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1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Install V-String
Development Exploratory
3. Address: Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,489 feet N/A feet
true vertical 7,101 feet N/A feet
Effective Depth measured 7,401 feet N/A feet
true vertical 7,024 feet N/A feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth) 2-3/8" 4.6# / L-80 5,509' MD 5,157' TVD
Packers and SSSV (type, measured and true vertical depth) Liner Top Pkr; N/A 2,590' MD 2,354' TVD N/A; N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
7,500psi
2,980psi
6,880psi
8,430psi
2,808' 2,549'
Burst Collapse
1,410psi
4,790psi
Production
Liner
4,896'
2,597'
Casing
Structural
7,096'
4-1/2"
7,486'
2,597' 2,360'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
2,808'
measured
TVD
8,430psi
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
222-039
50-283-20186-00-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
FEDA029657
Beluga River / Sterling-Beluga Gas
Beluga River Unit (BRU) 222-34
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
30
Size
120'
18 3691611
0 28116
181
Jake Flora, Operations Engineer
323-573
Sr Pet Eng:
7,500psi
Sr Pet Geo: Sr Res Eng:
WINJ WAG
2097
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
jake.flora@hilcorp.com
907-777-8442
N/A
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 11:16 am, Nov 22, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.11.21 13:14:47 -
09'00'
Noel Nocas
(4361)
Rig Start Date End Date
10/30/23 11/13/23
11/02/2023 - Thursday
PJSM, DISCUSS DAILY OPERATIONS, SIM OPS, PRESSURE TESTS, CRANE LIFTS, NIPPLE UP & RIG UP, CREW TRAVEL TO
LOCATION. SPOT IN TRIPLEX PUMP & PRESSURE TEST BODY AND VOIDS ON 7" MANUAL GATE VALVE & CONNECTIONS
ON 7" X 11" TUBING SPOOL. PRESSURE TEST TO 5000 PSI-GOOD TEST. REMOVE 2 WAY CHECK AND SECURE WELL.
NIPPLE UP BOP & SNUBBING EQUIPMENT.
10/31/2023 - Tuesday
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
BRU 222-34 50-283-20186-00-00 222-039
Daily Operations:
11/03/2023 - Friday
PJSM, DISCUSS RIGGING UP, PRESSURE TESTING. CREW TRAVEL TO LOCATION, RIG UP PUMPS, PIT, MIX TESTING FLUID,
FUNCTION TEST EQUIPMENT, FIX AND REPAIR HYDROLIC ISSUES. PICK UP JT OF 2-3/8", MAKE UP CIRCULATING HEAD &
SET SLIPS, PULL 15 K INTO JT, PRESSURE UP TO 3000 PSI WITH TOP ANNUALR & OUTSIDE CHOKE VALVES CLOSED
PERFORM SHELL TEST. MULTIPLE LEAKS, TIGHTEN BOLTS AND MAKE MULTIPLE ATTEMPTS @ SHELL TEST.
UNSUCCESSFUL.
11/05/2023 -Sunday
Finish Pre-testing BOPE looking for any deficiencies while waiting for inspector to arrive, Test BOPE as per Hilcorp &
AOGCC expectations, test witnessed by AOGCC inspector Adam Earl, tested 250/3000 with 2 3/8" TJ, tested primary
BOPE and stripping BOPE, tested gas alarms good. R/D test Eq. Drain & blow down BOPE, prep for picking up pipe, cover
same to protect from building with snow & ice. SDFN
PJSM, DISCUSS DAILY OPERATIONS RIGGING UP & TESTING BOPE, CREW TRAVEL TO LOCATION, TIGHTEN BOPE TO
PERFORM SHELL TEST, CONTINUE RIGGING UP FALL ARREST EQUIPMENT, FUNCTION AND TEST BOPE 250 LOW, 3000
HIGH-GOOD TEST, PERFORM RIG INSPECTION FOR ACCEPTANCE. REVIEW ALL ERP'S WITH COMPANY REPRESENATIVE &
SAFETY DOCUMENTATION.
11/04/2023 - Saturday
PJSM, DISCUSS DAILY OPERATIONS, PRE-TEST BOPE, Warm Eq. While waiting on AOGCC Inspector to arrive (delayed for
weather hold), R/U & PT 2 3/8 pump out plug t/3200psi from below, good, Drift hanger from wk basket through
stripping rams & primary BOPE to 7' wellhead valve good, POOH, P/t PX plug in X-nipple t/3300psi from below, good.
R/U & pre-test BOPE 250/3000psi all good. (Inspector unable to make it to Beluga due to weather will attempt again
tomorrow) SDFN
10/30/2023 - Monday
PJSM, CREW TRAVEL TO LOCATION, SPOT IN PARTIAL EQUIPMENT, RECEIVE APPROVAL FROM AOGCC BRIAN MCLELLAN.
LOTO & BLOW DOWN PRODUCTION AND FLOW LINES WITH OPERATOR, SECURE WELL WITH LOWER MASTER VALVE.
NIPPLE DOWN UPPER TREE, INSTALL 2 WAY CHECK VALVE, CHANGE CAP STRING ROUTING, INSTALL 11" X 7" TUBING
SPOOL, TEST VOIDS TO 5000 PSI, LEAVE 2500 PSI ON VOIDS, MAKE UP 7" MASTER VALVE, SECURE WELL.
11/01/2023-Wenesday
PJSM, DISCUSS RIGGING OPERATIONS, CRANE LIFTS, WORKING AT HEIGHTS. CREW TRAVEL TO LOCATION, NIPPLE UP
PRIMARY BOPS, RIG UP SUB STRUCTURE, NIPPLE UP SECONDARY BOPE, RIG UP EQUIPMENT
Rig Start Date End Date
10/30/23 11/13/23
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
BRU 222-34 50-283-20186-00-00 222-039
Daily Operations:
11/07/2023 - Tuesday
PTSM, Review TSI R/D SOP & hazzard assesment, check well pressures, Tubing 0, 2 3/8 x 4 1/2" 450psi, Blow down & R/D
aux eq. load on transports, drain pits, Prep Snubbing unit & r/d same, load on transport & move to H Pad. N/D primary
BOPE with Snubbing unit sub structure, load on transport & move to H pad. N/U tree, Tq flanges, Test neck seals t/5k
good, fill & test void t/5k good. Fill tree & test t/5k good, pull TWC, turn over to production.
11/06/2023 - Monday
PJSM, Review IRP 15 compliant TSI SOP for snubbing procedures, check current well pressure 400psi, calculate snubbing
forces, & transition depth's. Make up Isolation plug assy, 2 3/8" pump out plug, Pup joint, x-nipple with PX plug, pup
joint, full joint, 10' Marker joint. with closed TIW valve installed, RIH to above 7" valve, close snubbing annular, open 7"
valve equalize pressure, open TIW valve verify no no flow from tubing, Pull TIW valve, Snub in hole, cont. RIH with 2 3/8"
4.6#, L-80 IBT velocity string. run 10 joints making up to M/U marks, getting average torque, continue running in hole
spot checking M/U marks on connections, drift pipe on pipe rack & steel drift when picking up. Snubbed to transition
point then changed over to heavys stripping in hole t/2303', Had compramised hose to Heavy slips. Replace slip hose, &
re-route. Cont. RIH with 2 3/8" 4.6#, L-80 IBT velocity string. F/2303 t/5471', up wt 45, dn wt 33, wellhead pressure
425psi, M/U hanger w/TWC installed & landing joint, strip into hole as per procedure, landing hanger placing tubing tail
(pump out plug) @ 5509', RILD pins, verify measurements on pins good, pull test 5k over good, bleed down void slow for
negative test good, back out landing joint, close blinds pump accross flow cross & fill void, test t/3k 5 min good. blow
down & secure for night
11/13/2023 - Monday
Perform JSA - Gain permit approval. Start equipment- Gather light plant- Prep equipment for transit- Standby for snow
removal. Begin Spot & Rig up. Begin PT to 3000#- Test good- Standby for Equalize. RIH W/ 1.5 Blind box to 5700'KB- W/T-
Shear & knock out plug- fall to 5710'KB- Make multiple passes to confirm KO- POOH. Begin R/D - Prep equipment for
transit. Depart for bull rail- Plug in equipment for the evening- Depart for camp.
_____________________________________________________________________________________
Updated by DMA 11-17-23
SCHEMATIC
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
2
1
PBTD = 7,401 MD / TVD = 7,024
TD = 7,489 MD / TVD = 7,101
RKB to GL = 18
3
4-1/2
6-3/4
hole
7-5/8
9-7/8
hole
16
BEL F6
BEL F7
BEL G3
BEL G5
BEL G9
BEL G10
BEL H2
BEL H3
BEL H4
BEL H5
BEL H7
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16Conductor Driven
to Set Depth 84 X-56 Weld 15.01 Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875Surf 2,808
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.9582,5907,486
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958Surf 2,597
CASING DETAIL
2-3/8Tubing 4.6 L-80 IBT 1.995Surf 5,509
JEWELRY DETAIL
No. Depth ID OD Item
1 2,5904.8756.540Seal Stem / ZXP Liner hanger / LTP Assembly
2 5,5034.8756.540X nip w PX plug
3 5,509Pump out plug (11/6/23)
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (Returns to surface 8/14/22)
4-1/2 Est. TOC @ 4510 (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL F6 4,693'4,702'4,359'4,368'9'06/28/23 Open
BEL F6 4,707'4,717'4,373'4,383'10'06/28/23 Open
BEL F6 4,740'4,750'4,405'4,415'10'06/28/23 Open
BEL F6 4,759'4,765'4,424'4,429'6'06/28/23 Open
BEL F7 4,825'4,840'4,488'4,503'15'06/28/23 Open
BEL F7 4,844'4,854'4,507'4,516'10'06/28/23 Open
BEL F7 4,935'4,955'4,596'4,615'20'06/27/23 Open
BEL G3 5,1375,1544,7934,8101711/22/22 Open
BEL G3 5,163 5,169 4,819 4,825 611/22/22 Open
BEL G5 5,193 5,206 4,848 4,861 1311/22/22 Open
BEL G9 5,360 5,370 5,010 5,020 1011/22/22 Open
BEL G10 5,437 5,4575,087' 5,106'2006/14/23 Open
BEL H2 5,563 5,583 5,212 5,230 2011/21/22 Open
BEL H3 5,594 5,600 5,240 5,246 611/21/22 Open
BEL H3 5,611 5,617 5,257 5,263 611/21/22 Open
BEL H4 5,639 5,6475,284' 5,292'806/14/23 Open
BEL H4 5,650'5,6585,295' 5,303'806/14/23 Open
BEL H4 5,668 5,6765,313' 5,320'806/14/23 Open
BEL H5 5,696 5,7025,340' 5,346'606/14/23 Open
BEL H5 5,710 5,7225,354' 5,365'1206/13/23 Open
BEL H7 5,791 5,8015,433' 5,443'1006/13/23 Open
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 222-34
JBR 01/12/2024
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:0
Shear rams function tested. Good test
Test Results
TEST DATA
Rig Rep:Mike EadieOperator:Hilcorp Alaska, LLC Operator Rep:Harold Soule/Josh Stephens
Rig Owner/Rig No.:Team Snubbing TSI 101 PTD#:2220390 DATE:11/5/2023
Type Operation:WRKOV Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopAGE231113095946
Inspector Adam Earl
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5.5
MASP:
1850
Sundry No:
323-573
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.NA
Test Fluid W
Misc NA
Upper Kelly 0 NA
Lower Kelly 0 NA
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
10 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 1 7 1/16"P
Annular Preventer 1 7 1/16"P
#1 Rams 1 2 3/8" strip.P
#2 Rams 1 2 3/8" strip.P
#3 Rams 1 2 3/8" strip.P
#4 Rams 1 2 3/8"P
#5 Rams 1 Blind P
#6 Rams 1 Shear P
Choke Ln. Valves 1 3 1/8"P
HCR Valves 1 3 1/8"P
Kill Line Valves 3 4 1/16" & 2 1/P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P2200
200 PSI Attained P10
Full Pressure Attained P45
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P3 @ 2300
ACC Misc NA0
NA NATrip Tank
NA NAPit Level Indicators
NA NAFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P6
#1 Rams P3
#2 Rams P3
#3 Rams NA0
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill NA0
From:Jacob Flora
To:McLellan, Bryan J (OGC)
Cc:Joshua Stephenson - (C); Harold Soule - (C); Regg, James B (OGC); Rixse, Melvin G (OGC); Harold Soule - (C)
Subject:RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Compliance (COA #5)
Date:Saturday, October 28, 2023 4:54:35 PM
Attachments:image002.png
Hello Bryan,
I believe the below chapters of IRP 15 are most relevant to our project. Working with our WSMs I’ve compiled in the below table what we believe
are the pertinent chapters and how we plan on addressing the requirements.
We will be addressing the side load analysis in a separate email.
Lastly, the egress descender will be available for inspection on Wednesday during the BOP test.
Please advise on anything additional you require in your review,
Thanks,
Jake
Jake,
The Snubbing SOP does not meet the requirements of CoA #5. I expect Hilcorp to systematically list the requirements in IRP 15 and
demonstrate how they will comply with each.
The structural sideload analysis is for a non-snubbing operation on Furie’s offshore platform. The structural drawing does not appear to
include a snubbing stack on top of the primary BOP. Hilcorp needs to demonstrate how this is applicable to a snubbing operation with a
snubbing BOP stack on BRU 222-34 and BRU 212-26.
AOGCC inspectors will need to see how the Egress Descender is rigged up on location for safe escape from the snubbing basket.
IRP Chapter / Component Compliance Requirement
IRP 15.01.07 BHA components fit in snubbing stack 27' of stack heigth between gate valve & snubbing annular,
current BHA is 10'
Min one plug in tubing 2 plugs are planned: pump out plug & PX plug
Run a marker pup joint in tubing above BHA
pup
marker joints are planned
IRP 15.01.08 Snubbing forces calculated on site Will be done on site, performed by operator
Tubing buckling calculations Will be done on site, performed by operator
Pipe heavy calculations done for MPSP Completed for MPSP of 2394 psi, pipe heavy at 1769'
IRP 15.01.08.02 Prejob calculations including: max snubbing
force required, depth of neutral point,
critical buckling load of tubing string,
collapse point of tubing
Will be done on site, performed by operator
IRP 15.01.09.01 Explosive mixture in casing Well is currently online and gas packed with no exposure to
allowing air in the casing
IRP 15.01.10 Written Procedure requirement TSI Snubbing SOP
Job Scope requirement AOGCC Approved Sundry
IRP 15.01.11 Vendor selection Team Snubbing International
IRP 15.01.12 Supervisory control Hilcorp Wellsite Manager (WSM)
IRP 15.02.02 Plugs shall be tested to 1.3x BHP (1.3 x 2394
psi = 3112psi)
The PX plug has been shop tested to 5000psi. The pump out plug
will be tested during the BOP test. Will be done on site during
BOP test
IRP 15.02.04 Certification Manufacturer spec sheet available for 2-3/8" pump out plug
IRP 15.03.01 Regulatory requirements must be followed
for all primary BOP equipment
AOGCC Regulation/BOP test
Install shear ram as the lowest primary BOP Blind shear ram is planned per approved sundry
Minimum of one hole volume on site Hilcorp will have 240 bbls KWF on location (1.5x WBV (160 bbls x
2)
IRP 15.03.02 Unit shall have engineered fall protection
IRP 15.03.04 Certification & Inspection TSI HWO Unit is certified & inspected per IRP15. All certifications
available on site.
