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Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
06/09/2025
Mr. Jack Lau
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor
through 06/09/2025.
Dear Mr. Lau,
Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off
with cement, corrosion inhibitor in the surface casing by conductor annulus through 06/09/2025.
Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement
fallback during the primary surface casing by conductor cement job. The remaining void space
between the top of the cement and the top of the conductor is filled with a heavier than water
corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached
spreadsheets include the well names, API and PTD numbers, treatment dates and volumes.
As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that
the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations.
If you have any additional questions, please contact me at 564-4891 or
oliver.sternicki@hilcorp.com.
Sincerely,
Oliver Sternicki
Well Integrity Supervisor
Hilcorp North Slope, LLC
Digitally signed by Oliver
Sternicki (4525)
DN: cn=Oliver Sternicki (4525)
Date: 2025.06.09 14:30:46 -
08'00'
Oliver Sternicki
(4525)
Hilcorp North Slope LLC.Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-offReport of Sundry Operations (10-404)06/09/2025Well NamePTD #API #Initial top of cement (ft)Vol. of cement pumped (gal)Final top of cement (ft)Cement top off date Corrosion inhibitor (gal)Corrosion inhibitor/ sealant dateF-10C21308650029204100365/29/25F-29B2111475002921627026.25/29/25F-33A20816350029226400145/29/25F-3619519650029226310035/29/25F-39190141500292210100175/29/25F-44A2051615002922130012.55/29/25F-47B21007950029222320215/29/25L-2512231065002923772001.8813/31/24117/29/24L-2532230485002923758004.1201.13/31/24127/29/24L-2542230305002923752003.8321.23/31/24137/29/24L-2922230255002923751003.3301.33/31/24147/29/24N-282141275002923524006.8504.711/19/242212/28/24N-302141245002923523003.5330.311/17/243.512/28/24PAVE1-122309450029237670019.910/27/24PWDW3-221908150029236340014.810/27/24S-40120607850029233130015.31130.511/15/24412/28/24PAVE1-122309450029237670019.910/27/24
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Friday, April 5, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Guy Cook
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
PAVE 1-1
PRUDHOE BAY UNIT PAVE 1-1
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 04/05/2024
PAVE 1-1
50-029-23767-00-00
223-094-0
W
SPT
8119
2230940 2500
1857 1846 1859 1858
309 595 561 548
INITAL P
Guy Cook
2/15/2024
Initial MITIA to 2500 per PTD 223-094 within 10 days of injection. Testing was completed with a Little Red Services pump truck and
calibrated gauges.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PRUDHOE BAY UNIT PAVE 1-1
Inspection Date:
Tubing
OA
Packer Depth
127 2773 2756 2749IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitGDC240214181752
BBL Pumped:4.6 BBL Returned:4.3
Friday, April 5, 2024 Page 1 of 1
7. Property Designation (Lease Number):
1. Operations
Performed:
2. Operator Name:
3. Address:
4. Well Class Before Work:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
Susp Well Insp
Install Whipstock
Mod Artificial Lift Perforate New Pool
Perforate
Plug Perforations
Coiled Tubing Ops
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well Other:
Change Approved Program
Operations shutdown
11. Present Well Condition Summary:
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
16. Well Status after work:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
OIL GAS
WINJ WAG GINJ
WDSPL
GSTOR Suspended SPLUG
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
PBU PAVE1-1
Acid Stimulation
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
223-094
50-029-23767-00-00
13978
Conductor
Surface
Intermediate
Production
Liner
8857
78
4774
13261
851
13888
20"
13-3/8"
9-5/8"
7"
8778
48 - 126
47 - 4821
44 - 13305
13122 - 13973
48 - 126
47 - 3518
44 - 8272
8109 - 8853
none
2260
4760
7020
none
5020
6870
8160
13538 - 13848
7-5/8" 29.7# x 7" 26# L-80 42 - 13128
8477 - 8744
Structural
7" TNT , 13034 , 8031
No SSSV
13034
8031
Bo York
Operations Manager
Dave Bjork
David.Bjork@hilcorp.com
(907) 564-4672
PRUDHOE BAY, PRUDHOE OIL
Total Depth
Effective Depth
measured
true vertical
feet
feet
feet
feet
measured
true vertical
measured
measured
feet
feet
feet
feet
measured
true vertical
Plugs
Junk
Packer
Measured depth
True Vertical depth
feet
feet
Perforation depth
Tubing (size, grade, measured and true vertical depth)
Packers and SSSV
(type, measured and true vertical depth)
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.Representative Daily Average Production or Injection Data
Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure
Prior to well operation:
Subsequent to operation:
15. Well Class after work:
Exploratory Development Service StratigraphicDaily Report of Well Operations
Copies of Logs and Surveys Run
Electronic Fracture Stimulation Data
Sundry Number or N/A if C.O. Exempt:
ADL 0028326
42 - 8114
Perforations 13538 - 13848
Pumped 120 bbls of 9:1 Mud Acid at 650 psi
0
0
0
0
40699
47721
10
10
1555
1327
324-220
13b. Pools active after work:PRUDHOE OIL
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
Sr Pet Eng: Sr Pet Geo:
Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Sr Res Eng:
Due Within 30 days of Operations
By Grace Christianson at 11:51 am, Sep 12, 2024
Digitally signed by Bo York
(1248)
DN: cn=Bo York (1248)
Date: 2024.09.12 11:16:52 -
08'00'
Bo York
(1248)
DSR-9/13/24
CDW 09/13/2024
RBDMS JSB 091924
WCB 10-7-2024
ACTIVITYDATE SUMMARY
8/15/2024
SLB Acid Stimulation. Pump the folliwng as per schedule: 60 bbs of 3% NH4CL+
Musol, 440 bbls of 3% NH4CL, 30 bbls of 12% HCL, 30 bbls of 9:1 MUD acid, 15 bbls
of 3% NH4CL, 7 bbls of Oilseeker diversion, 15 bblsm of NH4CL, Pump same for 3
more stages. See decrease in tubing pressure as 1st acid hits perfs. Shut down
pump when oilseeker hit perfs for 4 mins. Brought pump back online at min rate (2
bpm) to maintain positive pressure. Wait for 2nd Oilseeker to hit perfs shut down and
wait 5 mins. TP has a slower fall off to 65 psi, bring pump online at min rate and
pump NH4CL at 2 bbls for 12 bbls to allow oilseeker to gain viscosity. Ramp rate up
to 7 bpm to push 3 stage of acid behind pipe. Perform same 3rd Oilseeker stage.
Pump 70 bbls of NH4CL+ Musol. Displace with 650 bbls of 3% NH4CL. Shut down
and monitor well. In 15 mins tubing pressure slowly decreased from 650 psi to a Vac.
Shut in well and start Rigging down.
Tota fluids pumped:
120 bbls of 12% HCL acid
120 bbls of 9:1 MUD acid
130 bbls of 3% NH4CL + Musol
1860 bbls of 3% NH4CL
21 bbls of Oilseeker
Daily Report of Well Operations
PBU PAVE1-1
Pump the folliwng as per schedule: 60 bbs of 3% NH4CL+g
Musol, 440 bbls of 3% NH4CL, 30 bbls of 12% HCL, 30 bbls of 9:1 MUD acid, 15 bbls
of 3% NH4CL, 7 bbls of Oilseeker diversion, 15 bblsm of NH4CL, Pump same for 3
more stages. See decrease in tubing pressure as 1st acid hits perfs. Shut downgg
pump when oilseeker hit perfs for 4 mins. Brought pump back online at min rate (2g(
bpm) to maintain positive pressure. Wait for 2nd Oilseeker to hit perfs shut down and)
wait 5 mins. TP has a slower fall off to 65 psi, bring pump online at min rate andg
pump NH4CL at 2 bbls for 12 bbls to allow oilseeker to gain viscosity. Ramp rate upgy
to 7 bpm to push 3 stage of acid behind pipe. Perform same 3rd Oilseeker stage.g
Pump 70 bbls of NH4CL+ Musol. Displace with 650 bbls of 3% NH4CL
Tota fluids pumped:
120 bbls of 12% HCL acid
120 bbls of 9:1 MUD acid
130 bbls of 3% NH4CL + Musol
1860 bbls of 3% NH4CL
21 bbls of Oilseeker
7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in this pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd?Yes No
Subsequent Form Required:
Approved By:Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU PAVE 1-1
Acid Stimulation
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK
99503
223-094
50-029-23767-00-00
0028326
13978
Conductor
Surface
Intermediate
Production
Liner
8857
78
4774
13261
851
13888
20"
13-3/8"
9-5/8"
7"
8779
48 - 126
47 - 4821
44 - 13305
13122 - 13973
2344
48 - 126
47 - 3518
44 - 8272
8109 - 8853
none
2270
4760
4790
none
4930
6870
6890
13538 - 13848 7-5/8" 29.7# x 7" 26# L-80 42 - 131288477 - 8744
Structural
7" TNT
No SSSV
13034 8031
Date:
Bo York
Operations Manager
Dave Bjork
David.Bjork@hilcorp.com
(907) 564-4672
PRUDHOE BAY
5/1/2024
Current Pools:
PRUDHOE OIL
Proposed Pools:
PRUDHOE OIL
Suspension Expiration Date:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov
/
Digitally signed by Bo York
(1248)
DN: cn=Bo York (1248)
Date: 2024.04.11 15:35:39 -
08'00'
Bo York
(1248)
324-220
By Grace Christianson at 1:26 pm, Apr 16, 2024
* Maximum BHP at sand face to stay below confining zone fracture gradient.
2344
SFD 4/20/2024
CDW 04/18/2024
MGR18APR24
ADL0028326 SFD
10-404
DSR-4/23/24*&:
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2024.04.23
15:17:09 -08'00'04/23/24
RBDMS JSB 042624
Mud Acid
Well: PAVE 1-1
PTD: 223-094
API: 50-029-23767-00
Well Name:PAVE 1-1 API Number:50-029-23767-00
Current Status:Operable – Online – PWI Rig:Fullbore
Estimated Start Date:May 1 2024 Estimated Duration:1 day
AFE:Cost:
IOR:Version:1
Regulatory Contact:Carrie Janowski
First Call Engineer:Dave Bjork (907) 564-4672 (O)(907) 440-0331 (M)
Second Call Engineer:Dave Wages (713) 380-9836 (M)
Current Bottom Hole Pressure:3224-psi @ 8,800’ TVDss 7.1 PPGE
Max Anticipated Surface Pressure:2344-psi (Based on 0.1 psi/ft gas gradient)
Last SI WHP:0 psi
Min ID:5.625” @ 13,069’ MD 7” HES ‘R’ Nipple
Max Angle:64 deg @ 5,190’
Brief Well Summary:
December 2023 new drill large bore injector. It was brought online in February injecting ~33,000BPD at 1,800-
psi of produced water for pressure maintenance. The well is currently under injecting by ~12,000BPD. Prosper
modelling indicates that we have a skin factor over 100. Acid jobs on PBE injectors have shown significant
improvement in individual well injectivity. Expected uplift from this job is 12,000 bwpd based on offsets.
Objective:
Mud acid treatment.
Procedure:
Fullbore/Special Projects –
1. SLB pumping: Pump the following pump schedule:
a. RU to pump down the tree cap
b. Pressure test to 4,000-psi
c. Ensure OE is either on the slope or on the phone for job
d. Pressure up IA to 500-psi and monitor throughout job.
e. Initial Max pressure is 2,200-psi.
f. Max rate: 7 BPM
i. Well is currently taking 23 BPM
g. When divert stages hit perfs, be prepared to hesitate to allow the OilSeeker to gain viscosity.
Depending on if the well goes on a vacuum, we may extend the hesitation duration.
i. Slow pump rate to ~1 BPM before OilSEEKER hits top perf
h. For every divert stage, we expect pressure to increase. Since the fluids are all fairly close to the
same density, the increase in pressure should be associated with backpressure from the
diverter. The pressure increase seen while diverter on bottom is how much we can increase
max treating pressure.
i. For example: initial: 2,200-psi max
1. After 1
st diversion: 100-psi pressure bump seen, Max pressure adjusted to
2,300-psi
2. After 2
nd diversion: 50-psi pressure bump seen, Max pressure adjusted to
2,350-psi
3. After 3
rd diversion: 200-psi bump seen. Max pressure adjusted to 2,550-psi
Maximum BHP at sand face to stay below confining zone fracture gradient. -mgr
Mud Acid
Well: PAVE 1-1
PTD: 223-094
API: 50-029-23767-00
i. Wellbore integrity: Do not exceed pressure is 4,000-psi.
Ops –
POI ~ 1 hour after SLB shuts in. We want to take advantage of cold fluid injection potentially improving well
injectivity, but it gives time for the musol to break down the oilseeker diverter.
