuddateforthewellislistedontheapplicationasJune1st.Isthis
planneddatestillaccurate?
WithasuccessfultestoftheP&AwellheadtheplannedspuddateisnowJune15th.
Thanksagainandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
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.
NCIU A-17
TERTIARY SYSTEM GAS
223-031
NORTH COOK INLET
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-17Initial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230310NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes Surface Location lies within ADL0017589; Top Prod Int & TD lie within ADL0037831.2 Lease number appropriateYes3 Unique well name and numberYes NORTH COOK INLET, TERTIARY GAS - 5645704 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For seNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedNo Close approach where exiting conductor to 550'. Will run Gyro surveys to reduce positional uncertainty.26 Adequate wellbore separation proposedYes Single diverter. Will shut-down drilling if wind direction is unfavorable.27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP 2940 psi. Rated to 5000 psi. (Initial test to 5000 psi. Subsequent test to 3500 psi).30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)No Batch drilling surface hole for A-17, then move to A-18, then return to drill production hole on A-17.32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not anticipated.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pore pressure gradient ranges from 8.3 to 10.0 ppg EMW.36 Data presented on potential overpressure zonesNA Will be drilled with 8.8 to 10.4 ppg mud. Planned mud weights appear sufficient to37 Seismic analysis of shallow gas zonesNA control forecast pressures. Some potential for drilling depleted sands; LCM will be available onsite.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/22/2023ApprBJMDate6/13/2023ApprSFDDate6/12/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 06/14/2023JLC 6/14/2023
From:Sean McLaughlin
To:McLellan, Bryan J (OGC)
Cc:Rixse, Melvin G (OGC)
Subject:RE: [EXTERNAL] NCIU A-17 PTD questions
Date:Friday, June 9, 2023 10:59:34 AM
Bryan,
Thank you for the conversation yesterday. I have added more specific drill planning verbiage per
your request. There are two close approaches when drilling out the A-17 conductor. Both have
been reviewed internally and externally to determine a departure strategy. Typically, setting a plug
in an offset well is a mitigation. Most often the new drill is on a collision course with an offset and
there are little to no other mitigations. In the case of A-17 (conductor drill out), the AC failure is the
result of the starting point. At the depth when the conductor is exited there is a close approach
from the neighboring conductor. Every foot that is drilled the new well will be gaining departure.
Some details of the drill plan are as follows:
Review offset well for directional accuracy. B-03A has an existing gyro survey that was
reviewed.
Determine the best method for ensuring correct toolface when starting new hole. Both
Gyrodata and Sperry prefer a drop gyro survey (rather than GWD) to orient the toolface
correctly prior to drillout. Using both GWD and drop gyro were considered but determined to
be no reduction in risk and using both systems could cause confusion.
Frequent gyros will be obtained when initiating drilling to ensure the tool face is correct and
the drill path is on plan. Ranging was considered however the amount of casing (multiple
casing strings) would make magnetization difficult and the duration of magnetization is
unknown.
A repeat gyro will be made not more than 20’ from the start of the well.
A mill tooth bit will be used (instead of the conventional PDC bit). Per drill bit vendor and
company reps, the mill tooth bit is unlikely to penetrate casing. A milltooth bit is much more
likely to track casing as the formation as the formation and cement will drill easier than steel.
Control drill at less than 80 ft/hour to allow more time for reaction.
With respect to the A-13 close approach:
There will be no injection during the close approach
A-13 is not a flow to surface well
Losses are not expected base on data from multiple penetrations over the last two years.
Regards,
sean
From: Sean McLaughlin
Sent: Friday, May 26, 2023 3:53 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Bryan,
The risk of penetrating A-13 is minimal as it has 0 psi tubing pressure when shut in. It is not a flow to
surface well. The drilling risk would be lost circulation due to the 9.0ppg drilling mud. Typically
injection occurs every 3 days and is possible to time the drill by so injection is not occurring.
Setting a shallow plug and fluid loading in B-03A is possible but not advisable. See concerns listed
below regarding LTSI and fluid loading. Again, setting a plug is a layer of protection from gas to
surface. Additional layers are not needed as discussed below. The focus is foremost on collision
avoidance. This really boils down to frequent gyro shots. The other preventative measure is about
collision detection. In this scenario, a collision will be detected prior to penetration.