IRP 15.05.01 Worker training TSI training competencies and documentation available on site
IRP 15.06.01 Hazard Assessment PJSM will review hazard assessments per TSI JSA / SOP for Tripping
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Pipe Into Wellbore
IRP 15.06.02 Hazards PJSM will review IRP 15.06.02 Table 8 Hazard Register
IRP 15.07.2 Joint Safety Meetings Hilcorp WSM will hold JSM prior to performing work with multiple
vendors or services on site. Agenda will include a risk assessment,
specific safety requirements, supervisory control, well shut in
procedures, responsibilities, egress, and communication for and
during SIMOPS.
IRP 15.07.3 Meeting Guidance Involve ALL personnel in PJSMs.
IRP 15.08.02 Pre-job calculations Will be done on site, performed by operator
IRP 15.08.03 Egress from snubbing platform Emergency egress system to be shown to AOGCC inspector
IRP 15.08.04 Primary BOPE tested per regulations AOGCC witnessed BOP test
Installing tubing hanger or FOSV Perform 10 min low test to 200 psi, 10 min high pressure test to
3000 psi.
Perform 10 min leak test to WHP if hanger is not landed
IRP 15.08.05 Contingency Practices PJSM will review different failure mechanisms and the corrective
action to then take place as detailed in IRP 15.8.5
IRP 15.08.06 Snubbing in the Dark:Hilcorp will have sufficient light plants on location
IRP 15.08.07.01 Cold Weather Ops/Heaters Hilcorp will have multiple heaters on location
IRP 15.08.09 Setting Jack Pressure Follow steps 1-11 in IRP 15.8.9 to set hydraulic jack pressure
IRP 15.08.13 Landing tubing hanger Hilcorp WSM & TSI supervisor will ensure tubing hanger lock down
screws are fully engaged & pull test is completed prior to bleeding
off stack pressure above
IRP 15.08.24.03 Overnight shut ins Ensure operation is in pipe heavy condition or out of the hole
Ensure dual barriers in tubing: two tubing plugs are in place, TIW
in place
Ensure dual barriers in annulus: close multiple rams and lock
Night watch required per AOGCC COA # 9
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Saturday, October 28, 2023 6:20 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC)
<jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12)
Jake,
The Snubbing SOP does not meet the requirements of CoA #5. I expect Hilcorp to systematically list the requirements in IRP 15 and
demonstrate how they will comply with each.
The structural sideload analysis is for a non-snubbing operation on Furie’s offshore platform. The structural drawing does not appear to
include a snubbing stack on top of the primary BOP. Hilcorp needs to demonstrate how this is applicable to a snubbing operation with a
snubbing BOP stack on BRU 222-34 and BRU 212-26.
AOGCC inspectors will need to see how the Egress Descender is rigged up on location for safe escape from the snubbing basket.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
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.
Sent: Friday, October 27, 2023 11:21 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>
Subject: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12)
Hello Bryan,
Please see attachments meant to satisfy the below outlined COAs. These are the requirements that have to be met at this time per my
understanding.
Please let me know if you have questions or need anything additional as you review-
Thanks,
Jake
COA Attachment
5 Snubbing SOP
6 Calculations below in this email (new pipe heavy depth = 1769’ with 1850 psi SITP)
8 Snubbing SOP
8 Installing tubing hanger
11.a Structural sideload (wind) analysis, drawing
11.b TSI safety meeting report, Rigless inspection
12 Egress / Descender spec sheet
Snubbing calcs using MPSP
Snub 2-3/8” tubing thru stripping annular to ~5700’
a. Expected SITP to snub against = 1850 psi
b. Cross-sectional area of 2-3/8” tubing = 4.4 in2 x 1850 psi = 8140 lbs upward force
c. 8140 lbs / 4.6 lb/ft = 1769 feet of 2-3/8” tubing to run before being pipe heavy
COAs per approved sundry
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and anyattachments 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 considersappropriate.
JSA / Safe Operating Procedure
Page 1
Title: Installing Tubing Hanger While Pipe Heavy
Specific Formal Hazard Assessment:
Task Hazard Rating Control Rating
Installing Tubing hanger while
Heavy
Uneven torques in landing
joint and tubing hanger
3 Verify that connection below tubing hanger is torqued
and the connection above is wrench tight.
1
Gas release 5 Ensure all equipment is pressure tested properly,
take care tagging rams.
2
Improper install of lag bolts 5 Count turns, may require flushing bowl. 2
Reference to other related Formal Hazard Assessments
Additional On-Site Hazard Assessment:
Identify HAZARDS: Is there a possibility of striking against, being struck by, or making harmful contact with an object; of
being caught in, by, or between objects; of slipping, tripping, or falling; of developing a strain from pushing, pulling, lif ting
bending, or twisting; of coming in contact with electricity or other power source; of receiving a thermal or chemical burn; o f being exposed
to hazardous environment or of compromising well control?
Task Hazard Rating Control Rating
JSA / Safe Operating Procedure
Page 2
Standard Operating Procedure:
1. Measure landing joint and mark it to know when tagging bowl and install stabbing valve.
2. Install tubing hanger and landing joint on to stump. Tighten with tongs and confirm lower connection is torqued to specifications.
3. Close lower stripping Rams, bleed off fully and open Annular BOP.
4. Jack heavy, short strokes until hanger tags Rams and lift the string 0.3m (1’) to ensure the tubing hanger is in fluted spool.
5. Close Annular and ensure jack has a really low bite with only both traveling slips shut on tubing.
6. Equalize very slowly, watching weights to ensure dog nut is not sealing in the snubbing stack.
7. Once equalized, leave equalizer valve open.
8. Open Rams and jack down to tag point.
9. Ensure you know up and down weights. Tag bowl and tighten and measure leg screws.
10. Once legs screws are tight, pull pipe over 2daN. If good, recheck to make sure leg screws are tight.
Position Requirements:
Supervisor: Maintain clear communication and lead the operation, Direct all personnel as necessary. Work with all individuals with upmost
respect and ethics.
Operator: Maintain clear communication and lead the operation with direction from the supervisor, Direct all personnel as necessary and assist
in identifying hazards. Work with all individuals with upmost respect and ethics.
Assistant: Maintain clear communication and perform duties as directed by the operator, Direct personal as necessary, and identify hazards.
Work with all individuals with upmost respect and ethics. Stop work if unsure of next task.
JSA / Safe Operating Procedure
Page 3
Specific PPE required:
Please utilize back of sheets if required for notes. Please ensure signed copies are placed in Job File and sent to head off ice for filing.
Initials of Review:
MSDS Information
Two-Way Radio's Barricades Chemical Respirator
Wet Suit Rubber Boots Rubber Gloves
LEL Monitor Lock-Out Equipment Vent Fans
SABA SCBA Gas Detector
Face Sheild Fall Protection Equipment Fire Extinguisher
Steel Toed Work Boots Safety Glasses Chemical Goggles
Gloves Hardhat Fire Resistant Coveralls
JSA / Safe Operating Procedure
Page 4
JSA / Safe Operating Procedure
Page 1
Title: Tripping Pipe into Wellbore
Specific Formal Hazard Assessment:
Task Hazard Rating Control Rating
Snubbing/Tripping pipe into
Wellbore
Dropping tubing string down
hole.
8 Complete pipe Light/Heavy Calculation as follows:
Tubing Diameter x Tubing Diameter x 0.7854 x well
pressure
3
Pinch points and overhead
hazards.
8 Use tag lines if necessary and position hands and
body safely.
3
Slip failure.
8 Clean and replace slip dies before the job. 3
Gas release at surface.
8 Equalize slowly.
3
Tubing buckling/parting if the
string bottom strikes the bit
guide, etc. as it enters the well.
8 Refer to D.G.1.01 Setting Jack Pressure 3
Slip failure, accumulator
failure, pressure building in the
well as you compress
fluid/gas, pipe dropping down
the well or pressure lifting the
tubing up and out of the well.
8 Watch your gauges for pressure build up and
changes in accumulator status, slip dies for wear,
and pay attention to everything around you - unusual
noises and things that don't look and feel right.
3
JSA / Safe Operating Procedure
Page 2
Dropping tubing string down
hole.
8 Be aware of what you are doing. Go slow and be
sure pipe is neutral. Double check pipe count to
match number from Step #2.
3
Reference to other related Formal Hazard Assessments
Additional On-Site Hazard Assessment:
Identify HAZARDS: Is there a possibility of striking against, being struck by, or making harmful contact with an object; of
being caught in, by, or between objects; of slipping, tripping, or falling; of developing a strain from pushing, pulling, lifting
bending, or twisting; of coming in contact with electricity or other power source; of receiving a thermal or chemical burn; of being exposed
to hazardous environment or of compromising well control?
Task Hazard Rating Control Rating
JSA / Safe Operating Procedure
Page 3
Standard Operating Procedure:
1. Hold Pre-Job Safety Meeting and discuss with rig crew preferred method of handling tubulars while snubbing - winch line or blocks.
2. Use well bore pressure and tubing size to calculate approx. how many joints will need to be snubbed in.
3. Position 1st joint/BHA in stack.
4. Close stationary snubbing slips (SS), raise travelling plate ~ 6 inches, close travelling snubbing slips (TS), travelling hea vy slips (TH) and
pull into SS with the jack to ensure SS are holding.
5. Close Annular and equalize the stack with casing pressure. Adjust the annular control as needed.
6. If there are no leaks anywhere on the stack, unlock and open blind rams and lubricate NSI annular with oil.
7. Set jack pressure and begin snubbing in the hole.
8. Continue snubbing in the hole until pipe starts to slide downwards in the slips a little bit indicating that you are approaching pipe neutral or,
when you approach your number from Step #2.
9. When the pipe starts to slide down, on your first stoke after a connection, snub the first collar so it is just above the NSI annular.
10. Leaving the SS open and the TS closed, raise the jack plate. Watch tbg
11. If tubing does not rise with the jack plate, then pipe is neutral. Begin snubbing pipe in with TH closed as well.
12. After you have snubbed ~ 3 more joints in using 3 slips, on your last stroke of that joint, once pipe is moving down, open your TS. If pipe
continues down, you are pipe heavy.
13. Tell driller you are ready to begin tripping with the blocks and snubbing only the collars.
14. After the connection is torqued with the tongs have the driller pick out of the TH and stop. Raise jack plate to near top. Set jack pressure
to 5 daN
15. Have the driller come down slowly and smoothly. Match this speed with the jack.
16. Time your speed and jack height so you can push the collar through the annular smoothly in one stroke.
JSA / Safe Operating Procedure
Page 4
Position Requirements:
Supervisor: Maintain clear communication and lead the operation, Direct all personnel, as necessary. Work with all individuals with upmost
respect and ethics.
Operator: Maintain clear communication and lead the operation with direction from the supervisor, direct all personal as necessary and assist in
identifying hazards. Work with all individuals with upmost respect and ethics.
Assistant: Maintain clear communication and perform duties as directed by the operator, Direct personal as necessary, and identify hazards.
Work with all individuals with upmost respect and ethics. Stop work if unsure of next task.
JSA / Safe Operating Procedure
Page 5
Specific PPE required:
Please utilize back of sheets if required for notes. Please ensure signed copies are placed in Job File and sent to head office for filing.
Initials of Review:
MSDS Information
Two-Way Radio's Barricades Chemical Respirator
Wet Suit Rubber Boots Rubber Gloves
LEL Monitor Lock-Out Equipment Vent Fans
SABA SCBA Gas Detector
Face Sheild Fall Protection Equipment Fire Extinguisher
Steel Toed Work Boots Safety Glasses Chemical Goggles
Gloves Hardhat Fire Resistant Coveralls
JSA / Safe Operating Procedure
Page 6
DIMENSIONS & TOLERANCES
1°
FRACTIONAL
ANGULAR
0.0
0.00
0.000 ±
0.030
0.015
0.005
±
±
±
±1/16
±0.0000 0.001 ENERGY SERVICESICON
6" 48"
0"
191 1/2"
568" WORK FLOOR
60" TOP OF VALVE
78" 7-1/16 5M BLIND SHEAR
87"
111" 7-1/16 5M DOUBLE GATE
128 1/2"
144 1/2" 7-1/16 5M ANNULAR
159 1/2"
183 1/2"
224 1/2"
248 1/2"
272 1/2"
290 1/2" 7-1/16 15K SINGLE GATE
322"
330" WORK FLOOR
361" 7-1/16 5M ANNULAR
260 1/2"
R40 FT
A
A
GUY E
GUY FGUY G
GUY H
NOTE: REFER TO OEM SPECS FOR GUY
GIN POLE GUY REQUIREMENTS
ESCAPE POLES DEPLOYED
TO SUB STRUCTURE PLATFORM
50° MAX
SECTION A-A
NOTE: ANCHOR BLOCKS MUST BE PLACED ON SOLID
GROUND WITH ANCHOR CLEATS EMBEDDED IN SOIL.
RECOMMENED MINIMUM ANCHOR WEIGHT 18,000 LB
NOTE: SCREW JACKS SHOULD BE
TORQUED TO 100 LB*FT TO
ENSURE LMS IS SUPORTING JACK
LOAD. CONFIRM DAILY
4' SQUARE PADS
6" THICK
NOTE: LINE LOADS ASSUME STRUCTURE IS FULLY ENCLOSED FOR WIND LOADING
GUYWIRE SPECS
EXPECTED LOAD TENSION 9,000 LB BASED ON 1,000 LB PRE-TENSION. 3/4 IWRC EIPS 6X19 WIRE ROPE
GUY E 60 FT
GUY F 60 FT
GUY G 60 FT
GUY H 60 FT
0SD05~HILCORP GUYLINESSHEET 1 OF 1 REV:ARCH C
GENERAL NOTES:1. U.N.O. ALL FILLET WELDS TO BE 1/4" CONTINUOUS.2. U.N.O. ALL BUTT WELDS TO BE 1/4" CONTINUOUS.3. SEAL WELD ALL TUBING.4. STICK AND FLUX-CORE WELDING PROCEDURES ARE INTERCHANGABLE ON AN EQUIVALENT BASIS.5. DO NOT SCALE DRAWING.6. IF IN DOUBT ASK.
RIG#DRAWN:
CHECKED:
APPROVED:
DATE:
SHEET SIZE:PROJECTION:SD02 TOP LEVEL ASSEMBLY
IC
RE
CUSTOMER:
FILE:
TITLE:
TEAM SNUBBING
SHEET TITLE:GENERAL ASSY
TS101
DWG#:2023-10-29
ALASKA JACK PACKAGE18033~
THE INFORMATION INCLUDED IN THIS DOCUMENT
IS PROPRIETARY AND SHALL NOT BE REPRODUCED,
TRANSFERRED, OR DISCLOSED TO OTHERS, FOR ANY
PURPOSE WHATSOEVER, WITHOUT THE WRITTEN
AUTHORIZATION OF ICON ENERGY SERVICES.