Mud Acid
Well: PAVE 1-1
PTD: 223-094
API: 50-029-23767-00
Fluid Recipes:
Fluid Type:Ammonium Chloride (NH4Cl)
Code Description Concentration
J285 Ammonium Chloride 417.0 (lbm/1000gal)
A264A Corrosion Inhibitor 0.0 (gal/1000gal)
F103 EZEFLO* Surfactant 0.0 (gal/1000gal)
L066 Acid Compatible Scale Inhibitor 0.0 (gal/1000gal)
U067 Mutual Solvent 0.0 (gal/1000gal)
W054 Non-Emulsifying Agent 0.0 (gal/1000gal)
W060 Sludge and Emulsion Preventer 0.0 (gal/1000gal)
A153 Inhibitor Aid 0.0 (lbm/1000gal)
L041 Chelating Agent 0.0 (lbm/1000gal)
L056 Scale Removal Agent 0.0 (lbm/1000gal)
L058 Iron Stabilizer 0.0 (lbm/1000gal)
Fluid Type:10% HCl
Code Description Concentration
H036 Hydrochloric Acid 10.0 (% HCl final)
A201 Inhibitor Aid 0.0 (gal/1000gal)
A255 H2S Scavenger 0.0 (gal/1000gal)
A264A Corrosion Inhibitor 4.0 (gal/1000gal)
F103 EZEFLO* Surfactant 2.0 (gal/1000gal)
L066 Acid Compatible Scale Inhibitor 0.0 (gal/1000gal)
U067 Mutual Solvent 0.0 (gal/1000gal)
W054 Non-Emulsifying Agent 5.0 (gal/1000gal)
W060 Sludge and Emulsion Preventer (gal/1000gal)
A153 Inhibitor Aid 0.0 (lbm/1000gal)
L041 Chelating Agent (lbm/1000gal)
L056 Scale Removal Agent (lbm/1000gal)
L058 Iron Stabilizer 20.0 (lbm/1000gal)
Mud Acid
Well: PAVE 1-1
PTD: 223-094
API: 50-029-23767-00
Fluid Type:9:1 Mud Acid
Code Description Concentration
H036 Hydrochloric Acid 10.0 (% HCl final)
B055 Ammonium Fluoride 1.0 (% HF final)
A201 Inhibitor Aid 0.0 (gal/1000gal)
A255 H2S Scavenger 0.0 (gal/1000gal)
A264A Corrosion Inhibitor 6.0 (gal/1000gal)
F103 EZEFLO* Surfactant 2.0 (gal/1000gal)
L066 Acid Compatible Scale Inhibitor 0.0 (gal/1000gal)
U067 Mutual Solvent 0.0 (gal/1000gal)
W054 Non-Emulsifying Agent 5.0 (gal/1000gal)
W060 Sludge and Emulsion Preventer (gal/1000gal)
A153 Inhibitor Aid 0.0 (lbm/1000gal)
L041 Chelating Agent (lbm/1000gal)
L056 Scale Removal Agent (lbm/1000gal)
L058 Iron Stabilizer 20.0 (lbm/1000gal)
Fluid Type:Overflush - NH4Cl + U066
Code Description Concentration
J285 Ammonium Chloride 417.0 (lbm/1000gal)
U067 Mutual Solvent 100.0 (gal/1000gal)
A264A Corrosion Inhibitor 0.0 (gal/1000gal)
F103 EZEFLO* Surfactant 0.0 (gal/1000gal)
L066 Acid Compatible Scale Inhibitor 0.0 (gal/1000gal)
U067 Mutual Solvent 0.0 (gal/1000gal)
W054 Non-Emulsifying Agent 0.0 (gal/1000gal)
W060 Sludge and Emulsion Preventer 0.0 (gal/1000gal)
A153 Inhibitor Aid 0.0 (lbm/1000gal)
L041 Chelating Agent 0.0 (lbm/1000gal)
L056 Scale Removal Agent 0.0 (lbm/1000gal)
L058 Iron Stabilizer 0.0 (lbm/1000gal)
Mud Acid
Well: PAVE 1-1
PTD: 223-094
API: 50-029-23767-00
Fluid Type:Oilseeker
Code Description Concentration
J285 Ammonium Chloride 417.0 (lbm/1000gal)
J590 OilSeeker 75.0 (gal/1000gal)
A264A Corrosion Inhibitor 0.0 (gal/1000gal)
F103 EZEFLO* Surfactant 0.0 (gal/1000gal)
L066 Acid Compatible Scale Inhibitor 0.0 (gal/1000gal)
U067 Mutual Solvent 0.0 (gal/1000gal)
W054 Non-Emulsifying Agent 0.0 (gal/1000gal)
W060 Sludge and Emulsion Preventer 0.0 (gal/1000gal)
A153 Inhibitor Aid 0.0 (lbm/1000gal)
L041 Chelating Agent 0.0 (lbm/1000gal)
L056 Scale Removal Agent 0.0 (lbm/1000gal)
L058 Iron Stabilizer 0.0 (lbm/1000gal)
Mud Acid
Well: PAVE 1-1
PTD: 223-094
API: 50-029-23767-00
Current Wellbore Schematic:
Mud Acid
Well: PAVE 1-1
PTD: 223-094
API: 50-029-23767-00
Hilcorp Alaska, LLC
Changes to Approved Sundry Procedure
Date:
Subject:
Sundry #:
Any modifications to an approved sundry will be documented and approved below. Changes to an approved
sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change
is required before implementing the change.
Step Page Date Procedure Change
HAK
Prepared
By (Initials)
HAK
Appro
By (Init
Approval:
Operations Manager Date
Prepared:
Operations Engineer Date
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: 2/16/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240208
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
END 1-27 50029216930000 187009 2/6/2024
YELLOW
JACKET PERF
KU 13-06A 50133207160000 223112 2/7/2024
YELLOW
JACKET GPT
MPU G-18 50029231940000 204020 2/8/2024 READ Caliper Survey
MPU B-28 50029235660000 216027 1/15/2024
YELLOW
JACKET PATCH
PBU PAVE 1-1 50029237670000 223094 1/5/2024
YELLOW
JACKET CBL
SRU 241-33B 50133206960000 221053 2/8/2024
YELLOW
JACKET GPT
Please include current contact information if different from above.
T38513
T38514
T38515
T38516
T38517
T38518
2/21/2024
YELLOW
PBU PAVE 1-1 50029237670000 223094 1/5/2024 JACKET CBL
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2024.02.21
09:17:43 -09'00'
By Grace Christianson at 12:24 pm, Feb 23, 2024
Completed
1/29/2024
JSB
RBDMS JSB 022924
G
DSR-3/21/24
Drilling Manager
02/21/24
Monty M
Myers
Digitally signed by Bo York
(1248)
DN: cn=Bo York (1248)
Date: 2024.02.22 16:12:21 -
09'00'
Bo York
(1248)
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU PAVE 1-1 Date:12/1/2023
Csg Size/Wt/Grade:13.375" 68# L-80 Supervisor:Barber/Amend
Csg Setting Depth:4821 TMD 3518 TVD
Mud Weight:9.3 ppg LOT / FIT Press =916 psi
LOT / FIT =14.31 ppg Hole Depth =4849 md
Fluid Pumped=4.5 Volume Back =4.0 bbls
Estimated Pump Output:0.093 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->668 ->6167
->12 176 ->12 380
->18 292 ->18 600
->24 408 ->24 760
->30 509 ->30 930
->36 610 ->36 1130
->42 698 ->42 1390
->48 778 ->48 1550
->54 854 ->54 1760
->60 914 ->60 1980
->62 916 ->66 2180
->64 900 ->72 2400
-> ->78 2657
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0900 ->02657
->1836 ->12651
->2820 ->22650
->3814 ->32648
->4806 ->42646
->5796 ->52645
->6788 ->10 2635
->7780 ->15 2625
->8772 ->20 2620
->9766 ->25 2616
->10 760 ->30 2612
-> ->
-> ->
-> ->
0
6
12
18
24
30
36
42
48
54
606264
0
6
12
18
24
30
36
42
48
54
60
66
72
78
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 102030405060708090
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
900
836820814806796788780772766760
265726512650264826462645 2635 2625 2620 2616 2612
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU PAVE 1-1 Date:1/10/2024
Csg Size/Wt/Grade:9.625", 47#, L-80 Supervisor:Barber/Amend
Csg Setting Depth:13305 TMD 8271 TVD
Mud Weight:8.7 ppg LOT / FIT Press =960 psi
LOT / FIT =10.93 ppg Hole Depth =13307 md
Fluid Pumped=3.4 Volume Back =3.4 bbls
Estimated Pump Output:0.093 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->10 316
->485 ->20 613
->8262 ->30 914
->12 380 ->40 1218
->16 496 ->50 1488
->20 614 ->60 1774
->24 728 ->70 2058
->28 844 ->80 2349
->32 960 ->90 2655
-> ->100 2948
-> ->110 3250
-> ->120 3550
-> ->130 3861
-> ->140 4163
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0960 ->04173
->1950 ->14172
->2939 ->24171
->3932 ->34170
->4925 ->44169
->5920 ->54168
->6916 ->10 4165
->7912 ->15 4160
->8908 ->20 4158
->9904 ->25 4157
->10 901 ->30 4156
-> ->
-> ->
-> ->
0
4
8
12
16
20
24
28
32
10
20
30
40
50
60
70
80
90
100
110
120
130
140
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
4100
4200
4300
4400
4500
0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
960950939932925920916912908904901
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
ACTIVITYDATE SUMMARY
1/21/2024
N/D BOP riser, clean and inspect void, TBG HGR neck and lift threads. Press in
SBMS. Fill void w/ test oil, install new BX160. N/U tree. R/U test equipment and test
void to 500/5,000 psi for 10 min ea. Passed. Assist rig during tree test. Pull 6" J-
plug w/ dry rod. S/B for rig to freeze protect. Set J BPV #423 for Rig Move
1/24/2024
T/I/O=BPV/0/0. Post Parker 273. Rotated MV to correct orientation, Installed Upper
Tree, Installed flanged check to WV, Torqued all flanges to spec, Pulled 6" J BPV,
Set 6" J TWC. PT'd full tree against TWC 350/5000 PSI (Pass). Pulled 6" J TWC.
RDMO. Final WHP's 0/0/0.
1/24/2024
***WELL S/I ON ARRIVAL***
RAN 5.625" PR-PLUG BODY, S/D IN 5,963" R-NIPPLE @ 2,465' (UNABLE TO
PASS THROUGH)
RIH W/ 5.625" PR-PLUG BODY
***CONTINUE 1/25/24***
1/24/2024
T/I/O= 30/38/202 (NEW WELL POST) Assist SL *** Job continued to 01-25-2024 ***.
**Man Down Drill Complete**
1/25/2024
***Job continued from 01/24/2024*** Assist SL - MIT-T to 4,343 psi ****PASSED****
Target Pressure= 4,000 psi - Max Pressure= 4,400 psi - MIT-IA to 3,222 psi
****PASSED**** Target Pressure= 3,300 psi - Max Pressure= 3,300 psi - Pumped
3.4 bbls of Diesel down TBG to test plug. Pumped 6 bbls of Diesel down TBG to
reach 4,369 psi. 1st 15-minute loss of 16 psi, 2nd 15-minute loss of 10 psi, for a total
loss of 26 psi in 30 minutes. Bled back ~8.8 bbls. Pumped 6.1 bbls of Diesel down IA
to reach 3,222 psi. 1st 15-minute loss of 10 psi, 2nd 15-minute loss of 3 psi, for a
total loss of 13 psi in 30 minutes. Bled back ~5.1 bbls. State witness waived by Brian
Bixby
SL in control of well upon departure.
FWHPs= 250/50/150
1/25/2024
***CONTINUE FROM 1/24/24***
SET 5.625" PR PLUG & PRONG @ 13,069' MD
LRS SET PACKER & PERFORMED A PASSING MIT-T TO 4,000 PSI
LRS PERFORMED A PASSING MIT-IA TO 3,000 PSI
PULLED PRONG & 5.625" PR PLUG BODY FROM 13,069' MD
DRIFT W/ 33' OF 3-3/8" DUMMY GUNS, S/D @ 13,888' MD
***CONTINUE 1/26/24***
****1700# OFF BTM 25 FPM**** (WEIGHT GETS BETTER @ 12,500' MD)
1/26/2024
***CONTINUE FROM 1/25/24***
RIG DOWN POLLARD # 59
***WELL LEFT S/I***
1/26/2024
*** WELL S/I ON ARRIVAL*** OBJECTIVE: PERFORATE INTERVAL W/3 3/8''
BASIX GUN 6 spf 60 DEG PHASE
MIRU YELLOW JACKET E-LINE.
REQUEST TO HAVE SCOFFOLD ON TO WELL HEAD,
LAY DOWN FOR THE NIGHT
***CONTINUE JOB ON 1/27/24***
Daily Report of Well Operations
PBU PAVE1-1
Daily Report of Well Operations
PBU PAVE1-1
1/27/2024
*** JOB CONTINUED FROM 1/26/2024***
STANDBY PER WEATHER
***JOB CONTINUE ON 1/28/2024***
1/28/2024
YJOS ELINE Weather Standby
***In Progress***
1/29/2024
***JOB CONTINUE FROM 1/28/2024*** OBJECTIVE: PERFORATE TWO
INTERVAL W/3 3/8'' GEO BASIX GUN 6 spf 60 DEG PHASE
PT PCE 300 PSI LOW./3000 PSI HIGH
RUN#1 W/CH/2.75'' GUN GAMMA/30' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13818'-13848'
CCL TO TOP SHOT=10.5' CCL STOP DEPTH= 13807.5' MD
RUN#2 W/CH/2.75'' GUN GAMMA/30' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13788'-13818'
CCL TO TOP SHOT=10.5' CCL STOP DEPTH= 13777.5' MD
ALL GAMMA RAY LOG CORRELATE TO HES MD LOG DATED 13-JAN-2024
LAY DOWN FOR THE NIGHT
***CONTINUE JOB ON 1/30/24***
1/30/2024
***JOB CONTINUE FROM 1/29/2024*** OBJECTIVE: PERFORATE TWO
INTERVAL W/3 3/8'' GEO BASIX GUN 6 spf 60 DEG PHASE
PT PCE 300 PSI LOW./3000 PSI HIGH
RUN#3 W/CH/2.75'' GUN GAMMA/28' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13760'-13788'
CCL TO TOP SHOT=12.5' CCL STOP DEPTH= 13747.5' MD
RUN#4 W/CH/2.75'' GUN GAMMA/30' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13694'-13724'
CCL TO TOP SHOT=10.5' CCL STOP DEPTH= 13683.5' MD
RUN#5 W/CH/2.75'' GUN GAMMA/30' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13664'-13694'
CCL TO TOP SHOT=10.5' CCL STOP DEPTH=13653.5' MD
ALL GAMMA RAY LOG CORRELATE TO HES MD LOG DATED 13-JAN-2024
LAY DOWN FOR THE NIGHT
***CONTINUE JOB ON 1/31/24***
Daily Report of Well Operations
PBU PAVE1-1
1/31/2024
***JOB CONTINUE FROM 1/30/2024*** OBJECTIVE: PERFORATE TWO
INTERVAL W/3 3/8'' GEO BASIX GUN 6 spf 60 DEG PHASE
PT PCE 300 PSI LOW./3000 PSI HIGH
RUN#6 W/CH/2.75'' GUN GAMMA/30' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13634'-13664' CCL TO TOP SHOT=10.5' CCL
STOP DEPTH=13623.5' MD
RUN#7 W/CH/2.75'' GUN GAMMA/30' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13604'-13634' CCL TO TOP SHOT=10.5' CCL
STOP DEPTH=13593.5' MD
RUN#8 W/CH/2.75'' GUN GAMMA/30' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13574'-13604' CCL TO TOP SHOT=10.5' CCL
STOP DEPTH=13563.5' MD
ALL GAMMA RAY LOG CORRELATE TO HES MD LOG DATED 13-JAN-2024
LAY DOWN FOR THE NIGHT
***CONTINUE JOB ON 2/1/24***
2/1/2024
***JOB CONTINUE FROM 1/31/2024*** OBJECTIVE: PERFORATE TWO
INTERVAL W/3 3/8'' GEO BASIX GUN 6 spf 60 DEG PHASE
PT PCE 300 PSI LOW./3000 PSI HIGH
RUN#9 W/CH/2.75'' GUN GAMMA/18' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13556'-13574'
CCL TO TOP SHOT=11.3' CCL STOP DEPTH= 13544.7' MD
RUN#10 W/CH/2.75'' GUN GAMMA/18' OF 3 3/8'' GEO BASIX GUN 6 spf 60 DEG
PHASE TO PERFORATE INTERVAL 13538';-13556'
CCL TO TOP SHOT=11.3' CCL STOP DEPTH= 13526.7' MD
ALL GAMMA RAY LOG CORRELATE TO HES MD LOG DATED 13-JAN-2024
JOB COMPLETE
***WELL S/I ON DEPARTURE***
2/2/2024
***WELL S/I ON ARRIVAL***(set A-1 sssv)
RAN 2' X 1-7/8" STEM, BRUSH, 5.93" GAUGE RING, BRUSHED THROUGH SSSV
NIPPLE DOWN TO 2,472' SLM
SET 7" A-1 INJECTION SSSV IN R-SVLN @ 2,462' MD (sn: BWS-139, 1 set std pkg,
5.963" lock, sec lkdwn installed)
***WELL LEFT SHUT IN ON DEPARTURE***
2/11/2024
T/I/O = 1820/80/0. Temp = 126°. Assist ops with POP. IA, OA FL @ surface. Well
brought online, monitored pressure build on IA, OA, Bled IAP, OAP to BT as needed
throughout day (4.92 bbls). Bled IAP, OAP to 0 psi before departure. Final WHPs =
1820/0/0.