If there are gaps in the collision avoidance plan please let me know. If you don’t believe a collision
can be detected prior to penetration let’s talk that through. If you believe penetration of multiple
casing strings while drilling parallel to an offset is more than an unlikely event I like to understand
the rational. Setting a plug in an offset wells would mean the other mitigations are not robust
enough. If there are gaps in the mitigations please let me know.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, May 26, 2023 2:15 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Sean,
The Anti-Collision report mentions two close approach failures, B-03A, which you discuss below, and
A-13, which isn’t mentioned below. The PTD application says A-13 is a disposal well. What are the
risks of drilling into this well? Can it be shut-in while drilling by?
As for B-03A, can a shallow plug be set below the potential intersection point and fluid loaded on top
of the plug?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Wednesday, May 24, 2023 4:27 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan,
As you know identifying a close approach is about recognition and is required in the permitting
process. Evaluating the risk and mitigation is a responsibility Hilcorp takes very seriously. Avoidance
is often used as a barrier however, the close approach is unavoidable in this case due to nearby wells
as the bit exits the conductor.
Offset well B-03A is a gas producer with a SBHP of 380 psi and a flowing tubing pressure of 160 psi.
The risk being evaluated is gas to surface. The following were the preventative measures that were
factored in when developing the drilling plan.
The relative position and location of the offset conductors are verified and understood.
The offset survey has been reviewed and the as drilled azimuth is known. B-03A has a good
1998 Gyrodata survey.
A gyro will be run prior to drilling new hole
Repeat gyro’s will be run to confirm the as drilled position and path. The second drop gyro will
be run within 20’ of new hole. Frequent gyro check shots is the best method for collision
avoidance.
A mill tooth bit (as opposed to a PDC) will be used to mitigate against penetration of steel.
The smooth gauge and cone configuration make casing penetration very difficult with a low
angle of incidence. The penetration risk of two vertical wells is very low because of the
intersection angle.
Control drill at less than 80 ft/hour to allow more time for reaction.
The 20” 133# casing of the offset well is fully cemented to surface and is a significant barrier
to gas.
When milling near parallel, the bit will preferentially track on the outside of the 20” casing
due to the relative weaker compressive strength of the cement and formation.
Ditch magnets will be in place an monitored while drilling. Should penetration of the 20#
casing occur an estimated 140# of metal would be expected prior to contact with the 13-3/8”
72# casing.
Clear stop points are in place should drilling parameters change (vibration, torque, motor
work), directional concerns arise, or cement or metal be observed at surface.
The 13-3/8” 72# casing of the offset well is fully cemented to surface and is also a significant
barrier to gas.
When milling near parallel the mill tooth bit is expected to hang up on a slab of 20” casing
making rotation difficult, if not impossible. It is likely a cone would be lost during this event.
Drilling parameters would be very erratic.
Ditch magnets will be in place an monitored while drilling. Should penetration of the 13-3/8”
casing occur an estimated 210# of metal would be expected prior to contact with the 9-5/8”
53.5# casing.
The 9-5/8” 53.5# casing of the offset well is fully cemented to surface and is also a significant
barrier to gas.
When milling near parallel the 12-1/4” mill tooth bit would be working on 20” and 13-3/8”
casing strings making rotation difficult, if not impossible. It is likely a cone would be lost
during this event and no forward progress would be possible.
Ditch magnets will be in place an monitored while drilling. Should penetration occur of the 9-
5/8” an estimated 245# of metal would be expected prior to contact with the 4-1/2” tubing.
And finally, should the 9-5/8” casing be penetrated an open annuli is present. Annuli
monitoring will be in place to detect a breach in the 9-5/8” casing.
Given the relatively low frequency of collisions coupled with engineering, mechanical, and
administrative barriers in place the likelihood of gas to surface is extremely low.
Setting a plug in B-03A was evaluated as an additional layer of protection. A few reasons an offset
plug was not required as a mitigation are:
Sufficient mitigations already in place to make the probability low.
Plug setting is incremental work that increases personal safety.
Collision avoidance is the best defense for preventing gas to surface.
And most importantly, shutting in B-03A may permanently harm future production or
reserves.