76146.1 LBWT:
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:McLellan, Bryan J (OGC)
To:Jacob Flora; Joshua Stephenson - (C); Harold Soule - (C)
Cc:Regg, James B (OGC)
Subject:RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - request to proceed with pre-rig steps 1-6
Date:Monday, October 30, 2023 10:25:00 AM
Jake,
Hilcorp has approval to proceed with the steps listed below.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Sunday, October 29, 2023 4:07 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Joshua Stephenson - (C)
<Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>
Subject: BRU 222-34 (Sundry 323-573) (PTD 222-039) - request to proceed with pre-rig steps 1-6
Bryan,
Hilcorp requests approval to perform the Pre-Rig steps #1-6 in the approved sundry. Anything that
we can do now will ensure our schedule will remain on track to barge back on November 6-8th.
Both WSMs (Joshua Stephenson, Harold Soule) are in Beluga now and attached to this email.
Thanks,
Jake
Summary of steps:
1. Set TWC w lubricator
2. ND tree
3. Reroute control line
4. NU tubing head
5. NU 7-1/16 gate valve, test same
6. Pull TWC w lubricator, close gate valve
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
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From:McLellan, Bryan J (OGC)
To:Jacob Flora
Cc:Joshua Stephenson - (C); Harold Soule - (C); Regg, James B (OGC); Rixse, Melvin G (OGC)
Subject:RE: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12)
Date:Monday, October 30, 2023 10:21:00 AM
Attachments:image002.png
Thanks Jake
This satisfies CoA #11a in approved sundry 323-573.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, October 30, 2023 10:07 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC)
<jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12)
Bryan,
Please see attached the as-planned layout for the snubbing unit, including:
Guywire layout & tension specs
Jack stand torque specs
Jack stand pads
Anchor block weights
Please advise if you need more data,
Thanks,
Jake
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Saturday, October 28, 2023 6:20 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC)
<jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12)
Jake,
The Snubbing SOP does not meet the requirements of CoA #5. I expect Hilcorp to systematically list the requirements in IRP 15 and
demonstrate how they will comply with each.
The structural sideload analysis is for a non-snubbing operation on Furie’s offshore platform. The structural drawing does not appear to
include a snubbing stack on top of the primary BOP. Hilcorp needs to demonstrate how this is applicable to a snubbing operation with a
snubbing BOP stack on BRU 222-34 and BRU 212-26.
AOGCC inspectors will need to see how the Egress Descender is rigged up on location for safe escape from the snubbing basket.
Bryan McLellan
Senior Petroleum Engineer
JSA / Safe Operating Procedure
Page 1
Title: Tripping Pipe into Wellbore
Specific Formal Hazard Assessment:
Task Hazard Rating Control Rating
Snubbing/Tripping pipe into
Wellbore
Dropping tubing string down
hole.
8 Complete pipe Light/Heavy Calculation as follows:
Tubing Diameter x Tubing Diameter x 0.7854 x well
pressure
3
Pinch points and overhead
hazards.
8 Use tag lines if necessary and position hands and
body safely.
3
Slip failure.
8 Clean and replace slip dies before the job. 3
Gas release at surface.
8 Equalize slowly.
3
Tubing buckling/parting if the
string bottom strikes the bit
guide, etc. as it enters the well.
8 Refer to D.G.1.01 Setting Jack Pressure 3
Slip failure, accumulator
failure, pressure building in the
well as you compress
fluid/gas, pipe dropping down
the well or pressure lifting the
tubing up and out of the well.
8 Watch your gauges for pressure build up and
changes in accumulator status, slip dies for wear,
and pay attention to everything around you - unusual
noises and things that don't look and feel right.
3
JSA / Safe Operating Procedure
Page 2
Dropping tubing string down
hole.
8 Be aware of what you are doing. Go slow and be
sure pipe is neutral. Double check pipe count to
match number from Step #2.
3
Reference to other related Formal Hazard Assessments
Additional On-Site Hazard Assessment:
Identify HAZARDS: Is there a possibility of striking against, being struck by, or making harmful contact with an object; of
being caught in, by, or between objects; of slipping, tripping, or falling; of developing a strain from pushing, pulling, lifting
bending, or twisting; of coming in contact with electricity or other power source; of receiving a thermal or chemical burn; of being exposed
to hazardous environment or of compromising well control?
Task Hazard Rating Control Rating
JSA / Safe Operating Procedure
Page 3
Standard Operating Procedure:
1. Hold Pre-Job Safety Meeting and discuss with rig crew preferred method of handling tubulars while snubbing - winch line or blocks.
2. Use well bore pressure and tubing size to calculate approx. how many joints will need to be snubbed in.
3. Position 1st joint/BHA in stack.
4. Close stationary snubbing slips (SS), raise travelling plate ~ 6 inches, close travelling snubbing slips (TS), travelling hea vy slips (TH) and
pull into SS with the jack to ensure SS are holding.
5. Close Annular and equalize the stack with casing pressure. Adjust the annular control as needed.
6. If there are no leaks anywhere on the stack, unlock and open blind rams and lubricate NSI annular with oil.
7. Set jack pressure and begin snubbing in the hole.
8. Continue snubbing in the hole until pipe starts to slide downwards in the slips a little bit indicating that you are approaching pipe neutral or,
when you approach your number from Step #2.
9. When the pipe starts to slide down, on your first stoke after a connection, snub the first collar so it is just above the NSI annular.
10. Leaving the SS open and the TS closed, raise the jack plate. Watch tbg
11. If tubing does not rise with the jack plate, then pipe is neutral. Begin snubbing pipe in with TH closed as well.
12. After you have snubbed ~ 3 more joints in using 3 slips, on your last stroke of that joint, once pipe is moving down, open your TS. If pipe
continues down, you are pipe heavy.
13. Tell driller you are ready to begin tripping with the blocks and snubbing only the collars.
14. After the connection is torqued with the tongs have the driller pick out of the TH and stop. Raise jack plate to near top. Set jack pressure
to 5 daN
15. Have the driller come down slowly and smoothly. Match this speed with the jack.
16. Time your speed and jack height so you can push the collar through the annular smoothly in one stroke.
JSA / Safe Operating Procedure
Page 4
Position Requirements:
Supervisor: Maintain clear communication and lead the operation, Direct all personnel, as necessary. Work with all individuals with upmost
respect and ethics.
Operator: Maintain clear communication and lead the operation with direction from the supervisor, direct all personal as necessary and assist in
identifying hazards. Work with all individuals with upmost respect and ethics.
Assistant: Maintain clear communication and perform duties as directed by the operator, Direct personal as necessary, and identify hazards.
Work with all individuals with upmost respect and ethics. Stop work if unsure of next task.
JSA / Safe Operating Procedure
Page 5
Specific PPE required:
Please utilize back of sheets if required for notes. Please ensure signed copies are placed in Job File and sent to head office for filing.
Initials of Review:
MSDS Information
Two-Way Radio's Barricades Chemical Respirator
Wet Suit Rubber Boots Rubber Gloves
LEL Monitor Lock-Out Equipment Vent Fans
SABA SCBA Gas Detector
Face Sheild Fall Protection Equipment Fire Extinguisher
Steel Toed Work Boots Safety Glasses Chemical Goggles
Gloves Hardhat Fire Resistant Coveralls
JSA / Safe Operating Procedure
Page 6
DIMENSIONS & TOLERANCES
1°
FRACTIONAL
ANGULAR
0.0
0.00
0.000 ±
0.030
0.015
0.005
±
±
±
±1/16
±0.0000 0.001 ENERGY SERVICESICON
6" 48"
0"
191 1/2"
568" WORK FLOOR
60" TOP OF VALVE
78" 7-1/16 5M BLIND SHEAR
87"
111" 7-1/16 5M DOUBLE GATE
128 1/2"
144 1/2" 7-1/16 5M ANNULAR
159 1/2"
183 1/2"
224 1/2"
248 1/2"
272 1/2"
290 1/2" 7-1/16 15K SINGLE GATE
322"
330" WORK FLOOR
361" 7-1/16 5M ANNULAR
260 1/2"
R40 FT
A
A
GUY E
GUY FGUY G
GUY H
NOTE: REFER TO OEM SPECS FOR GUY
GIN POLE GUY REQUIREMENTS
ESCAPE POLES DEPLOYED
TO SUB STRUCTURE PLATFORM
50° MAX
SECTION A-A
NOTE: ANCHOR BLOCKS MUST BE PLACED ON SOLID
GROUND WITH ANCHOR CLEATS EMBEDDED IN SOIL.
RECOMMENED MINIMUM ANCHOR WEIGHT 18,000 LB
NOTE: SCREW JACKS SHOULD BE
TORQUED TO 100 LB*FT TO
ENSURE LMS IS SUPORTING JACK
LOAD. CONFIRM DAILY
4' SQUARE PADS
6" THICK
NOTE: LINE LOADS ASSUME STRUCTURE IS FULLY ENCLOSED FOR WIND LOADING
GUYWIRE SPECS
EXPECTED LOAD TENSION 9,000 LB BASED ON 1,000 LB PRE-TENSION. 3/4 IWRC EIPS 6X19 WIRE ROPE
GUY E 60 FT
GUY F 60 FT
GUY G 60 FT
GUY H 60 FT
0SD05~HILCORP GUYLINESSHEET 1 OF 1 REV:ARCH C
GENERAL NOTES:1. U.N.O. ALL FILLET WELDS TO BE 1/4" CONTINUOUS.2. U.N.O. ALL BUTT WELDS TO BE 1/4" CONTINUOUS.3. SEAL WELD ALL TUBING.4. STICK AND FLUX-CORE WELDING PROCEDURES ARE INTERCHANGABLE ON AN EQUIVALENT BASIS.5. DO NOT SCALE DRAWING.6. IF IN DOUBT ASK.
RIG#DRAWN:
CHECKED:
APPROVED:
DATE:
SHEET SIZE:PROJECTION:SD02 TOP LEVEL ASSEMBLY
IC
RE
CUSTOMER:
FILE:
TITLE:
TEAM SNUBBING
SHEET TITLE:GENERAL ASSY
TS101
DWG#:2023-10-29
ALASKA JACK PACKAGE18033~
THE INFORMATION INCLUDED IN THIS DOCUMENT
IS PROPRIETARY AND SHALL NOT BE REPRODUCED,
TRANSFERRED, OR DISCLOSED TO OTHERS, FOR ANY
PURPOSE WHATSOEVER, WITHOUT THE WRITTEN
AUTHORIZATION OF ICON ENERGY SERVICES.
76146.1 LBWT:
JSA / Safe Operating Procedure
Page 1
Title: Installing Tubing Hanger While Pipe Heavy
Specific Formal Hazard Assessment:
Task Hazard Rating Control Rating
Installing Tubing hanger while
Heavy
Uneven torques in landing
joint and tubing hanger
3 Verify that connection below tubing hanger is torqued
and the connection above is wrench tight.
1
Gas release 5 Ensure all equipment is pressure tested properly,
take care tagging rams.
2
Improper install of lag bolts 5 Count turns, may require flushing bowl. 2
Reference to other related Formal Hazard Assessments
Additional On-Site Hazard Assessment:
Identify HAZARDS: Is there a possibility of striking against, being struck by, or making harmful contact with an object; of
being caught in, by, or between objects; of slipping, tripping, or falling; of developing a strain from pushing, pulling, lif ting
bending, or twisting; of coming in contact with electricity or other power source; of receiving a thermal or chemical burn; o f being exposed
to hazardous environment or of compromising well control?
Task Hazard Rating Control Rating
JSA / Safe Operating Procedure
Page 2
Standard Operating Procedure:
1. Measure landing joint and mark it to know when tagging bowl and install stabbing valve.
2. Install tubing hanger and landing joint on to stump. Tighten with tongs and confirm lower connection is torqued to specifications.
3. Close lower stripping Rams, bleed off fully and open Annular BOP.
4. Jack heavy, short strokes until hanger tags Rams and lift the string 0.3m (1’) to ensure the tubing hanger is in fluted spool.
5. Close Annular and ensure jack has a really low bite with only both traveling slips shut on tubing.
6. Equalize very slowly, watching weights to ensure dog nut is not sealing in the snubbing stack.
7. Once equalized, leave equalizer valve open.
8. Open Rams and jack down to tag point.
9. Ensure you know up and down weights. Tag bowl and tighten and measure leg screws.
10. Once legs screws are tight, pull pipe over 2daN. If good, recheck to make sure leg screws are tight.
Position Requirements:
Supervisor: Maintain clear communication and lead the operation, Direct all personnel as necessary. Work with all individuals with upmost
respect and ethics.
Operator: Maintain clear communication and lead the operation with direction from the supervisor, Direct all personnel as necessary and assist
in identifying hazards. Work with all individuals with upmost respect and ethics.
Assistant: Maintain clear communication and perform duties as directed by the operator, Direct personal as necessary, and identify hazards.
Work with all individuals with upmost respect and ethics. Stop work if unsure of next task.
JSA / Safe Operating Procedure
Page 3
Specific PPE required:
Please utilize back of sheets if required for notes. Please ensure signed copies are placed in Job File and sent to head off ice for filing.
Initials of Review:
MSDS Information
Two-Way Radio's Barricades Chemical Respirator
Wet Suit Rubber Boots Rubber Gloves
LEL Monitor Lock-Out Equipment Vent Fans
SABA SCBA Gas Detector
Face Sheild Fall Protection Equipment Fire Extinguisher
Steel Toed Work Boots Safety Glasses Chemical Goggles
Gloves Hardhat Fire Resistant Coveralls
JSA / Safe Operating Procedure
Page 4
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Cc:Joshua Stephenson - (C); Harold Soule - (C); Regg, James B (OGC); Rixse, Melvin G (OGC); Harold Soule - (C)
Subject:RE: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Compliance (COA #5)
Date:Monday, October 30, 2023 12:53:00 PM
Attachments:image002.png
Jake,
Thank you for demonstrating how Hilcorp intends to adhere to the rules of IRP 15. This satisfies the requirement of Condition of Approval #5 in
the approved sundries 323-573.
Will these same measures be taken during the snubbing operation on BRU 212-26, per sundry 323-521?
Thank you
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, October 30, 2023 10:46 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC)
<jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Harold Soule - (C) <hsoule@hilcorp.com>
Subject: RE: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Compliance (COA #5)
Bryan,
Hilcorp agrees that we are ultimately responsible for ensuring Team Snubbing International (TSI) is following IRP 15. I’ve made clear our
expectation to TSI that the “must” and “shall” statements within IRP 15 will be followed.
Hilcorp wellsite leaders will ensure the Industry Recommended Practices are followed in the execution of these jobs.