SV = C. WV, SSV, MV = O. IA, OA = OTG. 18:00
2/12/2024
T/I/O = 885/650/200. Temp = 130°. Assist ops with POP. IA, OA FL @ surface.
Ops brought online, testing choke, meter & fluid sources. Monitored pressure build
on IA, OA. Ble IAP, OAP to BT as needed throughout day ( 4.5 bbls). Bled IAP, OAP
to 0 psi before departure. Final WHPs = 1920/0/0.
SV = C. WV, SSV, MV = O. IA, OA = ATG. 17:30
2/15/2024
AOGCC MIT-IA (NEW WELL POST) AOGCC MIT-IA to 2749 psi ***PASS*** Max
Applied= 2750 psi Target = 2500 psi
Pumped 4.6 bbls 150* DSL to take IA to 2773 psi. IA lost 17 psi in 1st 15 mins and 7
psi in 2nd 15 mins for a total loss off 24 psi in 30 min test. Bled back ~4.3 bbls. DSO
notified of well status per LRS departure.
*Witnessed by State Rep Cook and WIC Holt
**Tags hung on IA
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:PB Wells Integrity
To:Brooks, Phoebe L (OGC); Regg, James B (OGC); Wallace, Chris D (OGC)
Cc:PB Wells Integrity; Oliver Sternicki
Subject:Hilcorp (PBU) January 2024 MIT Forms
Date:Friday, February 2, 2024 1:27:26 PM
Attachments:Jan 2024.zip
All,
Attached are the completed MIT forms for the tests completed in January 2024 by Hilcorp North
Slope, LLC.
Well: PTD: Notes:
04-20 1831190 4-year MIT-IA
14-25 1831020 4-year MIT-IA
14-35 1831420 2-year MIT-IA per AA AIO 4E.021
J-09C 2191480 2-year MIT-T & CMIT-TxIA per CO 736
P1-01 1900270 2-year MIT-IA per AA AIO 4G.012
P2-34 1950660 2-year MIT-IA per AA AIO 4G.013
PAVE1-1 2230940 Initial offline MIT-T & MIT-IA post rig
PWDW1-2A 1901180 4-year MIT-IA
S-22B 1970510 4-year MIT-IA
S-34 1921360 4-year MIT-IA
S-210 2190570 2-year MIT-IA per AA AIO 25A.021 (tested to 1.1 x PWI header
pressure)
S-201 2190920 Offline diagnostic MIT-IA while Under Eval for TxIA. Failed
S-210 2190570 2-year MIT-T per AA AIO 25A.021
S-210 2190570 2-year MIT-IA per AA AIO 25A.021 (tested to 1.1 x MI header
pressure)
W-24 1880700 2-year MIT-IA per AA AIO 3B.001
W-35 1880330 2-year MIT-IA per AA AIO 3C.002
W-223 2110060 4-year MIT-IA
X-20A 2071130 4-year MIT-IA
Z-103 2042290 MIT-IA to inform AA application
Please respond with any questions or concerns.
Andy Ogg
Hilcorp Alaska LLC
Field Well Integrity
andrew.ogg@hilcorp.com
P: (907) 659-5102
M: (307)399-3816
PBU PAVE1-1
PTD 2230940
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230940 Type Inj N Tubing 72 4369 4353 4343 Type Test P
Packer TVD 8030 BBL Pump 9.4 IA 79 229 229 226 Interval I
Test psi 2008 BBL Return 8.8 OA 210 224 229 230 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230940 Type Inj N Tubing 197 818 821 823 Type Test P
Packer TVD 8030 BBL Pump 6.1 IA 0 3222 3212 3209 Interval I
Test psi 2008 BBL Return 5.1 OA 193 560 549 544 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp North Slope LLC
Prudhoe Bay / PBU / PAVE
Waived by Brian Bixby
Jerry Culpepper
01/25/24
Notes:Offline MIT-T post rig
Notes:
Notes:
Notes:
PAVE1-1
PAVE1-1
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Offline MIT-IA post Rig
Notes:
Notes:
Form 10-426 (Revised 01/2017)2024-0125_MIT_PBU_PAVE1-1_2tests
J. Regg; 5/6/2024
David Douglas Hilcorp North Slope, 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:
Hilcorp North Slope, LLC
Date: 02/02/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: PAVE1-1
PTD: 223-094
API: 50-029-23767-00-00
FINAL LWD FORMATION EVALUATION LOGS (11/10/2023 to 01/11/2024)
ROP, AGR, DGR, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Surveys
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-094
T38476
2/2/2024Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.02.02
15:33:38 -09'00'
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: 1/31/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240131-1
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
NCI A-13 50883200870000 192106 1/10/2024 READ Caliper
PBU B-27C 50029214710300 215184 12/24/2023 HALLIBURTON RBT
PBU N-22C 50029213490300 223086 1/18/2024 HALLIBURTON RBT
PBU PAVE 1-1 50029237670000 223094 1/8/2024 HALLIBURTON CAST-CBL
PBU PAVE 1-1 50029237670000 223094 12/29/2023 HALLIBURTON CAST-CBL
PBU PAVE 1-1 50029237670000 223094 12/31/2023 HALLIBURTON CAST-CBL
PBU S-102A 50029229720100 223058 12/30/2023 HALLIBURTON RBT
Please include current contact information if different from above.
T38462
T38463
T38464
T38465
T38465
T38465
T38466
2/1/2024
PBU PAVE 1-1 50029237670000 223094 1/8/2024 HALLIBURTON CAST-CBL
PBU PAVE 1-1 50029237670000 223094 12/29/2023 HALLIBURTON CAST-CBL
PBU PAVE 1-1 50029237670000 223094 12/31/2023 HALLIBURTON CAST-CBL
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2024.02.01
16:16:30 -09'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Brett Anderson - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Frank Roach
Subject:PBE PAVE 1-1 BOPE test Parker 273 01-17-2024
Date:Wednesday, January 17, 2024 4:15:04 PM
Attachments:Pave 1-1 Hilcorp BOPE Test - Parker 273 1-17-24.xlsx
All,
Please see attached BOPE test report for Parker 273 on PBE PAVE 1-1.
Brett Anderson
Hilcorp DSM, Parker 273
Office: 907-659-5673
Mobile: 907-240-6258
brett.anderson@hilcorp.com
Alternate: Shane Barber
sbarber@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, 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.
3%83$9(
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSubmit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 1/17/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230940 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: X Bi-Weekly: Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2338
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 3P
Test Fluid Water Inside BOP 2P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP
#1 Rams 1 7-5/8" Fixed 5M P Flow Indicator PP
#2 Rams 1 Blind Shear 5M P Meth Gas Detector PP
#3 Rams 1 3.5"x 5.5" VBR 5M P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M P System Pressure (psi)3100 P
Kill Line Valves 2 2-1/16", 3-1/8" 5M P Pressure After Closure (psi)2200 P
Check Valve 0NA200 psi Attained (sec)16 P
BOP Misc 0NAFull Pressure Attained (sec)60 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2512 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 29 P
#1 Rams 6 P
Coiled Tubing Only:#2 Rams 6 P
Inside Reel valves 0NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:9.0 HCR Choke 2 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1/15/2024 @14:01
Waived By
Test Start Date/Time:1/16/2024 19:00
(date) (time)Witness
Test Finish Date/Time:1/17/2024 4:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Kam StJohn
Parker
Tested with 4", 5" and 7-5/8" test joint. Tested annular to 3000 psi. All test performed with water. No failures.
Jon King
Hilcorp North Slope
B. Anderson/ B. LaFleur
PBU PAVE 1-1
Test Pressure (psi):
rig273mgr@parkerwellbore.com
brett.anderson@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0117_BOP_Parker273_PBU_PAVE1-1
9
9 9
9
9
9 9 9 9
9
9
9
-5HJJ
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:Brett Anderson - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Frank Roach; Robert Tool Pusher
Subject:Pave 1-1 Hilcorp BOPE test - Parker 273 01-13-2024
Date:Sunday, January 14, 2024 3:04:55 PM
Attachments:Pave 1-1 Hilcorp BOPE Test - Parker 273 1-13-24.xlsx
Please see attached BOPE test report form for Parker 273 on PBE Pave 1-1 completed 01-13-2024.
Thank you,
Brett Anderson
Hilcorp DSM, Parker 273
Office: 907-659-5673
Mobile: 907-240-6258
brett.anderson@hilcorp.com
Alternate: Shane Barber
sbarber@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, 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.
3%83$9(
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSubmitt to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 1/13/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230940 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: X Bi-Weekly: Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2338
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 1P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP
#1 Rams 1 7" Fixed 5M P Flow Indicator PP
#2 Rams 1 Blind Shear 5M P Meth Gas Detector PP
#3 Rams 1 2-7/8"x 5" VBR 5M P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M P System Pressure (psi)3100 P
Kill Line Valves 2 2-1/16", 3-1/8" 5M P Pressure After Closure (psi)1900 P
Check Valve 0NA200 psi Attained (sec)14 P
BOP Misc 0NAFull Pressure Attained (sec)57 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2587 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1FP
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 27 P
#1 Rams 7 P
Coiled Tubing Only:#2 Rams 9 P
Inside Reel valves 0NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:12.0 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1/11/2024 @ 13:27
Waived By
Test Start Date/Time:1/12/2024 23:30
(date) (time)Witness
Test Finish Date/Time:1/13/2024 11:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Austin McLeod
Parker
Tested with 5" and 7" test joint. Tested annular to 3000 psi. One (FP) on manual choke, Cleaned retest and passed. Test with
water.
Jon King
Hilcorp North Slope
B. Anderson/ B. LaFleur
PBU PAVE 1-1
Test Pressure (psi):
rig273mgr@parkerwellbore.com
brett.anderson@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0113_BOP_Parker273_PBU_PAVE1-1
9 9
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9
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- 5HJJ
FP
One (FP) on manual choke
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:Shane Barber - (C)
To:Regg, James B (OGC); Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay
Cc:Oliver Amend - (C); Bryan Lafleur - (C); Brett Anderson - (C); Steve Carter - (C); Frank Roach
Subject:Parker 273 / Hilcorp PAVE 101 BOP test report
Date:Saturday, January 6, 2024 5:16:50 PM
Attachments:Pave 1-1 Hilcorp BOPE Test - Parker 273 1-5-24.xlsx
All,
Please see attached BOP test report. Thank you.
Shane G. Barber | Drilling Foreman
Hilcorp Alaska, LLC
Rig “Parker 273”
Office: 907-659-5673
Mobile: 907-841-5208
Harmony: 7008
sbarber@hilcorp.com
Alternate: Brett Anderson
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.
3%83$9(
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu b mit t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 1/5/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name: PTD #22230940 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: X Bi-Weekly: Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2338
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 1P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP
#1 Rams 1 2-7/8"x 5" VBR 5M P Flow Indicator PP
#2 Rams 1 Blind Shear 5M P Meth Gas Detector PP
#3 Rams 1 2-7/8"x 5" VBR 5M P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M P System Pressure (psi)3100 P
Kill Line Valves 2 2-1/16", 3-1/8" 5M P Pressure After Closure (psi)2090 P
Check Valve 0NA200 psi Attained (sec)16 P
BOP Misc 0NAFull Pressure Attained (sec)67 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2498 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 29 P
#1 Rams 7 P
Coiled Tubing Only:#2 Rams 13 P
Inside Reel valves 0NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:4.5 HCR Choke 2 P
Repair or replacement of equipment will be made within days. HCR Kill 2 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1/4/24 @ 13:27
Waived By
Test Start Date/Time:1/5/2024 6:30
(date) (time)Witness
Test Finish Date/Time:1/5/2024 11:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Brian Bixby
Parker
Tested with 5" test joint. Tested annular to 3000 psi. No Failures. Test with water.
Jon King
Hilcorp North Slope
S. Barber / O. Amend
PBU Pave 1-1
Test Pressure (psi):
rig273mgr@parkerwellbore.com
sbarber@hilcorp.com
Form 10-424 (Revised 08/2022) 2024-0105_BOP_Parker273_PBU_PAVE1-1
9
9
9
9 9
9
9 9
9
9
9
9
-5HJJ
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:Shane Barber - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Brett Anderson - (C); Oliver Amend - (C); Steve Carter - (C)
Subject:BOP test form
Date:Friday, December 29, 2023 2:42:12 PM
Attachments:Pave 1-1 Hilcorp BOPE Test - Parker 273 12-29-23.xlsx
All,
Please see attached BOP test report “Parker 273”. Thank you.
Shane G. Barber | Drilling Foreman
Hilcorp Alaska, LLC
Rig “Parker 273”
Office: 907-659-5673
Mobile: 907-841-5208
Harmony: 7008
sbarber@hilcorp.com
Alternate: Brett Anderson
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.
3%83$9(
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSubmitt to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 12/29/23
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230940 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: X Bi-Weekly: Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2338
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 1P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP
#1 Rams 1 2-7/8"x 5" VBR 5M P Flow Indicator PP
#2 Rams 1 Blind Shear 5M P Meth Gas Detector PP
#3 Rams 1 2-7/8"x 5" VBR 5M P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M P System Pressure (psi)3100 P
Kill Line Valves 2 2-1/16", 3-1/8" 5M FP Pressure After Closure (psi)2100 P
Check Valve 0NA200 psi Attained (sec)13 P
BOP Misc 0NAFull Pressure Attained (sec)61 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2600 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 27 P
#1 Rams 7 P
Coiled Tubing Only:#2 Rams 6 P
Inside Reel valves 0NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:6.5 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 12/27/23 @ 07:47
Waived By
Test Start Date/Time:12/28/2023 23:30
(date) (time)Witness
Test Finish Date/Time:12/29/2023 6:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Kam StJohn
Parker
Tested with 5" test joint. Tested annular to 3000 psi. 1x F/P on manual kill. Svc valved and retested without further issue. Test
with water.
Jon King
Hilcorp North Slope
S. Barber / O. Amend
PBU Pave 1-1
Test Pressure (psi):
rig273mgr@parkerwellbore.com
sbarber@hilcorp.com
Form 10-424 (Revised 08/2022) 2023-1229_BOP_Parker273_PBU_Pave1-1
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-5HJJ
FP
1x F/P on manual kill
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:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:20231228 1550 APPROVAL Packer Set PAVE 1-1 12-1/4" Intermediate Section OH LWD Logs (PTD: 223-094)
Date:Thursday, December 28, 2023 3:53:38 PM
From: Rixse, Melvin G (OGC)
Sent: Thursday, December 28, 2023 3:47 PM
To: Frank Roach <Frank.Roach@hilcorp.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC)
<steve.davies@alaska.gov>
Subject: RE: PAVE 1-1 12-1/4" Intermediate Section OH LWD Logs (PTD: 223-094)
Frank,
AOGCC is good with injection packer placement as described below.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake
in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Frank Roach <Frank.Roach@hilcorp.com>
Sent: Thursday, December 28, 2023 10:05 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: PAVE 1-1 12-1/4" Intermediate Section OH LWD Logs (PTD: 223-094)
Mel,
Please see the attached recorded log data from PAVE 1-1’s intermediate hole. TD was called at
13,307’ MD and the 9-5/8” intermediate casing tally puts the shoe at 13,305’ MD.