In recent years Hilcorp has not observed adverse impacts at the Tyonek Platform as a
result of short shut-in events (less than 8 days) and this is due to our Operating
philosophy – avoiding shut-in’s at all costs to prevent any possibility of damaging wells.
Experience has shown that wells could experience liquid loading (since all gas wells
make water) and due to current reservoir pressures fail to unload when brought online.
It should also be noted when water comes in contact with the Beluga formation, it can
be damaging, reducing the gas relative permeability as well as causing the breakdown
of the reservoir sands which could lead to sanding events when the well is brought
online.
B-03A is on Leg 1 of the Tyonek Platform, the same leg that we will be drilling the 2
grassroots and 1 sidetrack well from. The duration of these drilling operations is
anticipated to be 74 days, if a plug is set we would need to do so prior to 151’s arrival
and then we would not be able to pull it until the rig leaves due to operational footprint
of the rig. We have experienced shorter duration Operational shut-in, but this would
be an unprecedented shut-in duration of which we cannot predict what would happen
to the B-03A well.
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Hilcorp has fully reviewed mitigation for the close approach, collision risk, and potential for gas to
surface and does not suggest any changes to the current plan.
Regards,
Sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, May 23, 2023 3:36 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Sean,
The close approach issue needs to be resolved. It’s one of the checks commissioners look at before
they sign off on a PTD. Usually it’s resolved by tweaking the directional or setting a plug in the
offsets. We definitely don’t advocate drilling into the outer annulus of the offset well as a
mitigation. If you run frequent check shots can you get a pass on the close approaches? If so, how
frequent do you need to run them?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Sunday, May 21, 2023 9:34 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Re: [EXTERNAL] NCIU A-17 PTD questions
Correction/typo on #8. GL pressure is around 1000 psi. Not 100 psi.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
Sean
On May 19, 2023, at 4:21 PM, Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
wrote:
Bryan,
Please find answers in red below.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, May 19, 2023 1:36 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] NCIU A-17 PTD questions
Sean,
A few questions regarding the PTD application.
1. Could you send a proposed wellbore diagram with higher resolution? Some of
the numbers are illegible.
Attached
2. Is it possible to pressure test your diverter/conductor before you start drilling?
The equipment does not have the ability to test the diverter/conductor.
3. Need more justification for leaving Close approach failure wells on line while
drilling past them.
It is fortunate that so many great mitigations are available for these close
approaches (Bit selection, Gyro shots, Annuli monitoring, and multiple casing
strings). In fact, it would be more of a hazards to mobilize wireline, RU
lubricator, set plug, PT, then have a second rig up to pull the plug.
4. What is the depth and reservoir pressure of the injection zone just above surface
casing TD?
The top disposal zone is at 3307’ TVD and the bottom is at 3415’ TVD. The
shut-in WHP of the injection string in B-01 is 0 psi, so assuming a water
gradient of 0.43 psi/ft to 3307’ = 1422 psi.
5. Could you send the product specs for 12 ppg EconoCem?
Halliburton hasn’t loaded or tested for this job so no UCA or TT data available.
Below is the properties we ask for:
<image006.png>
6. How will your wellhead be configured after cementing surface casing and
moving to NCIU A-18? Send a diagram.
A blind flange is nippled up to the wellhead and a gate valve on the side outlet
for monitoring. I’ll see if Cactus can make a drawing on Monday.
<image002.png>
7. 4-1/2” liner cement job calculation uses 1.4 x excess, but text in step 19.6 calls
for 1.5 times excess.
40% excess in the calculation is correct.
8. What is the basis for the 2000 psi MITIA after running tubing? What is max gas
lift header pressure?
2000 psi is what the liner top will be tested to based on the following:
1. 10.1 ppg mud and 2000 psi @ 3420’ TVD = 178klbs force on the
4-1/2” liner (62%)
2. 2000 psi and 10.1 ppg mug equates to 21.3 ppg EWM
The 2000 psi MITIA was a consistent value to the liner top test and shows
tie back seal integrity. The casing and wellhead was tested to 3500 psi in
step 14.3.
Tyonek gas lift pressure runs around 100 psi.