To assure this is done Hilcorp has:
1. Doubled our WSM coverage to increase our oversight capacity
a. Brought in our most experienced Cook Inlet WSM in Harold Soule
b. Brought in a WSM with prior snubbing experience in Joshua Stephenson
2. Hilcorp WSM expectation is clear: WSM oversight will ensure IRP 15 is followed by TSI
To assure this is done TSI will:
1. Use pre-rigup checklist from IRP 15
a. available on site
2. Use daily inspection checklist from IRP 15
a. available on site
b. signed by Hilcorp WSM
c. includes calculations performed by the “Snubbing Operator”. This is most similar to the Driller on a drilling rig and is the
person responsible for the safe operation and movement of pipe. This statement is to clarify in the table who the “Operator”
is in the table. Hilcorp WSM will be double checking these calculations and signing off on them.
i. All calculations listed in IRP 15.1.8.2: Max snubbing force, neutral point, critical buckling load, tubing collapse point
ii. Calculations to be done for MPSP as listed in AOGCC 10-403 (2394 psi)
3. Have available upon request on all inspection, certification and training documents
Please advise if there is anything specific we can address in your review-
Thank you,
Jake
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Sent: Monday, October 30, 2023 10:00 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC)
<jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Harold Soule - (C) <hsoule@hilcorp.com>
Subject: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Compliance (COA #5)
Jake,
This is a good start. There are lots of other shall and must statements in IRP 15 not included in your table. Have you let TSI know that they are
expected to follow all of the “shall” and “must” statements, or else ask for AOGCC approval if they do not intend to follow them? At the end of the
day, it is Hilcorp’s responsibility to make sure they are followed, so how do you know if they are being followed or not?
I put a couple questions/comments in red in the table below.
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Saturday, October 28, 2023 4:54 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC)
<jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Harold Soule - (C) <hsoule@hilcorp.com>
Subject: RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Compliance (COA #5)
Hello Bryan,
I believe the below chapters of IRP 15 are most relevant to our project. Working with our WSMs I’ve compiled in the below table what we believe
are the pertinent chapters and how we plan on addressing the requirements.
We will be addressing the side load analysis in a separate email.
Lastly, the egress descender will be available for inspection on Wednesday during the BOP test.
Please advise on anything additional you require in your review,
Thanks,
Jake
Jake,
The Snubbing SOP does not meet the requirements of CoA #5. I expect Hilcorp to systematically list the requirements in IRP 15 and
demonstrate how they will comply with each.
The structural sideload analysis is for a non-snubbing operation on Furie’s offshore platform. The structural drawing does not appear to
include a snubbing stack on top of the primary BOP. Hilcorp needs to demonstrate how this is applicable to a snubbing operation with a
snubbing BOP stack on BRU 222-34 and BRU 212-26.
AOGCC inspectors will need to see how the Egress Descender is rigged up on location for safe escape from the snubbing basket.
IRP Chapter / Component Compliance Requirement
IRP 15.01.07 BHA components fit in snubbing stack 27' of stack heigth between gate valve & snubbing annular,
current BHA is 10'
Min one plug in tubing 2 plugs are planned: pump out plug & PX plug
Run a marker pup joint in tubing above BHA
pup
marker joints are planned
IRP 15.01.08 Snubbing forces calculated on site Will be done on site, performed by operator Who is the operator?
Hilcorp is the Operator, per AOGCC regulatory definition. -bjm
Tubing buckling calculations Will be done on site, performed by operator
Pipe heavy calculations done for MPSP Completed for MPSP of 2394 psi, pipe heavy at 1769'
IRP 15.01.08.02 Prejob calculations including: max snubbing
force required, depth of neutral point,
critical buckling load of tubing string,
collapse point of tubing
Will be done on site, performed by operator
For planning purposes and equipment ratings, snubbing calcs to
be included in the sundry using MPSP as basis for calculations
IRP 15.01.09.01 Explosive mixture in casing Well is currently online and gas packed with no exposure to
allowing air in the casing
IRP 15.01.10 Written Procedure requirement TSI Snubbing SOP
Job Scope requirement AOGCC Approved Sundry
IRP 15.01.11 Vendor selection Team Snubbing International
IRP 15.01.12 Supervisory control Hilcorp Wellsite Manager (WSM)
IRP 15.02.02 Plugs shall be tested to 1.3x BHP (1.3 x 2394
psi = 3112psi)
The PX plug has been shop tested to 5000psi. The pump out plug
will be tested during the BOP test. Will be done on site during
BOP test
IRP 15.02.04 Certification Manufacturer spec sheet available for 2-3/8" pump out plug
IRP 15.03.01 Regulatory requirements must be followed
for all primary BOP equipment
AOGCC Regulation/BOP test
Install shear ram as the lowest primary BOP Blind shear ram is planned per approved sundry
Minimum of one hole volume on site Hilcorp will have 240 bbls KWF on location (1.5x WBV (160 bbls x
2)
IRP 15.03.02 Unit shall have engineered fall protection
IRP 15.03.04 Certification & Inspection TSI HWO Unit is certified & inspected per IRP15. All certifications
available on site.
IRP 15.05.01 Worker training TSI training competencies and documentation available on site
IRP 15.06.01 Hazard Assessment PJSM will review hazard assessments per TSI JSA / SOP for Tripping
Pipe Into Wellbore
IRP 15.06.02 Hazards PJSM will review IRP 15.06.02 Table 8 Hazard Register
IRP 15.07.2 Joint Safety Meetings Hilcorp WSM will hold JSM prior to performing work with multiple
vendors or services on site. Agenda will include a risk assessment,
specific safety requirements, supervisory control, well shut in
procedures, responsibilities, egress, and communication for and
during SIMOPS.
IRP 15.07.3 Meeting Guidance Involve ALL personnel in PJSMs.
IRP 15.08.02 Pre-job calculations Will be done on site, performed by operator
IRP 15.08.03 Egress from snubbing platform Emergency egress system to be shown to AOGCC inspector
IRP 15.08.04 Primary BOPE tested per regulations AOGCC witnessed BOP test
Installing tubing hanger or FOSV Perform 10 min low test to 200 psi, 10 min high pressure test to
3000 psi.
Perform 10 min leak test to WHP if hanger is not landed
IRP 15.08.05 Contingency Practices PJSM will review different failure mechanisms and the corrective
action to then take place as detailed in IRP 15.8.5
IRP 15.08.06 Snubbing in the Dark:Hilcorp will have sufficient light plants on location
IRP 15.08.07.01 Cold Weather Ops/Heaters Hilcorp will have multiple heaters on location
IRP 15.08.09 Setting Jack Pressure Follow steps 1-11 in IRP 15.8.9 to set hydraulic jack pressure
IRP 15.08.13 Landing tubing hanger Hilcorp WSM & TSI supervisor will ensure tubing hanger lock down
screws are fully engaged & pull test is completed prior to bleeding
off stack pressure above
IRP 15.08.24.03 Overnight shut ins Ensure operation is in pipe heavy condition or out of the hole
Ensure dual barriers in tubing: two tubing plugs are in place, TIW
in place
Ensure dual barriers in annulus: close multiple rams and lock
Night watch required per AOGCC COA # 9
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.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Saturday, October 28, 2023 6:20 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Regg, James B (OGC)
<jim.regg@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] RE: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12)
Jake,
The Snubbing SOP does not meet the requirements of CoA #5. I expect Hilcorp to systematically list the requirements in IRP 15 and
demonstrate how they will comply with each.
The structural sideload analysis is for a non-snubbing operation on Furie’s offshore platform. The structural drawing does not appear to
include a snubbing stack on top of the primary BOP. Hilcorp needs to demonstrate how this is applicable to a snubbing operation with a
snubbing BOP stack on BRU 222-34 and BRU 212-26.
AOGCC inspectors will need to see how the Egress Descender is rigged up on location for safe escape from the snubbing basket.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Friday, October 27, 2023 11:21 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Joshua Stephenson - (C) <Joshua.Stephenson@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>
Subject: BRU 222-34 (Sundry 323-573) (PTD 222-039) - Snubbing Unit stack and stabilization design (COA #5, 6, 8, 11, 12)
Hello Bryan,
Please see attachments meant to satisfy the below outlined COAs. These are the requirements that have to be met at this time per my
understanding.
Please let me know if you have questions or need anything additional as you review-
Thanks,
Jake
COA Attachment
5 Snubbing SOP
6 Calculations below in this email (new pipe heavy depth = 1769’ with 1850 psi SITP)
8 Snubbing SOP
8 Installing tubing hanger
11.a Structural sideload (wind) analysis, drawing
11.b TSI safety meeting report, Rigless inspection
12 Egress / Descender spec sheet
Snubbing calcs using MPSP
Snub 2-3/8” tubing thru stripping annular to ~5700’
a. Expected SITP to snub against = 1850 psi
b. Cross-sectional area of 2-3/8” tubing = 4.4 in2 x 1850 psi = 8140 lbs upward force
c. 8140 lbs / 4.6 lb/ft = 1769 feet of 2-3/8” tubing to run before being pipe heavy
COAs per approved sundry
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1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install V-String, N2
2.Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field: Current Pools:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,489'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner 7,500psi
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Sterling-Beluga Gas
Liner Top; N/A 2,590' MD/2,354' TVD; N/A
7,101'7,401'7,024'
16"
7-5/8"
See Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 222-34CO 802
Same
7,098'4-1/2"
~1,850psi
4,896'
N/A
Length
November 1, 2023
2,597'2,597'
N/A
2,360'
7,486'
Perforation Depth MD (ft):
4-1/2"
See Schematic
2,980psi
6,880psi
120'120'
2,808'
Size
120'
2,808'
MD
Proposed Pools:
N/A
TVD Burst
N/A
8,430psi
2,549'
Beluga River
Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA029657
222-039
50-283-20186-00-00
Hilcorp Alaska, LLC
PRESENT WELL CONDITION SUMMARY
Jake Flora, Operations Engineer
AOGCC USE ONLY
8,430psi
Tubing Grade:Tubing MD (ft):
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
m
n
P
s
t
2
N
66
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 2:45 pm, Oct 19, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.10.19 14:09:29 -
08'00'
Noel Nocas
(4361)
323-573
SFD 10/20/2023
10-404
DSR-10/19/23
BOP test to 3000 psi.
See attached conditions of approval.
X
BJM 10/24/23*&:
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.10.24 13:42:11
-08'00'10/24/23
RBDMS JSB 102623
BRU 222-34 (PTD 222-039) Sundry 323-573 ^ŶƵďďŝŶŐŽƉĞƌĂƟŽŶ
ŽŶĚŝƟŽŶƐŽĨƉƉƌŽǀĂů
1. BOP test to 3000 psi. Shear rams capable of shearing 2-7/8" tubing must be included in BOP
stack.
2. Provide 48 hrs ŶŽƟĐĞƚŽK'ĨŽƌƌŝŐŝŶƐƉĞĐƟŽŶĂŶĚKWƚĞƐƚ͘
3. ŶŶƵůĂƌƉƌŽĚƵĐƟŽŶĨƌŽŵϮ-3/8" x 5-ϭͬϮΗĂŶŶƵůƵƐŝƐĂƉƉƌŽǀĞĚƚŽŝŶĐƌĞĂƐĞŇŽǁƌĂƚĞĂŶĚŝŵƉƌŽǀĞ
ƵŶůŽĂĚŝŶŐĐĂƉĂďŝůŝƚLJ͘ƉƌŽĚƵĐƟŽŶWĂĐŬĞƌǁŝůůŶŽƚďĞƌĞƋƵŝƌĞĚŽŶƚŚĞϮ-3/8" velocity string.
4. ^ŶƵďďŝŶŐĞƋƵŝƉŵĞŶƚ͕ƉĞƌƐŽŶŶĞůĂŶĚŽƉĞƌĂƟŽŶƚŽďĞĐŽŵƉůŝĂŶƚǁŝƚŚĂŶĂĚŝĂŶ/ZWϭϱ͘ ůů
“must” and “shall͟ƐƚĂƚĞŵĞŶƚƐĂƐĚĞƐĐƌŝďĞĚŝŶ/ZWϭϱ͘Ϭ͘ϳƐŚĂůůďĞĂĚŚĞƌĞĚƚŽƵŶůĞƐƐĂƉƉƌŽǀĂůŝƐ
ŽďƚĂŝŶĞĚĨƌŽŵK'ƚŽĚĞǀŝĂƚĞĨƌŽŵƚŚĞƐĞƐƚĂƚĞŵĞŶƚƐ͘/ĨƚŚĞƌƵůĞƐŝŶ/ZWϭϱĐŽŶŇŝĐƚǁŝƚŚ
K'ƌĞŐƵůĂƟŽŶƐ͕K'ƌĞŐƵůĂƟŽŶƐǁŝůůĂƉƉůLJƵŶůĞƐƐK'ǀĂƌŝĂŶĐĞŽƌǁĂŝǀĞƌŝƐŐƌĂŶƚĞĚ.
5. WƌŝŽƌƚŽƌŝŐŐŝŶŐƵƉŽŶƚŚĞǁĞůů͕,ŝůĐŽƌƉŵƵƐƚƉƌĞƐĞŶƚĂƉůĂŶƚŚĂƚŝƐĂĐĐĞƉƚĂďůĞƚŽƚŚĞK'͕
ĚĞŵŽŶƐƚƌĂƟŶŐŚŽǁƚŚĞƌƵůĞƐŽĨ/ZWϭϱǁŝůůďĞŝŵƉůĞŵĞŶƚĞĚ͘
6. SnubbiŶŐĐĂůĐƵůĂƟŽŶƐƚŽďĞďĂƐĞĚŽŶDW^W͘
7. tĞůůĐŽŶƚƌŽůƌĞŐƵůĂƟŽŶƐϮϬϮϱ͘ϮϴϱĨŽƌƌŽƚĂƌLJĚƌŝůůŝŶŐƌŝŐŽƉĞƌĂƟŽŶƐĂƉƉůLJ͘
8. ĞƚĂŝůĞĚƚƵďŝŶŐĚĞƉůŽLJŵĞŶƚƉƌŽĐĞĚƵƌĞƚŽďĞƐƵďŵŝƩĞĚĂŶĚĂƉƉƌŽǀĞĚďLJK'ƉƌŝŽƌƚŽ
deployment.
9. /ĨŶŽƚǁŽƌŬŝŶŐŽŶϮϰ-ŚŽƵƌĐŽŶƟŶƵŽƵƐŽƉĞƌĂƟŽŶĂůƐĐŚĞĚƵůĞ͕ƐŶƵďďŝŶŐƐƚƌŝŶŐŵƵƐƚďĞƌĞŵŽǀĞĚ
ĨƌŽŵƚŚĞŚŽůĞŽƌŚƵŶŐŽīin a pipe-ŚĞĂǀLJĐŽŶĚŝƟŽŶ͕ǁŝƚŚƚƌĞĞǀĂůǀĞĂŶĚďůŝŶĚƌĂŵƐĐůŽƐĞĚďĞĨŽƌĞ
ƐŚƵƫŶŐĚŽǁŶĨŽƌƚŚĞŶŝŐŚƚ͘ ŶŝŐŚƚǁĂƚĐŚŵĂŶƐŚĂůůďĞŽŶůŽĐĂƟŽŶƚŽŵŽŶŝƚŽƌƚŚĞǁĞůů͘
10. Well site supervisors shall have ĂĐůĞĂƌƵŶĚĞƌƐƚĂŶĚŝŶŐŽĨƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨ/ZWϭϱ͘ϱ͘Ϯ͕ĂŶĚ
have an ĂǁĂƌĞŶĞƐƐ ŽĨƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐof /ZWϭϱ͘ ŽĐƵŵĞŶƚĞĚĐŽŶĮƌŵĂƟŽŶŽĨƵŶĚĞƌƐƚĂŶĚŝŶŐ
ĂŶĚĂǁĂƌĞŶĞƐƐ ƚŽďĞĂǀĂŝůĂďůĞƵƉŽŶƌĞƋƵĞƐƚ͘
11. Prior to ƌŝŐŐŝŶŐƵƉŽŶƚŚĞǁĞůů, provide evidence ƚŽK' of:
a. WĞůůŚĞĂĚΘƐŶƵďďŝŶŐƐƚĂĐŬƐƚĂďŝůŝnjĂƟŽŶĚĞƐŝŐŶƉĞƌ/ZWϭϱ͘ϰ͘ϭ͘ϮƉƌŝŽƌƚŽƌŝŐŐŝŶŐƵƉŽŶƚŚĞ
ǁĞůů͘
b. Well-ƐƉĞĐŝĮĐ,ĂnjĂƌĚƐƐĞƐƐŵĞŶƚƉĞƌ/ZWϭϱ͘ϲ.