7” production liner top is expected ~150’ above the shoe at 13,155’ MD. With the planned tubing
tail, injection packer is expected to be placed at ~13,055’ MD. This will be confirmed after liner is set
in place.
Let me know if you need anything additional.
Regards,
Frank V Roach
Drilling Engineer
Hilcorp Alaska, LLC
907.854.2321 mobile
907.777.8413 office
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.
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:Brett Anderson - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Subject:Parker 273 PAVE 1-1 BOPE test form 12-21-23 REVISION
Date:Wednesday, December 27, 2023 7:57:10 AM
Attachments:Pave 1-1 Hilcorp BOPE Test Revised - Parker 273 12-21-23.xlsx
All,
I apologize, when I was filling out the notification form this morning, I noticed that I had an extra
zero (in addition to the trailing one) on the PTD. Please see the attached revised form.
Brett Anderson
Hilcorp DSM, Parker 273
Office: 907-659-5673
Mobile: 907-240-6258
brett.anderson@hilcorp.com
Alternate: Shane Barber
sbarber@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, 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.
3%83$9(
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSubmitt to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 12/21/23
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230940 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: X Bi-Weekly: Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2338
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 2P
Test Fluid Water Inside BOP 2P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP
#1 Rams 1 9-5/8" 5M P Flow Indicator PP
#2 Rams 1 Blind Shear 5M P Meth Gas Detector PP
#3 Rams 1 2-7/8"x 5" VBR 5M P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M FP System Pressure (psi)3075 P
Kill Line Valves 2 2-1/16", 3-1/8" 5M P Pressure After Closure (psi)1900 P
Check Valve 0NA200 psi Attained (sec)14 P
BOP Misc 0NAFull Pressure Attained (sec)63 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2550 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 28 P
#1 Rams 6 P
Coiled Tubing Only:#2 Rams 7 P
Inside Reel valves 0NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:10.0 HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 12/18/23 @ 18:31
Waived By
Test Start Date/Time:12/21/2023 10:30
(date) (time)Witness
Test Finish Date/Time:12/21/2023 20:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Sully Sullivan
Parker
Test upper rams and annular with 9-5/8" Test Joint. Test lower rams and annular with 5" test joint.
F/P on HCR Kill, Re-greased and re-cycled - Pass.
All rams functioned from panel in LER, Rig Managers Office, and Accumulator room.
Jon King
Hilcorp North Slope
B. Anderson / M. Brouillet
PBU Pave 1-1
Test Pressure (psi):
rig273mgr@parkerwellbore.com
brett.anderson@hilcorp.com
Form 10-424 (Revised 08/2022) 2023-1221_BOP_Parker273_PBU_Pave1-1
9 9
9
9
9
9 9 9
9
9
9
9
-5HJJ
FP
F/P on HCR Kill
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:Brett Anderson - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Steve Carter - (C); Shane Barber - (C); Oliver Amend - (C); Frank Roach; rig273mgr@parkerwellbore.com
Subject:Pave 1-1 BOPE test report Parker 273 12-14-23
Date:Friday, December 15, 2023 9:37:46 AM
Attachments:Pave 1-1, Hilcorp BOPE Test - Parker 273 12-14-23.xlsx
All, please see attached BOP test report for Parker 273 on Pave1-1.
Thank you,
Brett Anderson
Hilcorp DSM, Parker 273
Office: 907-659-5673
Mobile: 907-240-6258
brett.anderson@hilcorp.com
Alternate: Shane Barber
sbarber@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, 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.
3%83$9(
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSubmitt to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:273 DATE: 12/14/23
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230940 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: X Bi-Weekly: Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:2338
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 1P
Test Fluid Water Inside BOP 1P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP
#1 Rams 1 2-7/8"x 5" VBR 5M P Flow Indicator PP
#2 Rams 1 Blind Shear 5M P Meth Gas Detector PP
#3 Rams 1 2-7/8"x 5" VBR 5M P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" 5M P Time/Pressure Test Result
HCR Valves 2 3-1/8" 5M FP System Pressure (psi)3100 P
Kill Line Valves 1 3-1/8" 5M P Pressure After Closure (psi)1800 P
Check Valve 0NA200 psi Attained (sec)15 P
BOP Misc 0NAFull Pressure Attained (sec)67 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 14@2525 P
No. Valves 15 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 26 P
#1 Rams 6 P
Coiled Tubing Only:#2 Rams 8 P
Inside Reel valves 0NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:8.0 HCR Choke 2 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 12/11/23 @ 10:33
Waived By
Test Start Date/Time:12/13/2023 17:30
(date) (time)Witness
Test Finish Date/Time:12/14/2023 1:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Guy Cook
Parker
Used 5" test joint on all tests.
F/P on HCR Kill, Re-greased and re-cycled - Pass.
All rams functioned from panel in LER, Rig Managers Office, and Accumulator room.
Brandon Davis
Hilcorp North Slope
B. Anderson / S. Carter
PBU Pave 1-1
Test Pressure (psi):
rig273mgr@parkerwellbore.com
brett.anderson@hilcorp.com
Form 10-424 (Revised 08/2022) 2023-1214_BOP_Parker273_PBU_Pave1-1
99
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F/P on HCR Kill
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UNIT PAVE 1-1
JBR 01/22/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Test started off slow space out on 5" TJ was not done correctly and UPR closed on joint of pipe and caused a failure. The Doors
were opened to inspect the rams and the 5" TJ was spaced out correctly. So that was F/P on UPR and had a F on Kill HCR
Greased and cycled and passed. Other issue was they started after midnight on 12-06-23 which put them over on the required
test time. 18 accumulator bottles with a 1100 psi precharge.
Test Results
TEST DATA
Rig Rep:Brandon DavisOperator:Hilcorp North Slope, LLC Operator Rep:Shane Barber, Oliver Emend
Rig Owner/Rig No.:Parker 273 PTD#:2230940 DATE:12/6/2023
Type Operation:DRILL Annular:
250/3000Type Test:WKLY
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopKPS231207063958
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 19.5
MASP:
2338
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8"P
#1 Rams 1 2-7/8" x 5"FP
#2 Rams 1 blind/shears P
#3 Rams 1 2-7/8" x 5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"FP
Kill Line Valves 1 3-1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P1800
200 PSI Attained P22
Full Pressure Attained P70
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P14 @ 2675
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 P28
#1 Rams P7
#2 Rams P6
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
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6HHDWWDFKHGUHJDUGLQJODWHVWDUWRI%23(WHVWMEU
FP
FP
UPR closed on joint of pipe and caused a failure.
F on Kill HCR
Greased and cycled and passed.
F/P on UPR
started after midnight on 12-06-23
2023-1206_BOP_Parker273_notes_PBU_PAVE_1-1_ksj
Page 1 of 1
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO:Jim Regg DATE:12/06/2023
P. I. Supervisor
FROM:Kam StJohn SUBJECT:BOPE Test
Petroleum Inspector PBU Pave 1-1; PTD 2230940
Hilcorp North Slope LLC
12/06/2023: I was initially scheduled to out Parker 273 at PBU Pave 1-1 on 12/05/2023
to witness the weekly BOPE test (24-hour advance notification provided). Update was
sent by Shane Barber (Hilcorp), pushing the test start from 13:30 to 23:00. I arrived at
22:30. The delay was due to the wellbore packing off while they were trying to get back
into the casing shoe to set a storm packer and hang off the drill string for the BOPE test.
This situation was still not resolved - the storm packer set was not yet run in the well.
Hilcorp’s plan was to start the gas alarm tests thinking that would ensure compliance
with the requirement to start the BOPE test before midnight.
I witnessed that gas detector tests – started at 23:30 – followed by the testing of PVT
system. The storm packer was finally set at 00:30 on 12/07/23 and they began get
things ready. BOPE testing began around 04:00. There was an immediate issue with
the Upper Pipe Rams (UPR) leaking. The UPR doors were opened, and it was
determined the UPR were closed on the wrong size pipe in the test joint (incorrectly
spaced out. It took several hours to inspect the UPR and correct the tool joint space out.
Restarted testing about 12:30 and other than trouble shooting the leak on the HCR Kill
all other tests went well. HCR Kill trouble shooting and fix took a while.
The issue with starting the test late (after midnight) was not in neglect in my opinion.
Operational efforts (hole stability) took longer than expected to pull the drill string back
into casing. I did speak with them about allowing additional time over what they had
already planned or requesting a delay for starting the BOPE test (with justification).
The rig crew is inexperienced with personnel brought in from down in the states, having
not previously worked together and not worked on Parker 273. They are still definitely
learning the process and the rig. It will take some time for this crew to get things figured
out. I did notice that they have added some of the guys from Parker 272.
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BOPE testing began around 04:00.
()gp,
UPR were closed on the wrong size pipe in the test joint
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UNIT PAVE 1-1
JBR 01/19/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
Retest Bope after replacing 16 kumi bladders. Tested with 5" TJ with one FP on on Ram locks during test #12, cycle ram locks ,
retest and pass. No other failures.
Test Results
TEST DATA
Rig Rep:Kaleb EnfieldOperator:Hilcorp North Slope, LLC Operator Rep:Brett Anderson
Rig Owner/Rig No.:Parker 273 PTD#:2230940 DATE:11/28/2023
Type Operation:DRILL Annular:
250/5000Type Test:OTH
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopSTS231201112413
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 10
MASP:
2338
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 2 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8 P
#1 Rams 1 2 7/8x5 vari P
#2 Rams 1 blind/shear P
#3 Rams 1 2 7/8x5vari P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8 P
HCR Valves 2 3 1/8 P
Kill Line Valves 2 2 1/16 & 3 1/8 P
Check Valve 0 NA
BOP Misc 1 blind ram loc FP
System Pressure P3125
Pressure After Closure P1850
200 PSI Attained P14
Full Pressure Attained P63
Blind Switch Covers:Pall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P14@2084
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 P26
#1 Rams P6
#2 Rams P7
#3 Rams P6
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
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Retest Bope after replacing 16 kumi bladders.FP on on Ram locks
FP
P.I. Supv
Comm:
Rig Parker 273 Coil Tubing Unit?No
Rig Contractor Rig Representative
Operator Operator Representative
Well Permit to Drill #223-094 Sundry Approval #
Operation Inspection Location
Working Pressure, W/H Flange P Pit Fluid Measurement P Working Pressure P
P Flow Rate Sensor P Operating Pressure P
P Mud Gas Separator P Fluid Level/Condition P
P Degasser P Pressure Gauges P
NT Separator Bypass NA Sufficient Valves P
NA Gas Detectors P Regulator Bypass P
P Alarms Separate/Distinct P Actuators (4-way valves)P
P Choke/Kill Line Connections P Blind Ram Handle Cover P
FP Reserve Pits P Control Panel, Driller P
P Trip Tank P Control Panel, Remote P
P Firewall P
P 2 or More Pumps P
P Kelly or TD Valves FP Independent Power Supply P
P Floor Safety Valves P N2 Backup P
P Driller's Console P Condition of Equipment P
P Flow Monitor P
Flow Rate Indicator P
Pit Level Indicators P Valves F
PPE P Gauges P Remote Hydraulic Choke P
Well Control Trained F Gas Detection Monitor P FOV Upstream of Chokes P
Housekeeping P Hydraulic Control Panel P Targeted Turns P
Well Control Plan P Kill Sheet Current P Bypass Line P
FAILURES:3 CORRECT BY:
COMMENTS
Josh Hunt
11/27/2023INSPECT DATE
AOGCC INSPECTOR
11/28/2023
Parker Drilling
Hilcorp North Slope LLC
MISCELLANEOUS
Flange/Hub Connections
Drilling Spool Outlets
Flow Nipple
Control Lines
RIG FLOOR
ALASKA OIL AND GAS CONSERVATION COMMISSION
RIG INSPECTION REPORT
HCR Valve(s)
Manual Valves
Annular Preventer
Working Pressure, BOP Stack
Stack Anchored
Choke Line
Kill Line
Targeted Turns
Pipe Rams
Blind Rams
Robert Aguilera
Brett Anderson, Oliver Amend
Locking Devices, Rams
BOP STACK
One of the drillers on shift did not have a current IADC well control certification. Test failures documented on BOPE Test Inspection
Report #bopJDH231129111042.
CHOKE MANIFOLD
PBU PAVE 1-1
MUD SYSTEM
PBU PAVE 1-1
Drilling
CLOSING UNIT
2023-1127_Rig_Inspection_Parker273_PBU_PAVE_1-1_jh rev. 4-19-2023
Tool Pusher and Company Man well control certified;
meets AOGCC regulation. J. Regg
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UNIT PAVE 1-1
JBR 01/16/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Test was performed with a 5" test joint in the stack. First initial test had a nitrogen bottle bladder failure. This was immediately
after replacing three or 4 of them prior to my arrival. I suggested replacing as many of them that they had bladders for before the
next test. The company man agreed. However, the remaining bottles made it through the rest of the testing without any more
failures. Choke manifold valve # 12 failed two attempts and will be replaced. During the rig inspection I found the new kill line
had no tags or pressure rating. They didn't have the certification on hand. They were sent to me the next morning. This test was
started at 1:30 pm on 11/26/23, I left location at 05:00 am on 11/27/23 to head for camp and flight home.
Test Results
TEST DATA
Rig Rep:Robert AguileraOperator:Hilcorp North Slope, LLC Operator Rep:Brett Anderson / O. Amend
Rig Owner/Rig No.:Parker 273 PTD#:2230940 DATE:11/27/2023
Type Operation:DRILL Annular:
250/5000Type Test:INIT
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopJDH231129111042
Inspector Josh Hunt
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 19
MASP:
2338
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 2 P
FSV Misc 0 NA
15 FNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8" 5M P
#1 Rams 1 2-7/8"x5" VB P
#2 Rams 1 Blind/shear P
#3 Rams 1 2-7/8"x5" VB P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 2 2-1/6", 3-1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P2000
200 PSI Attained P14
Full Pressure Attained P69
Blind Switch Covers:PAll Stations
Bottle precharge F
Nitgn Btls# &psi (avg)P14@2084
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P29
#1 Rams P7
#2 Rams P15
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
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First initial test had a nitrogen bottle bladder failure.immediately
after replacing three or 4 of them prior to my arrival.
Choke manifold valve # 12 failed found the new kill line
had no tags or pressure rating.didn't have the certification on hand.
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Asset Identification Form
MA.FOR.002 Rev 3: 06/17/2015
PD – INTERNAL USE/Uncontrolled if printed
Form Owner: Maintenance Department
Rig # ID #
CRZ 054345
Location of Asset ID Tag on Named Equipment:
attached adjacent the Manu. ID
Equipment Name Type
Choke Hose Armoured 6.71m / 22 Ft.
Manufacturer Serial # Model #
Conitech Beattie Co. 63223 3” 5000 3 1/8 5K API Flange end
Name Plate Data (Must include all the information on the MFG. Nameplates below)
API Spec 16C Temp rate B
Conitech order #531357
Conitech PO 006156
Cert #987
Date of manufacture 31 May 2012
Additional Data or/and Comments:
Date: Entered By and Verified By:
12/3/18 James A Hundley
12/3/18 Larry Henley
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UNIT PAVE 1-1
JBR 01/12/2024
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:Tested with a 5" test joint.