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image001.jpg>
<NCI A-17 Proposed Schematic 3-21-23.pdf>
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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
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From:Sean McLaughlin
To:McLellan, Bryan J (OGC); Dan Marlowe
Cc:Ryan Rupert; Aras Worthington; Monty Myers
Subject:RE: [EXTERNAL] NCIU A-17 PTD questions
Date:Tuesday, June 13, 2023 1:46:37 PM
Yes, Please. I agree as well.
Can you make the same change to A-18 or would you like me to resubmit the PTD?
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, June 13, 2023 1:36 PM
To: Dan Marlowe <dmarlowe@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Dan,
I’m in agreement.
Sean, are you on board with a 3000 psi MITIA test pressure? Should I modify the PTD accordingly?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Dan Marlowe <dmarlowe@hilcorp.com>
Sent: Monday, June 12, 2023 10:00 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Sean McLaughlin
<Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
It should be tested to above MPSP, in this case 3,000 psi.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, June 12, 2023 9:21 AM
To: Dan Marlowe <dmarlowe@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Dan,
What do you believe to be an appropriate initial MIT-IA test pressure for this new well and what is
the reasoning?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Dan Marlowe <dmarlowe@hilcorp.com>
Sent: Friday, June 9, 2023 1:28 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Sean McLaughlin
<Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan
As you know, the calculated drilling MPSP at 2,940 psi. This is our worst case scenario on Tyonek . All
other production or injection MPSP’s fall below drilling MPSP.
Artificial lift on Tyonek is ~1,000 psi so anything in the 1,250 to 1,500 psi range addresses lift
pressure.
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Injectors on Tyonek are fairly shallow and are tested to 0.25 psi/ft or 1,500 psi whichever is greater
per regulation:
A-08 has an MIT-IA to 1,500 psi
A-13 has an MIT-IA to 2,500 psi
All wells have daily casing pressure monitoring with a backup report that flags any variance above
10% to town staff. We also have procedures in place that document any bleed events that occur.
Thanks
Dan
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, May 30, 2023 10:00 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Sean,
The relevant regulations for pressure testing in producing wells are:
During well construction, 20 AAC 25.030(d)(6) Test liner lap to 50% of casing burst, same as
the casing test, for any well type. The A-17 PTD application does not include a plan to test the
liner lap to 50% of surface casing burst.
As you sited below, injectors have a specific MITIA test pressure requirement, not relevant to
A-17.
During the producing phase, 20 AAC 25.205(d) Regulation is silent on the value of the test
pressure, so we are looking for an engineering basis for test pressure here. The premise is
that you should test to at least as high as you anticipate seeing the pressure throughout the
life of the well. Need to consider the pressure the well might see at any depth from the
wellhead down to the liner lap or packer. In the absence of other justification, we simply test
to Max Potential Surface Pressure (MPSP) calculated using reservoir pressure minus a gas
gradient of 0.1 psi/ft, but also need to look at potential artificial lift pressures that might be
imposed. Unfortunately, testing the wellhead to this pressure over a column of mud might
impose a test pressure at the packer that is higher than necessary.
Dan,
The reason I brought the OE into this conversation is that the life-of-well pressures are more a
production issue than a drilling issue. If Hilcorp wants to test to something lower than MPSP, then
possibly they can justify it with wellhead pressure monitoring and bleed protocol, or something else.
Can Hilcorp create a minimum MITIA test pressure basis for the different types of wells on the
platform, and get buyoff from AOGCC, so that we are all on the same page whenever a new PTD is
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
submitted? The drilling pressure test basis might be higher, but would need to be calculated on a
well-by-well basis, but at least we would know the minimum from a production standpoint.
Thanks and regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Friday, May 26, 2023 2:59 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan,
For and existing well on Tyonek a 1500 psi IA test is well above MASP and gas lift pressure. Also,
while it really doesn’t apply, a 1500 psi test fits 20 AAC 25.412c.
For a new drill the casing will be tested to ~50% at least 50% of casing burst and be above MASP for
that hole section and initial production. In the case of A-17 that is a 3500 psi casing test.
Could you help me find which regulation states that an IA test is required after running tubing in a
new drill? A Tubing test shows one envelope and Casing test shows the other. Is a MIT-IA required
after running the tubing? I thought I knew the regulation but now can’t find it.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, May 26, 2023 2:07 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
What’s the basis for the 1500 psi test pressure?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Friday, May 26, 2023 2:04 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan,
Please continue to route questions through me so I can get to the right person and there is a clear
line of communication for PTD’s.