12. WƌŝŽƌƚŽĞŶƚĞƌŝŶŐƚŚĞǁĞůůƚŽƉĞƌĨŽƌŵƐŶƵďďŝŶŐŽƉĞƌĂƟŽŶƐ͕ƉƌŽǀŝĚĞĞǀŝĚĞŶĐĞŽĨEmergency
Egress System in place ƉĞƌ/ZWϭϱ͘ϴ͘ϯ.
Well Prognosis
Well Name: BRU 222-34 API Number: 50-283-20186-00-00
Current Status: Gas Producer Permit to Drill Number: 222-039
First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C)
Second Call Engineer: Chad Helgeson (907) 777-8405 (O)
Maximum Expected BHP: 2394 psi @ 5443’ TVD (0.44 psi/ft gradient to deepest open perf)
Max. Potential Surface Pressure: 1850 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: Online gas producer @ 2000 mcfd, 15 bwpd @ 281 psi FTP
Brief Well Summary:
Drilled & completed in 2022, BRU 222-34 is an online producer in the Beluga River Undefined Gas Pool. The
well began struggling to stay unloaded in late June 2023. The well is currently able to flow just above the
unload rate for 4-1/2” tubing, however it requires multiple soap drops per day to assist in unloading.
Objective:
The objective of this sundry is to install in a 2-3/8” velocity string without pumping fluids on the sands by using
a hydraulic snubbing unit.
Snubbing Detail:
Prior to snubbing an additional tubing hanger will be flanged up with a gate valve above it to isolate while NU
BOPs. While snubbing, the tubing will be isolated from below with a pump out plug which holds pressure from
below and a PX plug set in set in a X-nipple. The tubing will be snubbed using traveling and stationary inverted
slips, through the snubbing annular, with the 2-3/8” snubbing rams used as needed to deploy the tubing
hanger. The extra gate valve will then be removed prior to NU tree for production.
Production:
Flow will initially be up the 2-3/8” x 4-1/2” annulus with water being unloaded as necessary up the 2-3/8”
tubing. The goal is to reduce slugging events and flatten production as this well continues to decline out.
History:
Nov 2022 Initial perforations from 5137’ – 5617’ MD (4793’ – 5263’ TVD)
Jun 2023 Perforated multiple Beluga sands from 4693’ – 5801’ MD (4359’ – 5443’ TVD)
10/03/23 1.75 DDB to 7004’, log PT survey
Pre-Rig:
1. Set 4’’ TWC in tubing hanger with lubricator
2. Nipple down tree and tree adapter
3. Re-route control line thru tubing head view port and terminate.
4. Nipple up 11 5M x 7 1/16 5M tubing head and test void to 5000psi
5. Nipple up 7 1/16 5M full opening gate valve and tree cap and test to 5000psi against TWC
6. Pull TWC with lubricator, shut in gate valve, and prep for install of the snubbing unit
Well Prognosis
Snubbing Rig:
1. Review all COAs, provide 48hrs notice of BOP testing
2. MIRU PESI snubbing unit (Snubbing International, Alberta, CA: DBA PESI)
3. NU 5k BOPs above existing 7-1/16” gate valve
4. Test primary BOPs to 3000 psi (2-3/8” pipe rams / blind-shear rams / annular)
5. Test stripping BOPs to 3000 psi (dual 2-3/8” rams, annular)
6. MU below completion components:
a. Pump out plug sub with plug installed (holds pressure from below)
b. 10’ pup
c. X-nipple with PX plug (tested from below)
d. 5’ pup / handling joint
7. With the above completion below the stripping BOP (above the closed gate valve) close stripping
annular on 2-3/8” handling joint
8. Stab/MU full opening safety valve in open position
9. Open gate valve, equalize pressure, confirm no flow from the tubing
10. Remove full opening safety valve
11. Snub 2-3/8” tubing thru stripping annular to ~5700’
a. Expected SITP to snub against = 700 psi
b. Cross-sectional area of 2-3/8” tubing = 4.4 in2 x 700 psi = 3080 lbs upward force
c. 3080 lbs / 4.6 lb/ft = 669 feet of 2-3/8” tubing to run before being pipe heavy
12. Close lower stripping rams, MU tubing hanger w TWC installed
13. Close stripping annular, open lower rams
14. Land tubing hanger, RILDs
15. Close blind rams, test TWC & hanger seals from above through kill line
16. ND BOPs, ND 7-1/16” gate valve
17. NU tubing head adapter and tree, test same
18. Pull TWC from tubing hanger using lubricator
19. Hand over well to operations
Post Rig
1. Modify flowlines to include choke & SSV on both tubing and annulus flowlines
2. RU slickline, PT lubricator to 3000 psi
3. Pull PX plug
4. RU Nitrogen, pressure up on tubing to over balance with BHP, shear pump out plug
5. Return well to Operations
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
3. Snubbing Unit Diagram
4. BOP diagram – Primary BOPs & Snubbing Rams/Annular
5. Current Wellhead Diagram
6. Proposed Wellhead Diagram
7. Nitrogen SOP
8. Change Form
Recalculate based on actual WHP while snubbing. -bjm
Pump out plug to be tested to 1.3 x MPSP from below. -bjm
_____________________________________________________________________________________
Updated by DMA 07-11-23
SCHEMATIC
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
1
2
PBTD = 7,401’ MD / TVD = 7,024’
TD = 7,489’ MD / TVD = 7,101’
RKB to GL = 18’
4-1/2”
6-3/4”
hole
7-5/8”
9-7/8”
hole
16”
BEL F6
BEL F7
BEL G3
BEL G5
BEL G9
BEL G10
BEL H2
BEL H3
BEL H4
BEL H5
BEL H7
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 2,808’
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.958”2,590’7,486’
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958”Surf 2,597’
JEWELRY DETAIL
No.Depth ID OD Item
1 502’3.958”4.500”Chemical Injection Sub
2 2,597’4.790”5.630”Seal Stem
2,590’4.875”6.540”ZXP Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8"TOC @ Surface (Returns to surface 8/14/22)
4-1/2”Est. TOC @ 4510’ (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL F6 4,693'4,702'4,359'4,368'9'06/28/23 Open
BEL F6 4,707'4,717'4,373'4,383'10'06/28/23 Open
BEL F6 4,740'4,750'4,405'4,415'10'06/28/23 Open
BEL F6 4,759'4,765'4,424'4,429'6'06/28/23 Open
BEL F7 4,825'4,840'4,488'4,503'15'06/28/23 Open
BEL F7 4,844'4,854'4,507'4,516'10'06/28/23 Open
BEL F7 4,935'4,955'4,596'4,615'20'06/27/23 Open
BEL G3 5,137’5,154’4,793’4,810’17’11/22/22 Open
BEL G3 5,163’5,169’4,819’4,825’6’11/22/22 Open
BEL G5 5,193 ‘5,206’4,848’4,861’13’11/22/22 Open
BEL G9 5,360‘5,370’5,010’5,020’10’11/22/22 Open
BEL G10 5,437’5,457’5,087'5,106'20’06/14/23 Open
BEL H2 5,563‘5,583’5,212’5,230’20’11/21/22 Open
BEL H3 5,594’5,600’5,240‘5,246’6’11/21/22 Open
BEL H3 5,611’5,617’5,257’5,263’6’11/21/22 Open
BEL H4 5,639’5,647’5,284'5,292'8’06/14/23 Open
BEL H4 5,650'5,658’5,295'5,303'8’06/14/23 Open
BEL H4 5,668’5,676’5,313'5,320'8’06/14/23 Open
BEL H5 5,696’5,702’5,340'5,346'6’06/14/23 Open
BEL H5 5,710’5,722’5,354'5,365'12’06/13/23 Open
BEL H7 5,791’5,801’5,433'5,443'10’06/13/23 Open
_____________________________________________________________________________________
Updated by DMA 10-16-23
PROPOSED
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
2
1
PBTD = 7,401’ MD / TVD = 7,024’
TD = 7,489’ MD / TVD = 7,101’
RKB to GL = 18’
3
4-1/2”
6-3/4”
hole
7-5/8”
9-7/8”
hole
16”
BEL F6
BEL F7
BEL G3
BEL G5
BEL G9
BEL G10
BEL H2
BEL H3
BEL H4
BEL H5
BEL H7
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 2,808’
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.958”2,590’7,486’
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958”Surf 2,597’
CASING DETAIL
2-7/8”Tubing 6.4 TBD TBD 2.441”Surf ~5700’
JEWELRY DETAIL
No.Depth ID OD Item
1 2,590’4.875”6.540”Seal Stem / ZXP Liner hanger / LTP Assembly
2 ~5,690’4.875”6.540”X nip w PX plug
3 ~5.700’Pump out plug
OPEN HOLE / CEMENT DETAIL
7-5/8"TOC @ Surface (Returns to surface 8/14/22)
4-1/2”Est. TOC @ 4510’ (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL F6 4,693'4,702'4,359'4,368'9'06/28/23 Open
BEL F6 4,707'4,717'4,373'4,383'10'06/28/23 Open
BEL F6 4,740'4,750'4,405'4,415'10'06/28/23 Open
BEL F6 4,759'4,765'4,424'4,429'6'06/28/23 Open
BEL F7 4,825'4,840'4,488'4,503'15'06/28/23 Open
BEL F7 4,844'4,854'4,507'4,516'10'06/28/23 Open
BEL F7 4,935'4,955'4,596'4,615'20'06/27/23 Open
BEL G3 5,137’5,154’4,793’4,810’17’11/22/22 Open
BEL G3 5,163’5,169’4,819’4,825’6’11/22/22 Open
BEL G5 5,193 ‘5,206’4,848’4,861’13’11/22/22 Open
BEL G9 5,360‘5,370’5,010’5,020’10’11/22/22 Open
BEL G10 5,437’5,457’5,087'5,106'20’06/14/23 Open
BEL H2 5,563‘5,583’5,212’5,230’20’11/21/22 Open
BEL H3 5,594’5,600’5,240‘5,246’6’11/21/22 Open
BEL H3 5,611’5,617’5,257’5,263’6’11/21/22 Open
BEL H4 5,639’5,647’5,284'5,292'8’06/14/23 Open
BEL H4 5,650'5,658’5,295'5,303'8’06/14/23 Open
BEL H4 5,668’5,676’5,313'5,320'8’06/14/23 Open
BEL H5 5,696’5,702’5,340'5,346'6’06/14/23 Open
BEL H5 5,710’5,722’5,354'5,365'12’06/13/23 Open
BEL H7 5,791’5,801’5,433'5,443'10’06/13/23 Open
Superseded
5000 psi BOP stack -bjm
Beluga River Unit
BRU 222-34
07/30/2022
Valve, Master, CIW-FLS,
4 1/16 5M FE, HWO,
EE trim
Valve, Upper master,
CIW-FLS,
4 1/16 5M FE, HWO, EE trim
Valve, Swab, CIW-FLS
4 1/16 5M FE, HWO,
EE trim
Valve, Wing, CIW-FC,
3 1/8 5M FE, HWO,
EE trim
BHTA, Bowen, 4 1/16 5M FE
x 7'’ Bowen quick union top
16'’
7 5/8'’
4 ½’’
Starting head, Cactus C-29L,
16 3/4 3M x 16 SOW, w/ 2- 2
1/16 5M SSO
Tubing head, Cactus C-29L-
HPS, 16 3/4 3M x 11 5M, w/
2- 2 1/16 5M SSO
BRU 222-34
16 x 7 5/8 x 4 ½
Tubing hanger, Cactus-EN-
CCL, 4 ½ EUE 8rd lift and
susp x w 6 ¼ od ext neck, 4'’
type H BPV profile, DD-NL
material
Valve, Wing, SSV, WKM-M,
3 1/8 5M FE, w/ 15'’ Hydraulic
operator
Adapter, Cactus-EN-6.25'’,
11 5M stdd x 4 1/16 5M stdd
top, w/ 2- 1'’npt control line
exits
Beluga River Unit
BRU 222-34
10/04/2023
Valve, Master, WKM-M,
2 1/16 5M FE, HWO,
DD trim
Valve, Upper master,
WKM-M,
2 1/16 5M FE, HWO, DD trim
Valve, Swab, WKM-M
2 1/16 5M FE, HWO,
DD trim
BHTA, Otis, 2 1/16 5M FE x
3'’ Bowen quick union top
Tubing head, Cactus C-HPS,
11 5M x 7 1/16 5M, w/ 2-
2 1/16 5M SSO
16'’
7 5/8'’
4 ½’’
Starting head, Cactus C-29L,
16 3/4 3M x 16 SOW, w/ 2- 2
1/16 5M SSO
Tubing head, Cactus C-29L-
HPS, 16 3/4 3M x 11 5M, w/
2- 2 1/16 5M SSO
2 3/8'’
Tubing hanger, Cactus-EN-CL,
7 x 2 3/8 EUE 8rd lift and
susp, w/ 2'’ type H BPV
profile
Adapter, Cactus-EN, 7 1/16
5M Stdd x 2 1/16 5M
prepped for 5 ½ extended
neck hanger
BRU 222-34
16 x 7 5/8 x 4 ½ x 2 3/8
New exit point for
CIM due to removing tree
out 1'’ view port in wellhead
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
Hilcorp Alaska, LLC
Hilcorp Alaska, LLC
Changes to Approved Rig Work Over Sundry Procedure
Subject: Changes to Approved Sundry Procedure for Well BRU 222-34 (PTD 222-039)
Sundry #: XXX-XXX
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 rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.
Sec Page Date Procedure Change New 403
Required?
Y / N
HAK
Prepared
By
(Initials)
HAK
Approved
By
(Initials)
AOGCC Written
Approval Received
(Person and Date)
Approval:
Asset Team Operations Manager Date
Prepared:
First Call Operations Engineer Date
Beluga River Unit
BRU 222-34—Snubbing unit stackup
10/23/2023
Tubing head, Cactus C-HPS,
11 5M x 7 1/16 5M, w/ 2-
2 1/16 5M SSO
16'’
7 5/8'’
4 ½’’
Starting head, Cactus C-29L,
16 3/4 3M x 16 SOW, w/ 2- 2
1/16 5M SSO
Tubing head, Cactus C-29L-
HPS, 16 3/4 3M x 11 5M, w/
2- 2 1/16 5M SSO
New exit point for
CIM due to removing tree
out 1'’ view port in wellhead
7 1/16 5M gate valve w/ full
drift bore f/ 7'’ nom tubing
hanger
BOPs Above
!!
!!!