24 Nitrogen bottles average at 1100.
Tested 5 alarm stations.
This rig does have a diverter configuration variance in place.
TEST DATA
Rig Rep:Jon KingOperator:Hilcorp North Slope, LLC Operator Rep:Shane Barber
Contractor/Rig No.:Parker 273 PTD#:2230940 DATE:11/6/2023
Well Class:DEV Inspection No:divJDH231106213652
Inspector Josh Hunt
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:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:16 P
Vent Line(s) Size:16 P
Vent Line(s) Length:36 P
Closest Ignition Source:100 P
Outlet from Rig Substructure:50 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:36 P
Knife Valve Open Time:27 P
Diverter Misc:0 NA
Systems Pressure:P3200
Pressure After Closure:P2200
200 psi Recharge Time:P6
Full Recharge Time:P51
Nitrogen Bottles (Number of):P14
Avg. Pressure:P2700
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Prudhoe Oil, PBU PAVE 1-1
Hilcorp Alaska, LLC
Permit to Drill Number: 223-094
Surface Location: 845' FSL, 4767' FEL, Sec 31, T11N, R15E, UM, AK
Bottomhole Location: 564' FNL, 793' FEL, Sec 30, T11N, R15E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of October 2023.
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.10.20
11:46:34 -08'00'
20
7 BTC
1
Drilling Manager
10/17/23
Monty M
Myers
By Grace Christianson at 2:17 pm, Oct 17, 2023
197 sx -mgr
MGR17OCT2023
50-029-23767-00-00
* Initial BOPE test to 5000 psi. Annular to 2500 psi.
* Weekly BOPE test to 3000 psi. Annular to 2500 psi.
* MIT-IA to be witnessed by AOGCC to 2500 psi within 10 days of stabilized injection.
* Variance to 20 AAC 25.412(b) may be approved for packer placement
@ ~12,900' MD after review of 12-1/4" OH LWD logs by AOGCC staff to assure
packer will be placed within upper confining zones of the PB oil pool.
A.Dewhurst 17OCT23
DSR-10/19/23
223-094
JLC 10/20/2023
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.10.20 11:47:40 -08'00'10/20/23
10/20/23
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Prudhoe Bay East
(PBU) PAVE 1-1
Drilling Program
Version 0
10/5/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12
11.0 Drill 16” Hole Section .............................................................................................................. 14
12.0 Run 13-3/8” Surface Casing .................................................................................................... 17
13.0 Cement 13-3/8” Surface Casing ............................................................................................... 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 12-1/4” Intermediate Hole Section .................................................................................. 28
16.0 Run 9-5/8” Intermediate Casing .............................................................................................. 34
17.0 Cement 9-5/8” Intermediate Casing ........................................................................................ 37
18.0 Drill 8-1/2” Production Hole Section ....................................................................................... 40
19.0 Run 7” Injection Liner............................................................................................................. 44
20.0 Cement 7” Injection Liner ....................................................................................................... 47
21.0 Run Upper Completion/ Post Rig Work ................................................................................. 50
22.0 Parker 273 Rig Diverter Schematic ......................................................................................... 54
23.0 Parker 273 Rig BOP Schematic ............................................................................................... 55
24.0 Wellhead Schematic ................................................................................................................. 56
25.0 Days Vs Depth .......................................................................................................................... 57
26.0 Formation Tops & Information............................................................................................... 58
27.0 Anticipated Drilling Hazards .................................................................................................. 61
28.0 Parker 273 Rig Layout............................................................................................................. 67
29.0 FIT Procedure .......................................................................................................................... 68
30.0 Parker 273 Rig Choke Manifold Schematic ............................................................................ 69
31.0 Casing Design ........................................................................................................................... 70
32.0 12-1/4” Hole Section MASP ..................................................................................................... 71
33.0 8-1/2” Hole Section MASP ....................................................................................................... 72
34.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 73
35.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 74
Page 2
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
1.0 Well Summary
Well PBU PAVE 1-1
Pad Prudhoe Bay SIP Pad
Planned Completion Type 7” x 7-5/8” Injection Tubing
Target Reservoir(s) Ivishak Sands
Planned Well TD, MD / TVD 13,889’ MD / 8,859’ TVD
PBTD, MD / TVD 13,809’ MD / 8,790’ TVD
Surface Location (Governmental) 845' FSL, 4,767' FEL, Sec 31, T11N, R15E, UM, AK
Surface Location (NAD 27) X= 692,358.8, Y=5,946,885.4
Top of Productive Horizon
(Governmental)833' FSL, 912' FEL, Sec 30, T11N, R11E, UM, AK
TPH Location (NAD 27) X= 695,953.0, Y=5,955,861.4
BHL (Governmental) 564' FNL, 793' FEL, Sec 30, T11N, R11E, UM, AK
BHL (NAD 27) X= 696,064.1, Y=5,956,133.8
AFE Number 231-00061
AFE Drilling Days 30
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 2338 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 3224 psig
Work String 5” 19.5# S-135 XT 50
Parker 273 KB Elevation above MSL: 29.6 ft + 46.95 ft = 76.55 ft
GL Elevation above MSL: 29.6 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25 - - - X-52 Weld
16” 13-3/8” 12.415 12.259 14.375 68 L-80 BTC 5,020 2,270 1,556
12-1/4” 9-5/8” 8.681 8.525 10.625 47 L-80 BTC 6,870 4,760 1,086
8-1/2” 7” 6.276 6.151 7.656 26 L-80 VamTop 7,240 5,410 604
Tubing 7-5/8” 6.875 6.750 8.111 29.7 L-80 JFEBear 6,890 4,790 683
Tbg Tail 7” 6.276 6.151 7.656 26 L-80 VamTop 7,240 5,410 604
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surf, Int,
& Prod
5”4.276”3.500”6.500”19.5 S-135 XT50 44,000 52,800 712klb
4”3.340”2.688” 4.875”14.0 S-135 XT39 17,700 21,200 513klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com, frank.roach@hilcorp.com,
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com,
frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer David Bjork 907.564.4672 david.bjork@hilcorp.com
Geologist Christopher Clinkscales 907.777.8316 christopher.clinkscales@hilcorp.com
Reservoir Engineer Tanner Gansert 907.564.5234 tanner.gansert@hilcorp.com
Drilling Env. Coordinator Chris Keil 303.681.8844 chris.keil@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PAVE 1-1 is a grassroots injector planned to be drilled in the Ivishak sands.
The directional plan is 16” surface hole and 13-3/8” surface casing set in the base of the SV4. A 12-1/4”
section will be drilled and 9-5/8” intermediate casing set at TSGR. An 8-1/2” section will be drilled to
BSAD. A 7” injection liner will be run in the open hole section and cemented in place. The well will be
completed with 7-5/8” injection tubing, with the packer setting, testing, and perforating being performed
pos-rig.
Parker 273 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately November 1, 2023, pending rig schedule.
Surface casing will be run to 4,850’ MD / ~3,500’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 16” hole to TD of surface hole section. Run and cement 13-3/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 12-1/4” to TD of intermediate hole section. Run and cement 9-5/8” intermediate casing
6. Drill 8-1/2” hole to TD
7. Run and cement 7” injection liner
8. Run CBL to evaluate 9-5/8” cement job
9. Run Upper Completion
10. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface Hole: No mud logging. Remote Ops geologist. LWD: GR + Res
2. Intermediate Hole: No mud logging. Field Ops geologist for casing pick. LWD: GR + Res
3. Production Hole: No mud logging. Field Ops geologist. LWD: Triple-Combo (For geo-
steering)
Page 8
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (1) week intervals during the drilling and completion of PBU PAVE 1-1.
Ensure to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/5,000 psi & subsequent tests of the BOP equipment
will be to 250/3,500 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 7 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
Page 9
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
1)20 AAC 253412 (b):“A well used for injection must be equipped with tubing and a packer, or with other
equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of
alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of
the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed
within 200 feet measured depth above the top of the perforations, unless the commission approves a different
placement depth as the commission considers appropriate given the thickness and depth of the confining zone.”
A variance is requested to set the completion packer > 200’ from the top-most planned perforated interval.
Traditional Prudhoe Bay Ivishak/Sadlerochit well design has the 9-5/8” intermediate casing topsetting the Sag
River formation, in order to isolate the HRZ/Kingak shales from the depleted Sag/Shublik/Ivishak sands. The
tubing packer is proposed to be set at ~ 12,900’ (~270’ above the 9-5/8” casing shoe), while the shallowest
perforation is proposed at ~13,295’ MD.
Summary of Parker 273 BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
16”x 21-1/4” 2M Annular BOP w/ 16” diverter line Function Test Only
12-1/4”
x 13-5/8” x 5M Annular BOP
x 13-5/8” x Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3-1/8” x 5M side outlets
x 13-5/8” x Single ram
x 3” x 5M Choke Line
x 2” x 5M Kill line
x 3” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/5,000
Subsequent Tests:
250/3,500
8-1/2”
x 13-5/8” x 5M Annular BOP
x 13-5/8” x Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3-1/8” x 5M side outlets
x 13-5/8” x Single ram
x 3” x 5M Choke Line
x 2” x 5M Kill line
x 3” x 5M Choke manifold
x Standpipe, floor valves, etc
Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven
pump and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Page 10
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 PAVE 1-1 will utilize a newly set 20” conductor on SIP Pad. Ensure to review attached surface
plat and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 Ensure any necessary wellhead equipment is staged prior to MIRU. A slip-loc starting head
should also be staged in the cellar in the event that surface casing must be set using emergency
slips.
9.8 MIRU Parker 273 Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.9 Mix spud mud for 16” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x NOV 12-P-160 1,600 HP mud pumps are rated at 4,670 psi, 513 gpm @ 120 spm @ 97%
volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” diverter (Diverter Schematic attached to program).
x N/U 20” riser to BOP Deck
x N/U 20”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 16” Hole Section
11.1 P/U 16” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 16” hole section to section TD in the SV4. Confirm this setting depth with the Geologist
and Drilling Engineer while drilling the well, targeting the shale package in the base of the SV4.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 600-650 gpm while drilling through permafrost. Monitor shakers closely to ensure
shaker screens and return lines can handle the flow rate.
x Avoid sliding when drilling across the prognosed base of permafrost, top SV6, and the
EOCU to prevent high dogleg severity.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.4 at
base of perm and at TD.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
x In PBE hydrates are not present. However, continue to drill using hydrate mitigation
measures:
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x Keep mud temperature as cool as possible, Target 60-70*F
x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
x Drill through hydrate sands and quickly as possible, do not backream.
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 16” hole mud program summary:
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density PV YP API FL HPHT Drill Solids MBT Hardness
Surface – BPRF 8.8 – 9.4 10-20 20-45 NC NA <9 <35 <200
BPRF - TD 9.4 –9.5 10-30 20-45 <10 NA <9 <35 <200
System Formulation: Gel + FW spud mud
Product Quantity
Water 0. 967 Bbls
Soda Ash 0.125 ppb
M-I GEL 35.0 ppb
Primary Products
Weight Material M-I WATE
Viscosifiers M-I GEL
Fluid Loss Additives M-I Pac UL (only if needed for fluid loss near TD)
Alkalinity Control Soda Ash
Bit & BHA Balling SCREENKLEEN (only if needed for balling in surface)
Contingency Products
Thinner CF Desco II, TANNATHIN & SAPP
Cement Contamination Sodium Bicarbonate & SAPP
Screen Blinding SCREENKLEEN
Lost Circulation Material NUT PLUG FINE & MEDIUM, M-I-X II FINE & Medium
Foaming/Aeration SCREENKLEEN / DEFOAM EXTRA
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Casing Running:Reduce system YP as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures.
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Reduce the system rheology once the casing is landed to a YP < 20 (check with the
cementers to see what YP value they have targeted).
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity. Drop mud temp as low as possible as well.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (600-900 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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12.0 Run 13-3/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 13-3/8” casing running equipment (CRT & Tongs)
x Ensure 13-3/8” BTC x XT50, and TXP x XT50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 12.25” on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
13-3/8” Float Shoe
1 joint – 13-3/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –13-3/8” , 1 Centralizer mid joint w/ stop ring
13-3/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –13-3/8” , 1 Centralizer mid joint with stop ring
13-3/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
12.5 Float equipment and Stage tool equipment drawings:
This end up.
Bypass Baffle
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12.6 Continue running 13-3/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints from ~1,000’ above shoe to ~100’ TVD below base
permafrost (~2,280’ MD)
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,280’ MD).
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 2800 psi.
13-3/8” 68/# L-80 BTC MUT – Make up to Mark 10 jts Take Average
Casing OD Minimum Optimum Maximum
13-3/8” 27,540 ft-lbs Mark 33,660 ft-lbs
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12.8 Continue running 13-3/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar, along with necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 13-3/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 120 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.11 Displacement calculation:
= (4,850-120)*.1497
=708 bbls
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.97 gal/sk
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13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 120 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
Lead Slurry Tail Slurry
System Arctic Cem G
Density 11.0 lb/gal 15.8 lb/gal
Yield 2.54 ft3/sk 1.17 ft3/sk
Mixed
Water 12.2 gal/sk 5.08 gal/sk
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13.26 Displacement calculation:
2280’ x 0.1497 bpf = 341 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 Make initial cut on 13-3/8” final joint. L/D cut joint. Make final cut on 13-3/8”. Dress off stump.
Install 13-3/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to frank.roach@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 9-5/8” FBRs in top cavity,blind ram in bottom
cavity.
x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/5,000 psi for 5/5 min. Test annular to 250/5,000 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 2-7/8” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
x NOTE: The 5,000 psi test is for the initial testing of Parker 273’s BOP equipment.
Subsequent tests will be to 250/3,500 psi.
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 9.4 ppg LSND fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 6” liners in mud pumps.
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15.0 Drill 12-1/4” Intermediate Hole Section
15.1 MU 12-1/4” directional BHA
x Motor and Gr/Res
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135 XT50.
x Run a solid float in this hole section.
15.2 TIH w/ 12-1/4” BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,020 / 2 = ~2,510 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track to within 10’ of the float shoe. Displace well over to 9.8 ppg LSND for
upcoming hole section
15.6 Continue to drill out remaining shoetrack and 20’ of new formation.
15.7 CBU and condition mud for LOT.
15.8 Conduct LOT targeting 12.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as
casing test. Document incremental volume pumped (and subsequent pressure) and volume
returned. Submit casing test and FIT digital data to AOGCC.
x 12.5 ppg desired to cover shoe strength for and more than expected ECDs. A 12.1 ppg FIT is the
minimum required to drill ahead
x 12.1 ppg FIT provides >>25bbls based on 11.0 ppg MW, 10.0 ppg PP (swabbed kick at 11.0
ppg EMW BHP)
upon completion.
email: melvin.rixse@alaska.gov
-mgr
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15.9 12-1/4” hole section mud program summary:
System Type:9.4 – 11.0 ppg LSND drilling fluid
Properties:
Interval Density PV YP API FL HPHT Drill Solids MBT Hardness
~4,850’ – ~7,110’
Shoe –UG4
9.4 – 9.8 5 – 20 15 – 30 < 8 N/A <6% <12 <200
~7,110’ – ~10,478’
UG4 –CM3
9.8 – 10.3 5 – 20 15 – 30 < 8 N/A <6% <20 <200
~10,478’ – ~12,889’
CM3 –THRZ
10.3 – 10.4 5 – 20 15 – 30 < 6 N/A <6% <20 <200
~12,889’ – TD
THRZ –TD
10.4 – 11.0 5 – 20 15 – 30 < 6 <10 <6% <20 <200
Product Quantity
Water 0.916 bbls/bbl
Soda Ash 0.17 ppb
DUO-VIS 1.0 –1.5 ppb (as needed)
DUAL-FLO/ FLO-TROL 3.0 ppb
SCREENKLEEN 0.25% v/v
M-I Wate 55 ppb (as needed for wt.)