Ryan Rupert is the Offshore Ops engineer and we have already conferred about the necessary
mechanical integrity for A-17. 1500 psi would be a usual IA test for Tyonek wells. Take B-03A, which
was drilled last year, as an example. It currently has a BHP of 380 psi. The casing and wellhead is
tested to 3500 psi after installation. After the liner run, the liner lap and seal test to 2000 psi would
show sufficient integrity for those components. The tubing hanger is tested with a 3000 psi pack off
test.
Regards,
sean
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Tuesday, May 23, 2023 3:53 PM
To: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: FW: [EXTERNAL] NCIU A-17 PTD questions
Ryan,
Do you want to answer Bryan’s question for him. Let me know if you want to chat about it.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or
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Chad
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, May 23, 2023 3:39 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Subject: FW: [EXTERNAL] NCIU A-17 PTD questions
Chad,
What do you test the MIT-IA’s to on Tyonek and what is the basis? See question 8 in the email
below.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Sunday, May 21, 2023 9:34 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Re: [EXTERNAL] NCIU A-17 PTD questions
Correction/typo on #8. GL pressure is around 1000 psi. Not 100 psi.
Sean
On May 19, 2023, at 4:21 PM, Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
wrote:
Bryan,
Please find answers in red below.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, May 19, 2023 1:36 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] NCIU A-17 PTD questions
Sean,
A few questions regarding the PTD application.
1. Could you send a proposed wellbore diagram with higher resolution? Some of
the numbers are illegible.
Attached
2. Is it possible to pressure test your diverter/conductor before you start drilling?
The equipment does not have the ability to test the diverter/conductor.
3. Need more justification for leaving Close approach failure wells on line while
drilling past them.
It is fortunate that so many great mitigations are available for these close
approaches (Bit selection, Gyro shots, Annuli monitoring, and multiple casing
strings). In fact, it would be more of a hazards to mobilize wireline, RU
lubricator, set plug, PT, then have a second rig up to pull the plug.
4. What is the depth and reservoir pressure of the injection zone just above surface
casing TD?
The top disposal zone is at 3307’ TVD and the bottom is at 3415’ TVD. The
shut-in WHP of the injection string in B-01 is 0 psi, so assuming a water
gradient of 0.43 psi/ft to 3307’ = 1422 psi.
5. Could you send the product specs for 12 ppg EconoCem?
Halliburton hasn’t loaded or tested for this job so no UCA or TT data available.
Below is the properties we ask for:
<image006.png>
6. How will your wellhead be configured after cementing surface casing and
moving to NCIU A-18? Send a diagram.
A blind flange is nippled up to the wellhead and a gate valve on the side outlet
for monitoring. I’ll see if Cactus can make a drawing on Monday.
<image002.png>
7. 4-1/2” liner cement job calculation uses 1.4 x excess, but text in step 19.6 calls
for 1.5 times excess.
40% excess in the calculation is correct.
8. What is the basis for the 2000 psi MITIA after running tubing? What is max gas
lift header pressure?
2000 psi is what the liner top will be tested to based on the following:
1. 10.1 ppg mud and 2000 psi @ 3420’ TVD = 178klbs force on the
4-1/2” liner (62%)
2. 2000 psi and 10.1 ppg mug equates to 21.3 ppg EWM
The 2000 psi MITIA was a consistent value to the liner top test and shows
tie back seal integrity. The casing and wellhead was tested to 3500 psi in
step 14.3.
Tyonek gas lift pressure runs around 100 psi.
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image001.jpg>
<NCI A-17 Proposed Schematic 3-21-23.pdf>
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From:McLellan, Bryan J (OGC)
To:McLellan, Bryan J (OGC)
Subject:FW: [EXTERNAL] NCIU A-17 PTD questions
Date:Tuesday, June 13, 2023 3:20:26 PM
Attachments:image002.png
See temporary wellhead below.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Tuesday, June 13, 2023 3:11 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan,
The THA will already be on location so we opted to use that and a valve.
Sean
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, June 13, 2023 3:06 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Sean,
Were you able to get the temporary wellhead diagram from Cactus, showing how it will be left after drilling surface
hole and moving to A-18?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