Pri
m
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r
y
A
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r
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i
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w
a
y
SEC. 27
SEC. 34
13N10W
BEL
U
G
A
H
WY
Beluga
River Unit
COOK INLET
REGION INC
F PAD
BRU P&S YARD
BRU 222-34_SHL
151°2'20"W151°2'30"W151°2'40"W151°2'50"W
61
°
1
0
'
5
5
"
N
61
°
1
0
'
5
5
"
N
61
°
1
0
'
5
0
"
N
61
°
1
0
'
5
0
"
N
61
°
1
0
'
4
5
"
N
61
°
1
0
'
4
5
"
N
61
°
1
0
'
4
0
"
N
61
°
1
0
'
4
0
"
N
61
°
1
0
'
3
5
"
N
61
°
1
0
'
3
5
"
N
61
°
1
0
'
3
0
"
N
61
°
1
0
'
3
0
"
N
±
0 100 200 300 400
Feet
1 inch = 200 feet @ 11x17 Page Size
Map Date: 3/18/2022
Do
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P
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\
B
R
U
\
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\
B
R
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_
2
2
2
-
3
4
_
6
6
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t
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u
f
f
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_
1
1
x
1
7
P
_
v
0
2
.
m
x
d
BRU 222-34 (wp08) Surface Hole Location
BRU F PAD
660 ft Buffer from Well Surface Hole Location
Legend
!Well Surface Hole Location (SHL)
Existing Gas Pipelines
660 ft Radius Buffer from Well SHL
KPB Parcels
Cook Inlet Oil and Gas Unit
Aerial Imagery flown by QSI
for Hilcorp Alaska LLC
May 2021
_____________________________________________________________________________________
Updated by JMF 10-23-23
PROPOSED
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
2
1
PBTD = 7,401’ MD / TVD = 7,024’
TD = 7,489’ MD / TVD = 7,101’
RKB to GL = 18’
3
4-1/2”
6-3/4”
hole
7-5/8”
9-7/8”
hole
16”
BEL F6
BEL F7
BEL G3
BEL G5
BEL G9
BEL G10
BEL H2
BEL H3
BEL H4
BEL H5
BEL H7
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor –Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 2,808’
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.958”2,590’7,486’
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958”Surf 2,597’
CASING DETAIL
2-3/8”Tubing 4.6 TBD TBD 1.995”Surf ~5700’
JEWELRY DETAIL
No. Depth ID OD Item
1 2,590’4.875”6.540”Seal Stem / ZXP Liner hanger / LTP Assembly
2 ~5,690’4.875”6.540”X nip w PX plug
3 ~5.700’Pump out plug
OPEN HOLE / CEMENT DETAIL
7-5/8"TOC @ Surface (Returns to surface 8/14/22)
4-1/2”Est. TOC @ 4510’ (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL F6 4,693'4,702'4,359'4,368'9'06/28/23 Open
BEL F6 4,707'4,717'4,373'4,383'10'06/28/23 Open
BEL F6 4,740'4,750'4,405'4,415'10'06/28/23 Open
BEL F6 4,759'4,765'4,424'4,429'6'06/28/23 Open
BEL F7 4,825'4,840'4,488'4,503'15'06/28/23 Open
BEL F7 4,844'4,854'4,507'4,516'10'06/28/23 Open
BEL F7 4,935'4,955'4,596'4,615'20'06/27/23 Open
BEL G3 5,137’5,154’4,793’4,810’17’11/22/22 Open
BEL G3 5,163’5,169’4,819’4,825’6’11/22/22 Open
BEL G5 5,193 ‘5,206’4,848’4,861’13’11/22/22 Open
BEL G9 5,360‘5,370’5,010’5,020’10’11/22/22 Open
BEL G10 5,437’5,457’5,087'5,106'20’06/14/23 Open
BEL H2 5,563‘5,583’5,212’5,230’20’11/21/22 Open
BEL H3 5,594’5,600’5,240‘5,246’6’11/21/22 Open
BEL H3 5,611’5,617’5,257’5,263’6’11/21/22 Open
BEL H4 5,639’5,647’5,284'5,292'8’06/14/23 Open
BEL H4 5,650'5,658’5,295'5,303'8’06/14/23 Open
BEL H4 5,668’5,676’5,313'5,320'8’06/14/23 Open
BEL H5 5,696’5,702’5,340'5,346'6’06/14/23 Open
BEL H5 5,710’5,722’5,354'5,365'12’06/13/23 Open
BEL H7 5,791’5,801’5,433'5,443'10’06/13/23 Open
1
Christianson, Grace K (OGC)
From:Jacob Flora <Jake.Flora@hilcorp.com>
Sent:Monday, October 23, 2023 12:46 PM
To:McLellan, Bryan J (OGC)
Subject:RE: [EXTERNAL] BRU 222-34 (PTD 323-573) sundry application questions
Attachments:BRU_222-34_660ft_Buffer_11x17P_v02.pdf; BRU 222-34 Proposed 10-23-23.pdf; BRU 222-34
proposed while snubbing wellhead.pdf
HiBryan,
1. Thetreecapontopthevalvethathas½npttestportinit.Wewillopenthegatevalveandbodytestagainst
theTWC.Thisteststhenewtubingheadandvalve.ThenpulltheTWC,closevalve,removethetreecap
(negaƟvetestonvalve),andinstallBOPstackandsnubbingunit.
2. UpdatedproposedWBDaƩachedshowing2Ͳ3/8”(aƩached)
3. Wellheaddiagram“whilesnubbing”showingtheaddiƟonalgatevalve(aƩached)
4. 660’buīermap(aƩached)
PleaseletmeknowifyouneedanythingelseasyoureviewthesundryͲ
Thanks,
Jake
From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>
Sent:Monday,October23,20239:46AM
To:JacobFlora<Jake.Flora@hilcorp.com>
Subject:[EXTERNAL]BRU222Ͳ34(PTD323Ͳ573)sundryapplicationquestions
Jake,
AfewquesƟonsaboutthesundry.
1. OnStep#5,howwillyoupressuretestthe7”gatevalveagainsttheTWC?Isthereatestportbetweenthetwo?
2. Proposeddiagramshows2Ͳ7/8”tubingtoberun.Textinsundrysays2Ͳ3/8”willberun.Pleasesendcorrected
diagramortext.
3. SubmitwellheaddiagramshowingstackupduringsnubbingoperaƟons.
4. Submitmapwith660’radiusaroundwellheadforSSSVdeterminaƟon.
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
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1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________
Development Exploratory
3. Address: Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,489 feet N/A feet
true vertical 7,101 feet N/A feet
Effective Depth measured 7,401 feet N/A feet
true vertical 7,024 feet N/A feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth) N/A N/A N/A N/A
Packers and SSSV (type, measured and true vertical depth) Liner Top Pkr; N/A 2,590' MD 2,354' TVD N/A; N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
7,500psi
2,980psi
6,880psi
8,430psi
2,808' 2,549'
Burst Collapse
1,410psi
4,790psi
Production
Liner
4,896'
2,597'
Casing
Structural
7,096'
4-1/2"
7,486'
2,597' 2,360'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
2,808'
measured
TVD
8,430psi
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
222-039
50-283-20186-00-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
FEDA029657
Beluga River / Sterling-Beluga Gas
Beluga River Unit (BRU) 222-34
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
120'
3 703545
0 24515
290
Jake Flora, Operations Engineer
323-135
Sr Pet Eng:
7,500psi
Sr Pet Geo: Sr Res Eng:
WINJ WAG
1352
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
jake.flora@hilcorp.com
907-777-8442
N/A
p
k
ft
t
Fra
O
s O
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 8:20 am, Jul 28, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.07.26 16:39:40 -
08'00'
Noel Nocas
(4361)
Rig Start Date End Date
6/13/23 6/29/23
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
BRU 222-34 50-283-20186-00-00 222-039
06/13/2023 - Tuesday
Begin rig up of eline unit and equipment. Had some issues getting soap stick system off well. Had to rig up scaffolding to
reach top of WLV's due to manlift being used by SLine
PT 300 low and 2500 high.
Make up gun, stab on well. RIH w/ (Gun#1)
10' x 2-7/8" perf gun (GEO chrgs - 15 gram - 6 SPF - 60 deg phasing). Pulled tie in pass and sent to town. Town approves
tie in pass on depth
Shot interval 5791' - 5801' (CCL to TS = 12.9 ) (CCL stop depth = 5778.1') ****
Good indication of firing. POOH & confirmed all shots fired
Tbg psi pre shot = 255/ 0 / 0
Tbg psi post shot = 255 / 0 / 0. RIH w/ (Gun#2)
12' x 2-7/8" perf gun (GEO chrgs - 15 gram - 6 SPF - 60 deg phasing). Pulled tie in pass and sent to town. Town approves
tie in pass on depth
Shot interval 5710' - 5722' (CCL to TS =10.9') (CCL stop depth = 5699.1') ****
Good indication of firing. POOH & confirmed all shots fired
Tbg psi pre shot = 253 / 0 / 0
Tbg psi post shot = 253 / 0 / 0. Laid down equipment for the night. Will return in AM to shoot remaining 51'
Rig Start Date End Date
6/13/23 6/29/23
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
BRU 222-34 50-283-20186-00-00 222-039
06/14/2023 - Wednesday
Attend morning meeting w/ Beluga team. Fill out permit. Head to location and start rig up of equipment
PT 300 low 2500# high
Arm gun and stab back on to well. RIH w/ (Gun#3)
6' x 2-7/8" perf gun (GEO RZR chrgs - 15 gram - 6 SPF - 60 deg phasing). Pulled tie in pass and sent to town. Town
approves tie in pass on depth
Shot interval 5696' - 5702 (Beluga H5 sands) (CCL to TS =16.1') (CCL stop depth = 5679.9') ***only blast debris in
bullnose***
Good indication of firing. POOH & confirmed all shots fired
Tbg psi pre shot = 258 / 0 / 0
Tbg psi post shot = 258 / 0 / 0. RIH w/ (Gun#4)
8' x 2.75" perf gun (GEO RZR chrgs - 15 gram - 6 SPF - 60 deg phasing). Pulled tie in pass and sent to town. Town
approves tie in pass on depth
Shot interval 5668' - 5676' (Beluga H4 sands) (CCL to TS =10.9') (CCL stop depth = 5657.1') ***only blast debris in
bullnose***
Good indication of firing. POOH & confirmed all shots fired
Tbg psi pre shot = 257 / 0 / 0
Tbg psi post shot = 257 / 0 / 0. RIH w/ (Gun#5)
8' x 2.75" perf gun (GEO RZR chrgs - 15 gram - 6 SPF - 60 deg phasing). Pulled tie in pass and sent to town. Town
approves tie in pass on depth
Shot interval 5650' - 5658' (Beluga H4 sands) (CCL to TS = 10.9') (CCL stop depth = 5639.1') ***only blast debris in
bullnose***
Good indication of firing. POOH & confirmed all shots fired
Tbg psi pre shot = 258 / 0 / 0
Tbg psi post shot = 258 / 0 / 0. RIH w/ (Gun#6)
8' x 2.75" perf gun (GEO RZR chrgs - 15 gram - 6 SPF - 60 deg phasing). Pulled tie in pass and sent to town. Town
approves tie in pass on depth
Rig Start Date End Date
6/13/23 6/29/23
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
BRU 222-34 50-283-20186-00-00 222-039
06/27/2023 - Tuesday
Air transport AKE-line crew and equipment from Kenai to Beluga River. Check in, obtain PTW and hold PJSM. Move E-line
units to F-pad and RU.
MU lubricator and 2-7/8" x 20' perf gun. (6spf - 60D phased gun) 9' CCL to top shot.
Move to well and PT 250psi / 2500psi. Pass. Open swab. Well flowing at 26 psi / 1.43 MMCFD. RIH to 5900' past lowest
perf at 5801'.
Run correlation tie-in pass from 5200' - 4500'. Send log to Geo. Confirmed tie-in log is on depth.
Position gun at 4926' (CCL depth) and shoot the Beluga F7 interval 4935'-4955'. Good shot indication. POOH.
Initial 265 psi / 1.43 mmcfd
5 min: 267 psi / 1.90 mmcfd
10 min: 274 psi / 2.16 mmcfd
15 min.: 273 psi / 2.27 mmcfd. OOH. All shots fired. Nightcap and secure well.
Continue flowing and monitoring well. Return to camp.
272.6 psi / 2.95 mmcfd
Plan forward to perforate four more Beluga F-6 intervals
Shot interval 5639' - 5647'(Beluga H4 sands) (CCL to TS = 10.9') (CCL stop depth = 5628.1')
Good indication of firing. POOH & confirmed all shots fired
Tbg psi pre shot = 258 / 0 / 0
Tbg psi post shot = 258 / 0 / 0. RIH w/ (Gun#7)
20' x 2-7/8" perf gun (GEO RZR chrgs - 15 gram - 6 SPF - 60 deg phasing). Pulled tie in pass and sent to town. Town
approves tie in pass on depthShot interval 5437' - 5457' (Beluga G10 sands) (CCL to TS =9.1') (CCL stop depth = 5427.9'')
****
Good indication of firing. POOH & confirmed all shots fired
Tbg psi pre shot = 258 / 0 / 0
Tbg psi post shot = 258 / 0 / 0. Begin rig down of equipment and stage on storage pad. Off load equipment in connex
Rig down complete. Depart Beluga on Otter and head to Kenai
Rig Start Date End Date
6/13/23 6/29/23
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
BRU 222-34 50-283-20186-00-00 222-039
06/28/2023 - Wednesday
AK E-line attend morning production meeting. Obtain PTW, hold PJSM and travel to location. FTP = 270 psi / 2.00 mmcfd
RU E-line, lubricator and MU Gun Gamma Ray/CCL and Gun #2 - 2-7/8" x 10' (6spf/60D) perf gun loaded with
GeoDynamics 15 gm charges. CCL to top shot 9'.
PU and stab onto wellhead. Open swab and RIH. Log correlation pass, send to Geo, confirm on-depth. Position gun at
4835' (CCL depth) and shoot the F7 interval 4844'-4854'. POOH
Initial: 270 psi / 2.00 mmcfd 5min: 272 psi / 2.75 mmcfd 10 min.: 272 psi / 2.71 mmcfd 15 min.: 272 psi / 2.50 mmcfd
OOH. All shots fired (some formation sand on tools).
MU Gun #3 - 2-7/8" x 15' gun (CCL to top shot - 14'). Open swab, RIH. Log correlation pass, send to Geo, confirmed on-
depth. Position gun at 4811' (CCL depth) and shoot the F7 interval 4825' - 4840'. POOH.
Initial: 273 psi / 3.63 mmcfd 5 min.: 274 psi / 3.55 mmcfd 10 min.: 273 psi / 3.51 mmcfd 15 min.: 274 psi / 4.00 mmcfd .7
bbls/H2O
OOH. All shots fired.
MU Gun #4 - 2-3/4" x 6' gun (9' CCL - T.S.). Open swab, RIH. Log correlation pass, send to Geo, confirmed on depth.
Position gun at 4750' (CCL depth) and shoot F6 interval 4759' - 4765'. POOH.
Initial: 274 psi / 3.6 mmcfd 5 min.: 278 psi / 4.93 mmcfd 10 min.: 276 psi / 4.7 mmcfd 15 min.: 276 psi / 4.7 mmcfd .9
bbls / H2O
OOH. All shots fired.