Busan 1060 2.1 gals/100 bbls
Sodium Metabisulfite 0.25 ppb (added at rig only)
Primary Products
Viscosifiers DUO-VIS/ XCD
Fluid Loss Additives FLO-TROL/ DUAL-FLO
Bit & BHA Balling SCREENKLEEN (only if needed for balling/Ugnu/WS)
Bridging Agent SAFE-CARB 20 & 40
Alkalinity Control Soda Ash
Inhibition Potassium Chloride
Lubricants LUBE 776 & LOTORQ
Corrosion Control Sodium Metabisulfite (added at rig only)
Bacteria Control Busan 1060
Contingency Products
Cement Contamination Sodium Bicarbonate & SAPP
Weight Material Sodium Chloride
Foaming/Aeration SCREENKLEEN, DEFOAM EXTRA
Lost Circulation Material NUT PLUG FINE & MEDIUM, SAFE-CARB 40, 250 & 750
x Density: Weighting material to be used for the hole section will be Barite. Additional
barite will be on location to weight up the active system (1) ppg above highest anticipated
MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
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running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (DUO-VIS / XCD). Do
not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole
diameter) for sufficient hole cleaning
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
15.10 Install MPD RCD
15.11 Displace wellbore to 9.4 ppg LSND drilling fluid
15.12 Obtain initial ECD benchmark readings prior to drilling ahead.
15.13 Drill 12-1/4” hole section from 13-3/8” shoe to ~ 6.910’ MD (~200’ MD above UG4) per
Geologist and Drilling Engineer Utilizing the following parameters:
x Flow Rate: 900-1000 GPM
x RPM: Maximize RPM when rotating Take the first couple stands to understand BHA
tendency. Maintenance slides may be necessary to keep sail angle
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to
limit drilling ECD to 1.0 ppg over calculated cleanhole ECD.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across any sands for any extended period of time.
x Limit maximum instantaneous ROP to < 200 FPH. The SV sands will drill faster than this,
but good hole cleaning practices now reduces time needed to cleanup prior to running casing.
x Target ROP is as fast as we can clean the hole without having to backream connections
x MPD will be utilized to monitor pressure build up on connections.
x 12-1/4” Hole Section A/C:
x There are no wells with a CF < 1.0
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15.14 Toward the end of the above interval, begin to weight up from 9.4 ppg to 9.8 ppg. Ensure mud is
a consistent 9.8 ppg ~200’ before entering the UG4.
x Overpressure is expected in the UG4 through UG1 from PWDW 1-2 disposal.
x PWDW 1-2 surface location is adjacent to PAVE 1-1. At PWDW 1-2’s disposal interval,
PAVE 1-1’s wellpath is ~ 3,940’ away.
15.15 Drill 12-1/4” hole section from ~6,910’ MD to ~ 10,280’ MD (~200’ MD above CM3) per
Geologist and Drilling Engineer Utilizing the following parameters:
x Flow Rate: 900-1000 GPM
x RPM: Maximize RPM when rotating
x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the
UG4-UG1
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to
limit drilling ECD to 1.0 ppg over calculated cleanhole ECD.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across any sands for any extended period of time.
x Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now
reduces time needed to cleanup prior to running casing.
x Target ROP is as fast as we can clean the hole without having to backream connections
x MPD will be utilized to monitor pressure build up on connections.
x 12-1/4” Hole Section A/C:
x There are no wells with a CF < 1.0
15.16 Toward the end of the above interval, begin to weight up from 9.8 ppg to 10.3 ppg. Ensure mud
is a consistent 10.3 ppg ~200’ before entering the CM3.
x If using a spike fluid to weight up, ensure the fluid is heated to avoid shocking the formation
and inducing losses/breathing
15.17 Drill 12-1/4” hole section from ~ 10,280’ MD to ~ 12,690’ MD (~200’ MD above HRZ) per
Geologist and Drilling Engineer Utilizing the following parameters:
x Flow Rate: 900 – 1000 GPM
x RPM: Maximize RPM when rotating
x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the
UG4-UG1
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
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Drilling Procedure
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to
limit drilling ECD to 1.0 ppg over calculated cleanhole ECD.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across any sands for any extended period of time.
x Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now
reduces time needed to cleanup prior to running casing.
x Target ROP is as fast as we can clean the hole without having to backream connections
x MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation
x 12-1/4” Hole Section A/C:
x There are no wells with a CF < 1.0
15.18 Toward the end of the above interval, begin to weight up from 10.3 ppg to 10.4 ppg and addition
of black product for HRZ stability. Ensure mud is a consistent 10.4 ppg ~200’ before entering
the HRZ.
15.19 Prior to entering the HRZ, perform a wiper trip back to the shoe.
15.20 Drill 12-1/4” hole section from ~12,690’ MD to section TD (projected at ~13,168’ MD) per
Geologist and Drilling Engineer Utilizing the following parameters:
x Flow Rate: 800 – 950 GPM
x RPM: Maximize RPM when rotating
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Limit maximum instantaneous ROP to < 120 FPH. On the final 3 stands, control drill with
WOB, RPM, and flow rate to indicate when transitioning into the TSGR “rabbit ears”
x MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation
x 8-1/2” Hole Section A/C:
x There are no wells with a CF < 1.0
15.21 Reference:Intermediate Casing Pick procedure
x Control drilling is key! Recognizing when the ROP changes is critical in knowing when to
call TD before getting too deep into the Sag River formation and going on losses.
x Drill through HRZ and LCU into the Kingak. Once the LCU and TJA are identified, use
prognosed thickness to establish first stop point.
x Stop drilling and CBU if one of the three occur:
x Reverse drilling break observed (drill additional 5’ MD before CBU)
x Sand identified in return samples
x Reach above established stop point
x If Sag River sand is not confirmed in samples, drill additional 5’ and CBU.
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Drilling Procedure
x Repeat above steps until Sag River sand is confirmed in samples.
15.22 At TD, CBU at least 3 times at 950 gpm and max RPM. Pump tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x Obtain BHCT from MWD tools and provide to Halliburton cementers.
15.23 Short trip to the previous trip point
x Pump and pull until above HRZ to limit swab effect on the HRZ/Kingak shales
x If tight hole is encountered, RIH 2-3 stands and CBU. If tight spot is at the same depth,
begin backreaming.
x If backreaming operations are commenced, continue backreaming to the shoe
x Monitor pressure, ECD, torque, and return flow to indicate potential packing off.
x If backreaming is initiated, utilize MPD to close on connections while BROOH.
x CBU minimum two times at trip point.
15.24 RIH to TD on elevators and circulate hole clean.
15.25 POOH and LD BHA.
x Pump and pull until above HRZ to limit swab effect on the HRZ/Kingak shales
15.26 9-5/8” fixed-bore rams in the upper ram cavity are already tested for upcoming intermediate
casing run.
Email OH LWD logs to AOGCC upon recovery of LWD logs. Email: melvin.rixse@alaska.gov
(This is to assure approved variance for packer placement within the PB oil pool confing zones.)
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Drilling Procedure
16.0 Run 9-5/8” Intermediate Casing
16.1 Well control preparedness: In the event of an influx of formation fluids while running the
intermediate casing, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 9-5/8” crossover installed on bottom, TIW valve in open
position on top, 5” handling joint above TIW). This joint shall be fully M/U and available
prior to running the first joint of 9-5/8” casing.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U 9-5/8” casing running equipment.
x Ensure 9-5/8” 47# BTC x XT50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 9-5/8” intermediate casing
x Use BOL 2000 or equivalent thread compound. Dope pin end only w/ paint brush. Wipe off
excess.
x Centralization:
x 1 centralizer every joint to ~ 2000’ MD from shoe
x 1 centralizer every 2 joints from ~2,000’ above shoe to 1 jt below 13-3/8” surface casing
shoe (~4,890’ MD)
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
x Obtain up and down weights of the casing before entering open hole. Record rotating torque
at 10 and 20 rpm
x See data sheets on the next page for MU torque for the 9-5/8” casing connection.
12.15 Continue M/U & thread locking 80’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8”, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8”, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar
1 joint – 9-5/8”, 1 Centralizer free floating
9-5/8” 47/# L-80 BTC MUT – Make up to Mark 10 jts Take Average
Casing OD Minimum Optimum Maximum
9-5/8” 21,440 ft-lbs Mark 26,200 ft-lbs
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Drilling Procedure
16.4 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
16.5 Slow in and out of slips.
16.6 RIH with 9-5/8” intermediate casing to 13-3/8” shoe at ~ 4,850’ MD. CBU and extablish PU and
SO weights prior to exiting shoe.
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Drilling Procedure
16.7 Continue to RIH with 9-5/8” intermediate casing using the following circulation strategy (Note:
Take special care when staging pumps up and down to avoid packing off and breaking down
formation):
x 13-3/8” shoe to top WS2: Every 5th joint, staging up to planned cementing rate. Circulate for
5 minutes.
x Top WS2 to THRZ: Every 5th joint, staging up to planned cementing rate. Circulate for 5
minutes.
x Circulate down consecutive joints to achieve a full bottoms-up by THRZ
x THRZ to TD: Do not circulate. Fill pipe only
16.8 P/U hanger and landing joint and M/U to casing string. Casing shoe +/- 5’ from TD.
16.9 Break circulation at 1 bpm to avoid breaking down formation. Slowly stage up to full circulating
rate (planned cementing rates). Allow circulating pressures to stabilize before increasing
circulating rate to the next stage. Circulate 2 BU or more if needed to condition hole for
cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop
until casing is on bottom and cementers are ready.
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Drilling Procedure
17.0 Cement 9-5/8” Intermediate Casing
17.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
17.2 Document efficiency of all possible displacement pumps prior to cement job.
17.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
17.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
17.5 Fill surface cement lines with water and pressure test.
17.6 Pump remaining 80 bbls 12.5 ppg tuned spacer.
17.7 Drop bottom plug – HEC rep to witness. Mix and pump cement per below calculations for the
1st stage, confirm actual cement volumes with cementer after TD is reached.
17.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of lead &
tail, TOC brought to above UG4.
Estimated Total Cement Volume:
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Drilling Procedure
Cement Slurry Design:
17.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
17.10 After pumping cement, drop top plug and displace with the rig pumps and LSND mud out of
mud pits.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
17.11 Displacement calculation:
= (13,168-80)*.0732
= 958 bbls
17.12 Monitor returns closely while displacing cement. Adjust pump rate if losses or packing off are
seen at any point during the job.
17.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±3.0 bbls before consulting with Drilling
Engineer.
17.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set.
17.15 Initiate injection with drilling mud to confirm annulus break-down pressure as soon as possible
in case of cement channeling.
x Pump 1-2 bbls down the annulus (after reaching breakdown pressure) every hour or as
conditions dictate to ensure an open annulus in preparation for the freeze protect job.
x The cement job was planned to within 1350’ MD of the surface casing shoe. There is a
possibility of bringing cement into the shoe.
17.16 Set packoff and test per wellhead tech.
Lead Slurry Tail Slurry
Density 13.0 lb/gal 15.3 lb/gal
Yield 1.84 ft3/sk 1.23 ft3/sk
Mix Water 10.13 gal/sk 5.57 gal/sk
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Drilling Procedure
17.17 Freeze protect 13-3/8” x 9-5/8” casing annulus to ~2,200’ MD with dead crude or diesel after
cement tests indicate cement has reached 500 psi compressive strength.
x Freeze protect with 131 bbls of dead crude/diesel
x Continue with the injection steps in 17.15 every hour until 500 psi compressive strength is
reached at the top of the cement.
x Ensure total injection volume injected down the annulus (including mud used to keep
annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume.
17.18 Change upper rams from 9-5/8” casing rams to 2-7/8” x 5” VBRs and test to 250 psi low, 3,500
psi high for 5/5 minutes with 5” test joint.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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Drilling Procedure
18.0 Drill 8-1/2” Production Hole Section
18.1 MU 8-1/2” directional BHA
x RSS and Triple Combo
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 XT50.
x Run a solid float in the production hole section.
18.2 TIH w/ 8-1/2” BHA to float collar. Note depth TOC tagged on AM report. Drill out shoe track
to 10’ above float shoe.
18.3 RU and test casing to 4,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and
volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin
17-001.
18.4 Displace well to 8.5 ppg LSND drilling fluid.
18.5 Drill out remaining shoe track and 20’ of new formation.
18.6 CBU and condition mud for FIT.
18.7 Conduct FIT to 10.8 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
x 10.8 ppg desired to cover shoe strength for expected ECDs. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg FIT provides >>25bbls based on 9.1 ppg MW, 7.00 ppg EMW PP (swabbed kick at 9.1
ppg EMW BHP)
18.8 8-1/2” hole section mud program summary:
System Type:8.5 – 9.1 ppg LSND drilling fluid
Properties:
Interval Density PV YP API FL LSYP pH MBT Hardness
Production 8.5-9.1 <8 12 –20 <12 15k –30k 8.5 - 9.5 <4.0 <100
Casing test and FIT digital data to AOGCC upon completion of FIT.
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Drilling Procedure
Product Quantity
Water 0.916 bbls/bbl
Soda Ash 0.17 ppb
DUO-VIS 0.75 –1.25 ppb (as needed)
DUAL-FLO/ FLO-TROL 3.0 ppb
SCREENKLEEN 0.25% v/v
KLC 10.7 ppb (3% by wt.)
Busan 1060 2.1 gals/100 bbls
Sodium Metabisulfite 0.25 ppb (added at rig only)
Primary Products
Viscosifiers DUO-VIS/ XCD
Fluid Loss Additives FLO-TROL/ DUAL-FLO
Bridging Agent SAFE-CARB 20 & 40
Alkalinity Control Soda Ash
Inhibition Potassium Chloride
Lubricants LUBE 776 & LOTORQ
Corrosion Control Sodium Metabisulfite (added at rig only)
Bacteria Control Busan 1060
Contingency Products
Cement Contamination Sodium Bicarbonate & SAPP
Weight Material Sodium Chloride
Foaming/Aeration SCREENKLEEN, DEFOAM EXTRA
Lost Circulation Material NUT PLUG FINE & MEDIUM, SAFE-CARB 40, 250 & 750
x Density: Weighting material to be used for the hole section will be sodium chloride.
Additional NaCl will be on location to weight up the active system (1) ppg above highest
anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (DUO-VIS / XCD). Data
suggests excessive viscosifier concentrations can decrease return permeability. Do not
pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter)
for sufficient hole cleaning
x Run the centrifuge as needed while drilling the production hole, this will help with solids
removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
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Drilling Procedure
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
18.9 Install MPD RCD
18.10 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
18.11 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Reservoir plan is to cross all Ivishak sands and TD beneath BSAD.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Hole Section A/C:
x 05-16A has a 0.685 CF. This well has been reservoir P&A’d.