MU Gun #5 - 2-7/8" x 10' gun (9' CCL - T.S.). Open swab, RIH. Log correlation pass. Gun stuck in perforations at 4830'.
Worked tools for 10 min. and came free. Rerun correlation pass and send to Geo. Confirmed on-depth.
Position gun at 4731' (CCL) and shoot F6 interval 4740' - 4750'. POOH.
Initial: 275 psi / 4.50 mmcfd 5 min.: 274 psi / 4.60 mmcfd 10 min.: 274 psi / 4.47 mmcfd 15 min.: 274 psi / 4.30 mmcfd
OOH. All shots fired. Rehead rope socket. MU Gun #6 - 2-3/4" x 10' gun (9' CCL - T.S.).
Open swab, RIH. Log correlation pass, send to Geo, confirmed on-depth. Position gun at 4698' (CCL) and shoot the F6
interval 4707' - 4717'. POOH.
Initial: 278 psi / 4.22 mmcfd 5 min.: 278 psi / 4.25 mmcfd 10 min.: 278 psi / 4.10 mmcfd 15 min. 279 psi / 4.9 mmcfd
OOH. All shots fired.
MU Gun #7 - 2-7/8" x 9'gun (10' CCL - T.S.). Open swab, RIH. Log correlation pass, send to Geo, confirmed on-depth.
Position gun at 4683' (CCL) and shoot the F6 interval 4693' - 4702'. POOH.
Initial: 279 psi / 4.50 mmcfd 5 min.: 280 psi / 4.01 mmcfd 10 min.: 281 psi / 4.44 mmcfd 15 min.: 281psi / 4.45 mmcfd
OOH. All shots fired,. Perforating complete.
Secure well, rig back and SDFN. Prep junk basket/gauge ring and PL tools to run production survey next day.
Rig Start Date End Date
6/13/23 6/29/23
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
BRU 222-34 50-283-20186-00-00 222-039
06/29/2023 - Thursday
AK E-line attend morning production meeting. Obtain PTW, hold PJSM and travel to F pad. RU wireline and MU wt. bars,
CCL and junk basket with 3.76" OD gauge ring. PU with lubricator and stab on wellhead. FTP - 279 psi / 4.30 mmcfd
Open swab and RIH. Run through all open perforations and tag PBTD at 7190'. Sticky on bottom. POOH.
Junk basket collected perf debris and small cement pieces.
MU PL tool string with centralizers, GR/CCL- Press/Temp, in-line spinner, water hold up sensor and full bore spinner.
Open swab and RIH at 120 fpm. At 4600' start 40 fpm down pass. End down pass at 5900'. Start 40 fpm up pass.
Repeat dynamic passes at 80 and 120 fpm. After last pass run down to 5819' to start 5 min. station stops. (Bottom perf
at 5801').
Continue moving uphole with 17 station stops placed between perf intervals. End last stop at 4650' (above last perf at
4693'). POOH. OOH. Break down PL tool string swing lubricator and WLV's to 244-27 well.
Secure well. Perforating and log survey complete.
_____________________________________________________________________________________
Updated by DMA 07-11-23
SCHEMATIC
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
1
2
PBTD = 7,401 MD / TVD = 7,024
TD = 7,489 MD / TVD = 7,101
RKB to GL = 18
4-1/2
6-3/4
hole
7-5/8
9-7/8
hole
16
BEL F6
BEL F7
BEL G3
BEL G5
BEL G9
BEL G10
BEL H2
BEL H3
BEL H4
BEL H5
BEL H7
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16Conductor Driven
to Set Depth 84 X-56 Weld 15.01 Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875Surf 2,808
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.9582,5907,486
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958Surf 2,597
JEWELRY DETAIL
No. Depth ID OD Item
1 5023.9584.500Chemical Injection Sub
2 2,5974.7905.630Seal Stem
2,5904.8756.540ZXP Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (Returns to surface 8/14/22)
4-1/2 Est. TOC @ 4510 (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL F6 4,693'4,702'4,359'4,368'9'06/28/23 Open
BEL F6 4,707'4,717'4,373'4,383'10'06/28/23 Open
BEL F6 4,740'4,750'4,405'4,415'10'06/28/23 Open
BEL F6 4,759'4,765'4,424'4,429'6'06/28/23 Open
BEL F7 4,825'4,840'4,488'4,503'15'06/28/23 Open
BEL F7 4,844'4,854'4,507'4,516'10'06/28/23 Open
BEL F7 4,935'4,955'4,596'4,615'20'06/27/23 Open
BEL G3 5,1375,1544,7934,8101711/22/22 Open
BEL G3 5,163 5,169 4,819 4,825 611/22/22 Open
BEL G5 5,193 5,206 4,848 4,861 1311/22/22 Open
BEL G9 5,360 5,370 5,010 5,020 1011/22/22 Open
BEL G10 5,437 5,4575,087' 5,106'2006/14/23 Open
BEL H2 5,563 5,583 5,212 5,230 2011/21/22 Open
BEL H3 5,594 5,600 5,240 5,246 611/21/22 Open
BEL H3 5,611 5,617 5,257 5,263 611/21/22 Open
BEL H4 5,639 5,6475,284' 5,292'806/14/23 Open
BEL H4 5,650'5,6585,295' 5,303'806/14/23 Open
BEL H4 5,668 5,6765,313' 5,320'806/14/23 Open
BEL H5 5,696 5,7025,340' 5,346'606/14/23 Open
BEL H5 5,710 5,7225,354' 5,365'1206/13/23 Open
BEL H7 5,791 5,8015,433' 5,443'1006/13/23 Open
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 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: 07/25/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230725
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BRU 222-34 50283201860000 222039 6/29/2023 AK E-LINE Perf-ProductionProfile
BRU 223-34 50283201880000 223041 7/14/2023 AK E-LINE CBL/Perf
BRU 223-34 50283201880000 223041 7/16/2023 AK E-LINE Perf
BRU 244-27 50283201850000 222038 6/30/2023 AK E-LINE Perf
END 1-01 50029218010000 188037 7/9/2023 AK E-LINE Plug/Cement
END DIU 1-01 50029218010000 188037 7/7/2023 AK E-LINE Cross-Flow-Detect
GO 8 50133206510000 215077 7/13/2023 AK E-LINE Perf
KBU 33-06X 50133205290000 203183 7/18/2023 AK E-LINE GPT/Patch
PBU F-29B 50029216270200 211147 7/8/2023 AK E-LINE CIBP
Please include current contact information if different from above.
T37872
T37873
T37873
T37874
T37875
T37875
T37876
T37877
T37878
BRU 222-34 50283201860000 222039 6/29/2023 AK E-LINE Perf-ProductionProfile
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2023.07.25
12:04:00 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 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: 07/10/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230422
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BRU 214-26 50283200830000 212050 6/2/2023 AK E-LINE PPROF
BRU 222-34 50283201860000 222039 6/14/2023 AK E-LINE Perf
BRU 244-27 50283201850000 222038 6/13/2023 AK E-LINE Perf
KBU 33-06X 50133205290000 203183 6/17/2023 AK E-LINE Patch
Paxton 12 50133207100000 223014 6/7/2023 AK E-LINE Perf
PBU 18-29C 50029223160300 209055 6/2/2023 AK E-LINE CBL
Pearl 10 50133207110000 223028 6/6/2023 AK E-LINE Perf
Pearl 11 50133207120000 223032 6/8/2023 AK E-LINE Perf
Please include current contact information if different from above.
PTD: 190-042 T37810
T37811
T37812
T37813
T37814
T37815
T37816
T37817
BRU 222-34 50283201860000 222039 6/14/2023 AK E-LINE Perf
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.10
13:32:37 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Subject:RE: BRU 222-34 AOGCC 10-403 323-135 PTD 222-039 (request for expanded perf set in approved sundry)
Date:Thursday, June 8, 2023 9:45:00 AM
Attachments:image002.png
image003.png
image004.png
image005.png
Hilcorp has approval to add the additional, amended, perf intervals as part of sundry 323-135. The
shallowest authorized perforation is 4617’ MD.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Wednesday, June 7, 2023 1:06 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: BRU 222-34 AOGCC 10-403 323-135 PTD 222-039 (request for expanded perf set in
approved sundry)
Hello Bryan,
I caught a mistake in this request. This well had losses during the cement job and the logged TOC is
at 4510’. I had incorrectly requested perfs above this to be added to the already open sundry.
Please see amended table below:
Request to add (Amended):
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Thursday, June 1, 2023 11:52 AM
To: bryan.mclellan@alaska.gov
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 222-34 AOGCC 10-403 323-135 PTD 222-039 (request for expanded perf set in
approved sundry)
Hi Bryan,
A similar request. We would like to request additional perfs to be added to the existing open
sundry. They are above, below and within the currently approved perf table.
Please let me know if you need anything additional-
Thanks,
Jake
Currently approved in Open Sundry 323-135
Request to add to Open Sundry (shallower and deeper perf adds)
Maximum Expected BHP: 2927 psi @ 6421’ TVD (Based on 0.456 psi/ft gradient))
Max. Potential Surface Pressure: 2285 psi (Based on 0.1 psi/ft gas gradient to
surface)
a. Frac Calcs: Using 14.5 ppg EMW FIT at surface casing shoe (0.754 psi/ft frac grad)
b. Shallowest Allowable Perf TVD = MPSP/(0.754-0.1) = 2285 psi / 0.654 = 3493‘ TVD
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 responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Jacob Flora
To:McLellan, Bryan J (OGC)
Subject:RE: BRU 222-34 AOGCC 10-403 323-135 PTD 222-039 (request for expanded perf set in approved sundry)
Date:Wednesday, June 7, 2023 1:06:00 PM
Attachments:image003.png
image004.png
image005.png
image006.png
Hello Bryan,
I caught a mistake in this request. This well had losses during the cement job and the logged TOC is
at 4510’. I had incorrectly requested perfs above this to be added to the already open sundry.
Please see amended table below:
Request to add (Amended):
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Thursday, June 1, 2023 11:52 AM
To: bryan.mclellan@alaska.gov
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 222-34 AOGCC 10-403 323-135 PTD 222-039 (request for expanded perf set in
approved sundry)
Hi Bryan,
A similar request. We would like to request additional perfs to be added to the existing open
sundry. They are above, below and within the currently approved perf table.
Please let me know if you need anything additional-
Thanks,
Jake
Currently approved in Open Sundry 323-135
Request to add to Open Sundry (shallower and deeper perf adds)
Maximum Expected BHP: 2927 psi @ 6421’ TVD (Based on 0.456 psi/ft gradient))
Max. Potential Surface Pressure: 2285 psi (Based on 0.1 psi/ft gas gradient to
surface)
a. Frac Calcs: Using 14.5 ppg EMW FIT at surface casing shoe (0.754 psi/ft frac grad)
b. Shallowest Allowable Perf TVD = MPSP/(0.754-0.1) = 2285 psi / 0.654 = 3493‘ TVD
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 responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require a spacing exception?Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
7,489'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner 7,500psi
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
8,430psi7,098'7,486'
8,430psi2,597'2,360'
120'
2,808'
Perforation Depth MD (ft):
4,896'
4-1/2"2,597'
4-1/2"
16"
7-5/8"
120'
2,808'
2,980psi
6,880psi
120'
2,549'
Length Size
Proposed Pools:
TVD Burst
PRESENT WELL CONDITION SUMMARY
7,101'7,401'7,024'~1,789psi N/A
MD
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA029657
222-039
50-283-20186-00-00
Beluga River Sterling-Beluga Gas Same
CO 802
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 222-34
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size:
N/A N/A
March 21, 2023
Liner Top; N/A 2,590' MD/2,354' TVD; N/A
See Schematic See Schematic N/A
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
AOGCC USE ONLY
Jake Flora, Operations Engineer
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
m
n
P
s
t
_
66
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Samantha Carlisle at 1:33 pm, Mar 07, 2023
323-135
Digitally signed by Noel Nocas
(4361)
DN: cn=Noel Nocas (4361),
ou=Users
Date: 2023.03.07 12:15:50 -09'00'
Noel Nocas
(4361)
BJM 3/9/23
x 10-404
MDG 3/8/2023
DSR-3/7/23GCW 03/09/23JLC 3/9/2023
3/9/23
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.03.09 15:59:30
-09'00'
RBDMS JSB 030923
Well Prognosis
Well Name: BRU 222-34 API Number: 50-283-20186-00-00
Current Status: Gas Producer Permit to Drill Number: 222-039
First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M)
Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M)
Maximum Expected BHP: ~2315 psi @ 5263’ TVD (0.44 psi/ft gradient to bottom perf)
Max. Potential Surface Pressure: ~1789 psi (Max expected BHP - gas to surface)
Well Status: Online Producer making 3400 mcfd at 276 psi FTP with 0 bw
Brief Well Summary
BRU 222-34 is a 2022 grass roots producer drilled and completed in the Beluga G-H sands. The objective of this
sundry is to increase productivity by perforating additional Beluga sands.
Notes Regarding Wellbore Condition:
11/22/22 Shot Beluga G-H sands 5137-5617’ MD (4793-5263’ TVD), brought online
Procedure
1. RU E-line, PT lubricator to 2500 psi
2. Perforate Beluga sands from the bottom up within the below interval:
Sand MD Top MD Bottom Total Footage
(MD) TVD Top TVD Bottom
Beluga F6 ±4,693' ±4,702' 9' ±4,359' ±4,368'
Beluga F6 ±4,707' ±4,717' 10' ±4,373' ±4,383'
Beluga F6 ±4,740' ±4,750' 10' ±4,405' ±4,415'
Beluga F6 ±4,759' ±4,765' 6' ±4,423' ±4,429'
Beluga F7 ±4,934' ±4,955' 21' ±4,595' ±4,616'
a) If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
Attachments:
1. As-built Well Schematic
2. Proposed Well Schematic
_____________________________________________________________________________________
Updated By: CJD 1/09/23
SCHEMATIC
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
1
2
PBTD = 7,401’ MD / TVD = 7,024’
TD = 7,489’ MD / TVD = 7,101’
RKB to GL = 18’
4-1/2”
6-3/4”
hole
7-5/8”
9-7/8”
hole
16”
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 2,808’
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.958”2,590’7,486’
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958”Surf 2,597’
JEWELRY DETAIL
No.Depth ID OD Item
1 502’3.958”4.500”Chemical Injection Sub
2 2,597’4.790”5.630”Seal Stem
2,590’4.875”6.540”ZXP Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8"TOC @ Surface (Returns to surface 8/14/22)
4-1/2”Est. TOC @ 4510’ (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top
(MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL G3 5137’5154’ 4793’ 4810’ 17’ 11-22-22 Open
BEL G3 5163’5169’ 4819’ 4825’ 6’ 11-22-22 Open
BEL G5 5193 ‘5206’ 4848’ 4861’ 13’ 11-22-22 Open
BEL G9 5360 ‘5370’ 5010’ 5020’ 10’ 11-22-22 Open
BEL H2 5563 ‘5583’ 5212’ 5230’ 20’ 11-21-22 Open
BEL H3 5594’5600’ 5240 ‘ 5246’ 6’ 11-21-22 Open
BEL H3 5611’5617’ 5257’ 5263’ 6’ 11-21-22 Open
_____________________________________________________________________________________
Updated by DMA 02-21-23
PROPOSED
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
1
2
PBTD = 7,401’ MD / TVD = 7,024’
TD = 7,489’ MD / TVD = 7,101’
RKB to GL = 18’
4-1/2”
6-3/4”
hole
BEL G
9-7/8”
hole
16”
7-5/8”
BEL H
BEL F
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 2,808’
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.958”2,590’7,486’
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958”Surf 2,597’
JEWELRY DETAIL
No.Depth ID OD Item
1 502’3.958”4.500”Chemical Injection Sub
2 2,597’4.790”5.630”Seal Stem
2,590’4.875”6.540”ZXP Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8"TOC @ Surface (Returns to surface 8/14/22)
4-1/2”Est. TOC @ 4510’ (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top
(MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL F6-F7 ±4,693’±4,955’±4,395’±4,616’Proposed TBD
BEL G3 5,137’5,154’4793’4,810’17’11-22-22 Open
BEL G3 5,163’5,169’4819’4,825’6’11-22-22 Open
BEL G5 5,193‘5,206’4848’4,861’13’11-22-22 Open
BEL G9 5,360‘5,370’5010’5,020’10’11-22-22 Open
BEL H2 5,563‘5,583’5212’5,230’20’11-21-22 Open
BEL H3 5,594’5,600’5240‘5,246’6’11-21-22 Open
BEL H3 5,611’5,617’5,257’5,263’6’11-21-22 Open
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Beluga River Field
GL: 83.7' BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" X-56 120'
7-5/8" L-80 2,548'
4-1/2" L-80 7,101'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
00725 0
12/26/2022 24
Flow Tubing
0
4357
N/A43570
N/A
N/A
N/A
7,489' MD / 7,101' TVD
7,401' MD / 7,024' TVD
2113' FNL, 2528' FEL, Sec 34, T13N, R10W, SM, AK
2430' FNL, 2433' FWL, Sec 34, T13N, R10W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6# 2,355'
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
12/2/2022
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
315372
315048
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
BRU 222-34August 27, 2022953' FNL, 1414' FEL, Sec 34, T13N, R10W, SM, AK
102.2'
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2623082
SETTING DEPTH TVD
2622770
TOP HOLE SIZE
Mudlog, LWD (DGR, SP4, CTN, ALD), CBL 9-15-22, Perf, GPT.