18.12 At TD, CBU at drilling rate and max rotation. Pump sweeps if needed
x Monitor BU for increase in cuttings
18.13 Perform wiper trip to the 9-5/8” casing shoe
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If pulling tight, trip back to TD and begin backreaming operations.
x If backreaming operations are commenced, continue backreaming to the shoe
18.14 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
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Drilling Procedure
18.15 Trip back to TD and CBU 2x or until well cleans up, whichever comes later.
18.16 POOH and LD BHA. Rabbit DP that will be used to run liner.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
19.0 Run 7” Injection Liner
19.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open
position on top, 5” handling joint above TIW). This joint shall be fully M/U and available
prior to running the first joint of 7” liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
19.2 Change upper VBRs to 7” casing rams and test to 250 psi low, 3,500 psi high for 5/5 minutes
using 7” test joint.
19.3 R/U 7” liner running equipment.
x Ensure 7” 26# VT x XT50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
19.4 Run 7” injection liner
x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
x Obtain up and down weights of the liner before entering open hole.
x See data sheet on the next page for MU torque for the 7” liner connections.
x Centralization:
x 1 centralizer every joint to ~ 50’ MD from 9-5/8” shoe
19.5 Run 7” injection liner as follows:
7” Float Shoe
1 joint –7”, 2 Centralizers 10’ from each end w/ stop rings
7” Float Collar
1 joint –7”, 1 Centralizer free floating
7” landing collar for liner wiper plug
1 joint – 7”, 1 Centralizer mid joint w/ stop ring
7” 26/# L-80 VT – Make up Torque
Casing OD Minimum Optimum Maximum
7” 7,470 ft-lbs 8,300 ft-lbs 9,130 ft-lbs
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Drilling Procedure
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Drilling Procedure
19.6 Ensure hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place
liner hanger/packer across 9-5/8” connection.
19.7 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
19.8 M/U Baker SLZXP liner top packer to 7” liner. Circulate 2 liner volumes to clear string and
allow for PAL mix to set
19.9 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
19.10 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the
hole. Slow down running speed if necessary.
x Ensure 5” DP has been drifted
x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging.
19.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
19.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM. If torque approaches make-up torque of liner, discontinue rotation.
19.13 Tag bottom and PU to position float shoe ~2’ off bottom.
19.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Do not
exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses.
Confirm all pressures with Baker.
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Drilling Procedure
20.0 Cement 7” Injection Liner
20.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
20.2 Document efficiency of all possible displacement pumps prior to cement job.
20.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
20.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
20.5 Fill surface cement lines with water and pressure test.
20.6 Pump remaining 60 bbls 12.5 ppg tuned spacer.
20.7 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail slurry,
TOC brought to top of liner.
Estimated Total Cement Volume:
Cement Slurry Design:
Tail Slurry
Density 15.8 lb/gal
Yield 1.16 ft3/sk
Mix Water 4.98 gal/sk
- mgr
40.8 229.4 197.4
5.1 28.8
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PAVE 1-1 Ivishak Injector
Drilling Procedure
20.8 Wash up lines back to the cement unit. This will help reduce risk of cement stringers in the liner.
Drop drillpipe dart and displace with perf pill before swapping to drilling mud. If hole conditions
allow – continue rotating and reciprocating liner throughout displacement. This will ensure a
high quality cement job with 100% coverage around the pipe.
20.9 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
20.10 If elevated displacement pressures are encountered, position casing at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
20.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
20.12 Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool Slack off total liner weight plus 30k to confirm hanger is set.
20.13 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down
50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating
at 10-20 RPM and set down 50K again.
20.14 PU to neutral weight, close BOP and test annulus to 1,500 psi for 5 minutes to confirm liner top
packer is set.
20.15 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, repeat setting process in 20.13. If running tool cannot be hydraulically
released, apply LH torque to mechanically release the setting.
20.16 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top)
20.17 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
20.18 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
Page 49
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
20.19 RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
20.20 Change upper rams from 7” fixed to 2-7/8” x 5” VBRs and test with 2-7/8” and 5” test joints. If
not completed in the previous BOP test, test the lower VBRs with 2-7/8” and 5” test joints.
20.21 RU e-line and RIH w/CBL to top of liner. Log 9-5/8” from top of 7” liner to 13-3/8” shoe depth
to confirm TOC prior to running upper completion. RD e-line after successful log of interval.
20.22 Pressure test casing and liner to 250 psi low / 4,000 psi high for 30 minutes. Do not test until
cement has reached minimum 1,000 psi compressive strength.
Note: Once running tool is LD, swap to the completion AFE.
Page 50
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
21.0 Run Upper Completion/ Post Rig Work
21.1 RU to run 7” 26#, L-80 Vam Top x 7-5/8”, 29.7#, L-80 JFE Bear tubing.
x Ensure wear bushing is pulled.
x Ensure 5”, L-80, 29.7#, JFE Bear x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
21.2 PU, MU and RH with the following 7” completion jewelry (tally to be provided by Operations
Engineer):
x Torque Turn All Connections
x Tubing Jewelry to include (top to bottom):
x 1x ‘R’ Nipple
x 1x ‘R’ Nipple
x 1x Production Packer
x 1x ‘R’ Nipple
x 1x WLEG
x All tubing jewelry assemblies and tubing tail are 7”, 26#, L-80, VamTop and crossed over to
the 7-5/8” tubing
x Tubing is 7-5/8”, 29.7#, L-80, JFE Bear
7” 26/# L-80 VT – Make up Torque
Casing OD Minimum Optimum Maximum
7” 7,470 ft-lbs 8,300 ft-lbs 9,130 ft-lbs
7-5/8” 29.7/# L-80 JFE Bear – Make up Torque
Casing OD Minimum Optimum Maximum
7-5/8” 7,470 ft-lbs 8,300 ft-lbs 9,130 ft-lbs
Page 51
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
Page 52
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
Page 53
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
21.3 PU and MU the 7” tubing hanger.
21.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
21.5 Land the tubing hanger and RILDS.
21.6 Circulate well over to completion brine. Do not exceed 4 bpm when circulating.
21.7 Lay down the landing joint. Install 6” CIW Type J TWC. ND BOP.
21.8 NU the tubing head adapter and NU the tree.
21.9 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
21.10 Pull TWC. Line up to the IA and reverse circulate 155 bbls diesel freeze protect. Hook up
jumper line to the tree and allow freeze protect to u-tube.
x Volume to freeze protect down to 2,200’ TVD.
21.11 Set BPV in wellhead in preparation for RDMO.
21.12 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
21.13 RDMO Parker 273
i. POST RIG WELL WORK (sundry to follow)
1. Slickline/Fullbore
a. Pull BPV.
b. Set plug in tubing tail and set production packer.
c. Test Tubing and IA to 250 psi low for 5 min, 4,000 psi high for 30 min
d. Pull plug from tubing tail.
2. CTU
a. Perforate injection interval.
Page 54
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
22.0 Parker 273 Rig Diverter Schematic
Page 55
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
23.0 Parker 273 Rig BOP Schematic
Page 56
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
24.0 Wellhead Schematic
Page 57
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
25.0 Days Vs Depth
Page 58
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
26.0 Formation Tops & Information
Page 59
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
Page 60
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
Page 61
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
27.0 Anticipated Drilling Hazards
16” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have NOT been seen on SIP Pad, nor the closest Drillsites (DS-05 and DS-02).
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Faults):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
Page 62
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
H2S:
SIP is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-05 and
DS-02 (nearest sites with production/injection) have a history of H2S in their wells. Below are the most
recent H2S values of monitored wells in the Ivishak Pool.
Well Name H2S Level Date of Reading
#1 Closest SHL Well H2S Level PWDW 1-2A 115 ppm 10/7/2023
#2 Closest SHL Well H2S Level 02-34B 22 ppm 7/21/2023
#1 Closest BHL Well H2S Level 05-28B 10 ppm 7/21/2023
#2 Closest BHL Well H2S Level 05-16B 20 ppm 4/8/2023
Max. Recorded H2S on nearest Pad/Facility DS-05: 05-09A
DS-02: 02-29A
580 ppm
100 ppm
6/25/1998
10/23/1992
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 63
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
12-1/4” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning
(weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole
angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run
centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time
is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at
maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the
wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean
the hole. Maintain circulation rate of > 800 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
While SIP is not an H2S location from a surface perspective, treat every hole section as though it has the
potential for H2S. PBU DS-05 and DS-02 (nearest sites with production/injection) have a history of
H2S in their wells. Below are the most recent H2S values of monitored wells in the Ivishak Pool.
Well Name H2S Level Date of Reading
#1 Closest SHL Well H2S Level PWDW 1-2A 115 ppm 10/7/2023
#2 Closest SHL Well H2S Level 02-34B 22 ppm 7/21/2023
#1 Closest BHL Well H2S Level 05-28B 10 ppm 7/21/2023
#2 Closest BHL Well H2S Level 05-16B 20 ppm 4/8/2023
Max. Recorded H2S on nearest Pad/Facility DS-05: 05-09A
DS-02: 02-29A
580 ppm
100 ppm
6/25/1998
10/23/1992
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
Page 64
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
PWDW 1-2 is Flow Station 1’s disposal well. Expected pore pressure when drilling through UG4 and
UG3 is 9.5 ppg. Ensure mud is at least 9.8 ppg prior to drilling through.
Ugnu/West Sak Hardstreaks:
Hard formations (which are not necessarily predictable) can be encountered resulting in damage to PDC
cutters. Damage occurs due to high impact loading of the bit cutting structure when hard streaks are hit
at high ROP. Follow the appropriate mitigation strategy of reducing rotary speed while maintaining
WOB.
Formation Breakout (HRZ/Kingak instability):
This is related to the fissile (finely laminated) nature of the formation in conjunction with higher pore
pressure, which requires higher mud weight to maintain wellbore stability. If splintering cuttings are
observed at surface, additional circulations and mud weight may be required.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
8.5” Hole Section Specific AC:
x There are no wells with a CF < 1.0
Page 65
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning
(weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole
angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run
centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time
is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at
maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the
wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean
the hole. Maintain circulation rate of > 500 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
While SIP is not an H2S location from a surface perspective, treat every hole section as though it has the
potential for H2S. PBU DS-05 and DS-02 (nearest sites with production/injection) have a history of
H2S in their wells. Below are the most recent H2S values of monitored wells in the Ivishak Pool.
Well Name H2S Level Date of Reading
#1 Closest SHL Well H2S Level PWDW 1-2A 115 ppm 10/7/2023
#2 Closest SHL Well H2S Level 02-34B 22 ppm 7/21/2023
#1 Closest BHL Well H2S Level 05-28B 10 ppm 7/21/2023
#2 Closest BHL Well H2S Level 05-16B 20 ppm 4/8/2023
Max. Recorded H2S on nearest Pad/Facility DS-05: 05-09A
DS-02: 02-29A
580 ppm
100 ppm
6/25/1998
10/23/1992
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
Page 66
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
8.5” Hole Section Specific AC:
x 05-16A has a 0.685 CF. This well has been reservoir P&A’d.
Page 67
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
28.0 Parker 273 Rig Layout
Page 68
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
29.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 69
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
30.0 Parker 273 Rig Choke Manifold Schematic
Page 70
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
31.0 Casing Design
Page 71
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
32.0 12-1/4” Hole Section MASP
Page 72
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
33.0 8-1/2” Hole Section MASP
Page 73
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
34.0 Spider Plot (NAD 27) (Governmental Sections)
Page 74
Prudhoe Bay East
PAVE 1-1 Ivishak Injector
Drilling Procedure
35.0 Surface Plat (As Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
6HSWHPEHU
3ODQ 3$9(ZS
+LOFRUS1RUWK6ORSH//&
3%86$7
3:':
3ODQ 3$9(
3$9(
0
475
950
1425
1900
2375
2850
3325
3800
4275
4750
5225
5700
6175
6650
7125
7600
8075
8550
9025
So
u
t
h
(
-
)
/
N
o
r
t
h
(
+
)
(
9
5
0
u
s
f
t
/
i
n
)
-475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175
West(-)/East(+) (950 usft/in)
PAVE-FS1 wp04 Fault 2
PAVE-FS1 wp04 Fault 1
PAVE-FS1 wp07 tgt1
13 3/8" x 17 1/2"
9 5/8" x 12 1/4"
7" x 8 1/2"
1250
1750
2000
2250
2500
2750
3000
3250
3500
3750
4000
4250
4500
4750
5000
5250
5500
5750
6000
6250
6500
6750
7000
7250
7500
7750
8000
8500
8859
PAVE 1-1 wp08
Start Dir 1º/100' : 300' MD, 300'TVD
Start Dir 2º/100' : 600' MD, 599.86'TVD
Start Dir 3º/100' : 1000' MD, 996.58'TVD
fault-1 (<20' throw)
End Dir : 2553.47' MD, 2251.46' TVD
fault-2 (<20' throw)
Start Dir 3º/100' : 12097.43' MD, 7441.21'TVD
fault-3 (<20' throw)
End Dir : 12999.4' MD, 8089.1' TVD
Total Depth : 13888.52' MD, 8859.1' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3000.00 2923.45 3930.03 13-3/8 13 3/8" x 17 1/2"
8200.00 8123.45 13127.45 9-5/8 9 5/8" x 12 1/4"
8859.10 8782.55 13888.52 7 7" x 8 1/2"
Project: PBUSAT
Site: PWDW
Well: Plan: PAVE 1-1
Wellbore: PAVE 1-1
Plan: PAVE 1-1 wp08
WELL DETAILS: Plan: PAVE 1-1
29.60
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
5946885.43 692358.80 70° 15' 33.8475 N 148° 26' 42.1422 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: PAVE 1-1, True North
Vertical (TVD) Reference: PAVE 1-1 as built RKB @ 76.55usft
Measured Depth Reference:PAVE 1-1 as built RKB @ 76.55usft
Calculation Method:Minimum Curvature
-1500
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
Tr
u
e
V
e
r
t
i
c
a
l
D
e
p
t
h
(
1
5
0
0
u
s
f
t
/
i
n
)
0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500
Vertical Section at 23.65° (1500 usft/in)
PAVE-FS1 wp07 tgt1
PAVE-FS1 wp04 Fault 1
PAVE-FS1 wp04 Fault 2
13 3/8" x 17 1/2"
9 5/8" x 12 1/4"
7" x 8 1/2"
50 0
1 0 0 0
1 5 0 0
2 0 0 0
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000
7500
8000
8500
9000
9500
10000
10500
11000
11500
12000
12500
1 3 0 0 0
1 3 5 0 0
1 3 8 8 9
PAVE 1-1 wp08
Start Dir 1º/100' : 300' MD, 300'TVD
Start Dir 2º/100' : 600' MD, 599.86'TVD
Start Dir 3º/100' : 1000' MD, 996.58'TVD
fault-1 (<20' throw)
End Dir : 2553.47' MD, 2251.46' TVD
fault-2 (<20' throw)
Start Dir 3º/100' : 12097.43' MD, 7441.21'TVD
fault-3 (<20' throw)
End Dir : 12999.4' MD, 8089.1' TVD
Total Depth : 13888.52' MD, 8859.1' TVD
BPRF
SV6
SV5
SV4
SV3
SV2
SV1
UG4
UG3
UG1
WS2
WS1
CM3
CM2
CM1
THRZ
LCU
TSGR
TSHU
TSAD
BSAD
Hilcorp North Slope, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: PAVE 1-1
29.60
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 5946885.43 692358.80 70° 15' 33.8475 N 148° 26' 42.1422 W
SURVEY PROGRAM
Date: 2023-08-30T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
46.95 1000.00 PAVE 1-1 wp08 (PAVE 1-1) GYD_Quest GWD
1000.00 3930.00 PAVE 1-1 wp08 (PAVE 1-1) 3_MWD+IFR2+MS+Sag
3930.00 13128.00 PAVE 1-1 wp08 (PAVE 1-1) 3_MWD+IFR2+MS+Sag
13128.00 13888.52 PAVE 1-1 wp08 (PAVE 1-1) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
503.55 427.00 503.59 BPRF
2227.90 2151.35 2510.87 SV6
2882.40 2805.85 3713.77 SV5
3022.52 2945.97 3971.45 SV4
3561.10 3484.55 4961.90 SV3
3769.41 3692.86 5344.98 SV2
4191.00 4114.45 6120.28 SV1
4729.19 4652.64 7110.01 UG4
4972.16 4895.61 7556.84 UG3
5541.13 5464.58 8603.17 UG1
6097.44 6020.89 9626.23 WS2
6326.09 6249.54 10046.71 WS1
6560.57 6484.02 10477.92 CM3
7018.60 6942.05 11320.24 CM2
7674.97 7598.42 12472.93 CM1
7995.08 7918.53 12888.93 THRZ
8178.82 8102.27 13103.00 LCU
8234.76 8158.21 13167.59 TSGR
8280.52 8203.97 13220.43 TSHU
8344.84 8268.29 13294.70 TSAD
8825.90 8749.35 13850.18 BSAD
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: PAVE 1-1, True North
Vertical (TVD) Reference:PAVE 1-1 as built RKB @ 76.55usft
Measured Depth Reference:PAVE 1-1 as built RKB @ 76.55usft
Calculation Method:Minimum Curvature
Project:PBUSAT
Site:PWDW
Well:Plan: PAVE 1-1
Wellbore:PAVE 1-1
Design:PAVE 1-1 wp08
CASING DETAILS
TVD TVDSS MD Size Name
3000.00 2923.45 3930.03 13-3/8 13 3/8" x 17 1/2"
8200.00 8123.45 13127.45 9-5/8 9 5/8" x 12 1/4"
8859.10 8782.55 13888.52 7 7" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.00
2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 1º/100' : 300' MD, 300'TVD
3 600.00 3.00 0.00 599.86 7.85 0.00 1.00 0.00 7.19 Start Dir 2º/100' : 600' MD, 599.86'TVD
4 1000.00 10.97 7.30 996.58 56.14 4.84 2.00 10.00 53.36 Start Dir 3º/100' : 1000' MD, 996.58'TVD
5 2553.47 57.06 23.65 2251.46 843.70 301.71 3.00 18.98 893.87 End Dir : 2553.47' MD, 2251.46' TVD
6 12097.43 57.06 23.65 7441.21 8180.33 3515.35 0.00 0.00 8903.47 Start Dir 3º/100' : 12097.43' MD, 7441.21'TVD
7 12999.40 30.00 23.65 8089.10 8744.08 3762.27 3.00 -179.99 9518.92 End Dir : 12999.4' MD, 8089.1' TVD
8 13167.35 30.00 23.65 8234.55 8821.01 3795.96 0.00 0.00 9602.90 PAVE-FS1 wp07 tgt1
9 13888.52 30.00 23.65 8859.10 9151.31 3940.61 0.00 0.00 9963.48 Total Depth : 13888.52' MD, 8859.1' TVD
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Vertical Section at 23.65° (1500 usft/in)
PAVE-FS1 wp07 tgt1
PAVE-FS1 wp04 Fault 1
PAVE-FS1 wp04 Fault 2
13 3/8" x 17 1/2"
9 5/8" x 12 1/4"
7" x 8 1/2"
50 0
1 0 0 0
1 5 0 0
2 0 0 0
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3000
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1 3 0 0 0
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1 3 8 8 9
PAVE 1-1 wp08
Start Dir 1º/100' : 300' MD, 300'TVD
Start Dir 2º/100' : 600' MD, 599.86'TVD
Start Dir 3º/100' : 1000' MD, 996.58'TVD
fault-1 (<20' throw)
End Dir : 2553.47' MD, 2251.46' TVD
fault-2 (<20' throw)
Start Dir 3º/100' : 12097.43' MD, 7441.21'TVD
fault-3 (<20' throw)
End Dir : 12999.4' MD, 8089.1' TVD
Total Depth : 13888.52' MD, 8859.1' TVD
BPRF
SV6
SV5
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SV3
SV2
SV1
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UG3
UG1
WS2
WS1
CM3
CM2
CM1
THRZ
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TSHU
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BSAD
Hilcorp North Slope, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: PAVE 1-1
29.60
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 5946885.43 692358.80 70° 15' 33.8475 N 148° 26' 42.1422 W
SURVEY PROGRAM
Date: 2023-08-30T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
46.95 1000.00 PAVE 1-1 wp08 (PAVE 1-1) GYD_Quest GWD
1000.00 3930.00 PAVE 1-1 wp08 (PAVE 1-1) 3_MWD+IFR2+MS+Sag
3930.00 13128.00 PAVE 1-1 wp08 (PAVE 1-1) 3_MWD+IFR2+MS+Sag
13128.00 13888.52 PAVE 1-1 wp08 (PAVE 1-1) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
503.55 427.00 503.59 BPRF
2227.90 2151.35 2510.87 SV6
2882.40 2805.85 3713.77 SV5
3022.52 2945.97 3971.45 SV4
3561.10 3484.55 4961.90 SV3
3769.41 3692.86 5344.98 SV2
4191.00 4114.45 6120.28 SV1
4729.19 4652.64 7110.01 UG4
4972.16 4895.61 7556.84 UG3
5541.13 5464.58 8603.17 UG1
6097.44 6020.89 9626.23 WS2
6326.09 6249.54 10046.71 WS1
6560.57 6484.02 10477.92 CM3
7018.60 6942.05 11320.24 CM2
7674.97 7598.42 12472.93 CM1
7995.08 7918.53 12888.93 THRZ
8178.82 8102.27 13103.00 LCU
8234.76 8158.21 13167.59 TSGR
8280.52 8203.97 13220.43 TSHU
8344.84 8268.29 13294.70 TSAD
8825.90 8749.35 13850.18 BSAD
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: PAVE 1-1, True North
Vertical (TVD) Reference:PAVE 1-1 as built RKB @ 76.55usft
Measured Depth Reference:PAVE 1-1 as built RKB @ 76.55usft
Calculation Method:Minimum Curvature
Project:PBUSAT
Site:PWDW
Well:Plan: PAVE 1-1
Wellbore:PAVE 1-1
Design:PAVE 1-1 wp08
CASING DETAILS
TVD TVDSS MD Size Name
3000.00 2923.45 3930.03 13-3/8 13 3/8" x 17 1/2"
8200.00 8123.45 13127.45 9-5/8 9 5/8" x 12 1/4"
8859.10 8782.55 13888.52 7 7" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.00
2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 1º/100' : 300' MD, 300'TVD
3 600.00 3.00 0.00 599.86 7.85 0.00 1.00 0.00 7.19 Start Dir 2º/100' : 600' MD, 599.86'TVD
4 1000.00 10.97 7.30 996.58 56.14 4.84 2.00 10.00 53.36 Start Dir 3º/100' : 1000' MD, 996.58'TVD
5 2553.47 57.06 23.65 2251.46 843.70 301.71 3.00 18.98 893.87 End Dir : 2553.47' MD, 2251.46' TVD
6 12097.43 57.06 23.65 7441.21 8180.33 3515.35 0.00 0.00 8903.47 Start Dir 3º/100' : 12097.43' MD, 7441.21'TVD
7 12999.40 30.00 23.65 8089.10 8744.08 3762.27 3.00 -179.99 9518.92 End Dir : 12999.4' MD, 8089.1' TVD
8 13167.35 30.00 23.65 8234.55 8821.01 3795.96 0.00 0.00 9602.90 PAVE-FS1 wp07 tgt1
9 13888.52 30.00 23.65 8859.10 9151.31 3940.61 0.00 0.00 9963.48 Total Depth : 13888.52' MD, 8859.1' TVD
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
PRUDHOE OILPRUDHOE BAY POOL
223-094
X
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No
16
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9
-
5
/
8
"
c
e
m
e
n
t
e
d
f
r
o
m
s
h
o
e
i
n
t
o
p
o
f
P
B
o
i
l
p
o
o
l
t
o
6
2
0
0
'
M
D
.
4
6
6
b
b
l
l
e
a
d
f
o
l
l
o
w
e
d
b
y
7
8
b
b
l
t
a
i
l
.
21
C
M
T
v
o
l
a
d
e
q
u
a
t
e
t
o
t
i
e
-
i
n
l
o
n
g
s
t
r
i
n
g
t
o
s
u
r
f
c
s
g
Ye
s
22
C
M
T
w
i
l
l
c
o
v
e
r
a
l
l
k
n
o
w
n
p
r
o
d
u
c
t
i
v
e
h
o
r
i
z
o
n
s
Ye
s
23
C
a
s
i
n
g
d
e
s
i
g
n
s
a
d
e
q
u
a
t
e
f
o
r
C
,
T
,
B
&
p
e
r
m
a
f
r
o
s
t
Ye
s
P
a
r
k
e
r
R
i
g
#
2
7
3
h
a
s
a
d
e
q
u
a
t
e
t
a
n
k
a
g
e
a
n
d
g
o
o
d
t
r
u
c
k
i
n
g
s
u
p
p
o
r
t
24
A
d
e
q
u
a
t
e
t
a
n
k
a
g
e
o
r
r
e
s
e
r
v
e
p
i
t
NA
T
h
i
s
i
s
a
g
r
a
s
s
r
o
o
t
s
w
e
l
l
.
25
I
f
a
r
e
-
d
r
i
l
l
,
h
a
s
a
1
0
-
4
0
3
f
o
r
a
b
a
n
d
o
n
m
e
n
t
b
e
e
n
a
p
p
r
o
v
e
d
Ye
s
H
a
l
l
i
b
u
r
t
o
n
c
o
l
l
i
s
i
o
n
s
c
a
n
s
h
o
w
s
n
o
c
l
o
s
e
a
p
p
r
o
a
c
h
e
s
t
o
l
i
v
e
w
e
l
l
s
o
r
w
e
l
l
s
w
i
t
h
p
r
e
s
s
u
r
e
.
26
A
d
e
q
u
a
t
e
w
e
l
l
b
o
r
e
s
e
p
a
r
a
t
i
o
n
p
r
o
p
o
s
e
d
Ye
s
2
1
-
1
/
4
"
d
i
v
e
r
t
e
r
w
i
t
h
1
6
"
d
i
v
e
r
t
e
r
l
i
n
e
t
o
d
r
i
l
l
1
6
"
O
H
.
27
I
f
d
i
v
e
r
t
e
r
r
e
q
u
i
r
e
d
,
d
o
e
s
i
t
m
e
e
t
r
e
g
u
l
a
t
i
o
n
s
Ye
s
A
l
l
f
l
u
i
d
s
t
o
b
e
o
v
e
r
b
a
l
a
n
c
e
t
o
p
o
r
e
p
r
e
s
s
u
r
e
.
28
D
r
i
l
l
i
n
g
f
l
u
i
d
p
r
o
g
r
a
m
s
c
h
e
m
a
t
i
c
&
e
q
u
i
p
l
i
s
t
a
d
e
q
u
a
t
e
Ye
s
1
a
n
n
u
l
a
r
,
3
r
a
m
s
t
a
c
k
t
e
s
t
e
d
t
o
5
0
0
0
p
s
i
i
n
i
t
i
a
l
t
h
e
3
0
0
0
p
s
i
w
e
e
k
l
y
.
29
B
O
P
E
s
,
d
o
t
h
e
y
m
e
e
t
r
e
g
u
l
a
t
i
o
n
Ye
s
5
0
0
0
p
s
i
t
e
s
t
i
n
t
i
a
l
l
y
,
3
0
0
0
p
s
i
a
f
t
e
r
o
n
a
w
e
e
k
l
y
b
a
s
i
s
.
30
B
O
P
E
p
r
e
s
s
r
a
t
i
n
g
a
p
p
r
o
p
r
i
a
t
e
;
t
e
s
t
t
o
(
p
u
t
p
s
i
g
i
n
c
o
m
m
e
n
t
s
)
Ye
s
P
a
r
k
e
r
2
7
3
h
a
s
3
-
1
/
8
"
m
a
n
u
a
l
a
n
d
h
y
d
r
a
u
l
i
c
c
h
o
k
e
,
2
-
9
/
1
6
"
m
a
n
u
a
l
g
a
t
e
v
a
l
v
e
s
31
C
h
o
k
e
m
a
n
i
f
o
l
d
c
o
m
p
l
i
e
s
w
/
A
P
I
R
P
-
5
3
(
M
a
y
8
4
)
Ye
s
32
W
o
r
k
w
i
l
l
o
c
c
u
r
w
i
t
h
o
u
t
o
p
e
r
a
t
i
o
n
s
h
u
t
d
o
w
n
No
33
I
s
p
r
e
s
e
n
c
e
o
f
H
2
S
g
a
s
p
r
o
b
a
b
l
e
Ye
s
34
M
e
c
h
a
n
i
c
a
l
c
o
n
d
i
t
i
o
n
o
f
w
e
l
l
s
w
i
t
h
i
n
A
O
R
v
e
r
i
f
i
e
d
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
No
H
2
S
m
e
a
s
u
r
e
s
r
e
q
u
i
r
e
d
.
R
e
c
e
n
t
(
1
0
/
0
7
/
2
3
)
m
e
a
s
u
r
m
e
n
t
o
f
1
1
5
p
p
m
a
t
P
W
D
W
1
-
2
A
35
P
e
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
i
d
e
m
e
a
s
u
r
e
s
Ye
s
M
a
x
p
o
r
e
p
r
e
s
s
u
r
e
a
n
t
i
c
i
p
a
t
e
d
a
t
1
0
p
p
g
E
M
W
i
n
H
R
Z
a
n
d
L
C
U
.
I
v
i
s
h
a
k
e
x
p
e
c
t
e
d
t
o
b
e
7
.
2
p
p
g
E
M
W
.
36
D
a
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
e
s
s
u
r
e
z
o
n
e
s
NA
37
S
e
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
38
S
e
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
C
o
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
AD
D
Da
t
e
10
/
1
6
/
2
0
2
3
Ap
p
r
MG
R
Da
t
e
10
/
1
8
/
2
0
2
3
Ap
p
r
AD
D
Da
t
e
10
/
1
3
/
2
0
2
3
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
i
n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
JL
C
1
0
/
2
0
/
2
0
2
3