Sterling-Beluga Pool
A029657
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
316499 2624231
50-283-20186-00-00August 2, 2022
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
11/21/2022 222-039 / 322-304
N/A
PACKER SET (MD/TVD)
Conductor
9-7/8"
Driven
Surface L - 370 sx / T - 175 sx
Surface
2,808'
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,590' 7,489'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
TUBING RECORD
L - 370 sx / T - 100 sx6-3/4"
2,597'4-1/2"
SIZE DEPTH SET (MD)
2,590' MD / 2,355' TVD
WINJ
SPLUGOther Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By James Brooks at 8:06 am, Jan 10, 2023
Completed
11/21/2022
JSB
RBDMS JSB 011123
G
BRU 222-34
222-039 / 322-304
WCB 1-24-2025 DSR-1/23/23
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval 5,137' Bel G3 4,793'
3,140' 2,851'
3,516' 3,210'
3,668' 3,358'
3,873' 3,558'
4,093' 3,773'
4,491' 4,162'
5,051' 4,709'
5,456' 5,106'
6,263' 5,895'
6,881' 6,503'
6,981' 6,601'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
INSTRUCTIONS
Beluga J2
Bel F
Bel G
Bel J
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey (+PB1), Csg and Cmt Reports
Authorized Title: Drilling Manager
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Bel I
Bel D
ST X1
Bel E
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
Bel H
Sterling B
TPI (Top of Producing Interval).
Authorized Name and
Sterling C
Formation Name at TD:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
1.9.2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.01.09 15:02:49 -09'00'
Monty M
Myers
_____________________________________________________________________________________
Updated By: CJD 1/09/23
SCHEMATIC
Beluga River Unit
Well: BRU 222-34
PTD: 222-039
API: 50-283-20186-00-00
1
2
PBTD = 7,401’ MD / TVD = 7,024’
TD = 7,489’ MD / TVD = 7,101’
RKB to GL = 18’
4-1/2”
6-3/4”
hole
7-5/8”
9-7/8”
hole
16”
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 2,808’
4-1/2"Prod Lnr 12.6 L-80 DWC/C-HT 3.958”2,590’7,486’
4-1/2"Prod Tieback 12.6 L-80 DWC/C-HT 3.958”Surf 2,597’
JEWELRY DETAIL
No.Depth ID OD Item
1 502’3.958”4.500”Chemical Injection Sub
2 2,597’4.790”5.630”Seal Stem
2,590’4.875”6.540”ZXP Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8"TOC @ Surface (Returns to surface 8/14/22)
4-1/2”Est. TOC @ 4510’ (9-15-2022 CBL)
PERFORATION DETAIL
Zone Top
(MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status
BEL G3 5137’5154’ 4793’ 4810’ 17’ 11-22-22 Open
BEL G3 5163’5169’ 4819’ 4825’ 6’ 11-22-22 Open
BEL G5 5193 ‘5206’ 4848’ 4861’ 13’ 11-22-22 Open
BEL G9 5360 ‘5370’ 5010’ 5020’ 10’ 11-22-22 Open
BEL H2 5563 ‘5583’ 5212’ 5230’ 20’ 11-21-22 Open
BEL H3 5594’5600’ 5240 ‘ 5246’ 6’ 11-21-22 Open
BEL H3 5611’5617’ 5257’ 5263’ 6’ 11-21-22 Open
Activity Date Ops Summary
7/28/2022 Cont. R/D. Unplug derrick lights, and pason. Untie bridle lines. Scope mast down, L/D torque tube. Disconnect water lines, blow down and L/D pit mod roofs.
Hang blocks, unspool DW and cut 80' of drill line. Hang drill line. Unplug electrical. Hand kelly hose and service loop.
7/29/2022 Cont RD for move, CCI transported crane and trucks from barge landing to Ivan Pad, RD Handy Berm, tore out catwalk, mats and liner, tore out pit mod 3, RD
office trailers, LD poorboy degasser, sent BLM and AOGCC notice for potential diverter function test on 8-2-22, installed shipping;beams in sub base, tore out pit
2 and 1, tore out jig, prep to lay over mast, tore out Foreman's and Pushers trailers.;Laid mast down, tore out expediter, change and safety shacks, transported
same 13 miles from Ivan Pad to F Pad. Set office trailers, sewer tanks and gen/change shack. Wired in and powered up same. Set and raised comm tower,
comm's up and running. Lowered doghouse and tore out, tore out gen skid,;Tore out pump skids, transported poorboy degasser and rig mats to F
pad.;Measured and marked for felt/liner on F pad and laid out same. . Remove liner and felt, clean up Ivan pad.;CCI load out topdrive HPU and boiler house.
Haul rig mats and stage on pad for placement.;Lay out rig mats. Place change shack and handy berm conex Clean/organize break shack and change
house.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 0 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
7/30/2022 Cont clean up exposed liner and felt on Ivan Pad, travel to pad, spot cranes and trucks, RU and remove derrick from carrier, carrier from sub, sub from pony
walls. Load all items and transport to F pad. Set pony walls,;Staged sub and cranes, set sub, centered up over well, set carrier and derrick. Pinned hoist rams
and stood mast, set all three pit mods and raise roof tops. Set pump skids and HPU. Troubleshoot Grove crane outriggers, move crane, set doghouse/water
tank. Raise and pin derrick board,;raised doghouse, set gen skid.;Bring generators online. Install gas system. Bring cuttings box and centrifuge. R/U centrifuge
and vacuum degasser. Spot 3rd party shacks. M/U equalizer lines. Install rig lights.;R/U feed line and cuttings chute on centrifuge. H/U steam heaters in pits.
Spool DW and slip on 80’ of new drill line. Continue hooking up pason sensors and electrical lines.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 0 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
7/31/2022 Set boiler skid, cont stringing cords and hoses, staged diverter "T" and annular in cellar, stood poorboy degasser with crane and pinned in place, layed out
felt/liner and rig mats for catwalk, set catwalk and layed over beaver slide, powwered up service shacks and RU comm's,;hammered up plumbing on gas buster,
took on rig water, brought in load of gravel for backyard access to backside of rig, held PJSM and scoped up derrick, hung lower torque tube.;Cont securing
torque tube to derrick, staged topdrive on rig floor and transitioned to blocks, installed torque bushing on torque tube and topdrive, installed wear ring and run
tool in well head, stabbed DSA, diverter T and annular on wellhead, staged diverter vent line, installed service loop,;installed kelly hose, installed knife valve,
staged frac tank at E pad water well, installed standpipe and cement line manifold on rig floor.;RU water meter and hoses on E pad for water well. Well flows
~86bbl/hr. Brought in empty dumpster to F pad. Installed bails and elevators, crown-o-matic. Installed an airline spool on the drawworks. .Installed pason weight
indicator. R/U tongs and pipe handling equipment.;Moved water around pits and leak checked lines. Drilling torque set to 16k on TD. Hooked power up to
change house and boiler room. N/U diverter and surface stack. Install vent line for diverter. End of line 102' OAL 91'f/rig 81' f/ hurricane vac exhaust.;Hook up
hydraulic lines on knife valve and annular. Take on 300 bbl water in pits. Working on rig acceptance check list. Load DP on pipe racks. Function annular and
knife valve.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 0 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
BRU 222-34
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:221-00037 BRU 222-34 Drilling
Spud Date:
gg y
sent BLM and AOGCC notice for potential diverter function test on 8-2-22
8/1/2022 Tested surface lines from mud pumps to topdrive at 3000 psi, good test. Brought in and stood upright water tank, Handy Berm Rep bermed in entire rig footprint,
Witness of diverter function test was waived by Allie Schoessler with BLM at 08:33 on 8-1-22 and Jim Regg with;AOGCC at 09:25 on 8-1-22. Function tested
diverter annular and knife valve with no issues. Checked end play on topdrive (good). Retrieved run tool from wear ring, singled in hole and tagged at 130’ RKB.
Accepted rig at 12:00 on 8-1-22.;Cont PU rack back 4 1/2" DP. Welder on location at noon extending mud pump pop off lines in pits and repairing washout in
mud pump pod #2. 3rd party Rep inspected all fire extinguishers and updated tags. Started building spud mud in pits. Brought in dry mud product for staging on
mud dock.;Finish picking up pipe. P/U DP 92jnts 4.5" DP and 16jnts 4.5" HWDP. Continue building spud mud and helping welder with popoff and bleeder line
extension.;Work on Diverter system inspection report. Perform drawdown on accumulator system and verified pason alarm function on the pit system and flow
show.;Install new annular rubber in annular housing;Finish installing annular element. Build another 300 bbl of spud mud for a total of 900 bbl. Power wash
derrick and pits. Stage sperry directional surface BHA #1 on catwalk. Set timbers and begin bringing in surface casing to strap and tally.;Dragon Boxes Loaded
0 bbls
Total Dragon Boxes 0 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
8/2/2022 Cont. with pressure washing and housekeeping. Finished mixing spud mud. Quadco rep flew into Beluga at 09:30 hrs. Bump tested gas alarm system (ok).;P/U
& M/U 9-7/8” Kymera Bit (RR), 1.5° motor, XO, and RIH with HWDP T/130’, tagged with 5K. Displaced conductor to Spud mud, checked for leaks (ok). Drilled
F/96’-T/217’ (rat hole for MWD tools). GPM-300 SPP-308 psi RPM-40 TQ-4K ROP-60 WOB-3K MW-8.9 ppg Vis-240;CBU, POOH F/217’-T/35’ w/ no
issues.;P/U MWD tools, uploaded data. RIH T/185', washed down T/217', had 32' of fill on bottom. GPM-375 SPP-722 psi RPM-40 TQ-2.7K ECD-9.1 ppg MW-
8.8 ppg Vis-240;Drill ahead as per Sperry WP08a f/217' t/385' Rack stand of HWDP back and P/U jars stand. RIH t/ 385' Resume drilling.;Drill ahead t/691'
Survey on that stand down had high magnetics. Enough to swing the TF to left even though sliding with a 20R TF. Hit what seemed to be a "hard spot" or
"boulder" at 652'. This correlated to where the Sperry survey tool was at survey depth.;Prior two surveys had showed a slight increase in magnetics but azimuth
was in line with slide direction.;Investigated ditch magnets and found some metal curly q's. Notified town drilling engineer. Decision made to pull up the hole
three stands and survey every 10' back to bottom for data density. Production was notified and nearest well (241-34T) was shut in for precaution.;According to
Sperry surveys 241-34T should be 51' away. Surveys sent to Sperry survey management group and Sperry well planner to verify surveys and confirm anti-
collision.;BROOH t/512'. Saver sub and a HWDP box connection was damaged. Put head pin in and circulate while changing out saver sub.;Survey every 10'
f/512' t/691', adjust torque tube while surveying at 640'.;Distance to plan: 5.23' center to center 4.85' high 1.97' left;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 0 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
8/3/2022 Flow checked well on bottom at 691' (static). POOH on elevator's F/691-T/427'. Had 30K over pull, attempted to work through on elevators w/ no luck. M/U TD,
and BROOH F/427'-T/320'. GPM-460 SPP-1150 psi RPM-45 TQ-3-11K P/U-35K S/O-35K ROT-35K.;Pumped OOH F/320'-T/200'. GPM-325 SPP-550 psi P/U-
30K S/O-30K. Cont. POOH on elevators L/D and inspecting BHA for any signs on marring on MWD tools or mud motor (no indications), F/200'-T/Surface. B/O 9-
7/8" Kymera bit. Bit grade-in gauge;1-1-ER-G-X-I-CT-HP. Bit was in the same condition that it went in at. While grading bit noticed a round chunk of metal
about the size of a dime, stuck between a roller cone and the PDC blade. (See photos in well file).;Decision was made by drilling engineer to bring out AK E-line
and Gyrodata. Started expediting personal & equip to Beluga.;Serviced rig- Greased TD, DWKS, IR, blocks, crown, wash pipe, and brake linkage.;Crew
change, held PTSM. Adjusted TQ tube turnbuckles to true up TD over hole. Rig crews worked on housekeeping and cleaning on rig. AK E-line & Gyrodata
personal arrived in Beluga. Held PJSM on running Gyro tools on E-line with Production lead operator, AK E-line, Gyrodata, CCI, Toolpusher, and DSM;Currently
R/U AK E-line unit on BRU 241-34. M/U Gyrodata tools- E-line rope socket, centralizer (2.5" OD), SCT (1.8" OD), gyro tool (1.8"OD), centralizers X2 (2.5" OD),
and weight bar (1.8" OD). Total length of tool=19'. Sensor distance from bottom of tool=9';RIH w/ Gyrodata tools T/2500’ take shots every 100', POOH taking
shots every 300'. Removed grease head from top of tree. L/D Gyrodata tool and grease head. Buttoned up top of tree on BRU 241-34. R/D E-line unit. Cont.
working on general housekeeping, maintenance, and power washing on the rig.;Move e-line over to BRU 222-34T. Get with production and take well offline. R/U
e-line and gyrodata tools on well. P/T lubricator to 1k psi, had a connection leaking. R/D grease head and change o-ring R/U and test again to 1k psi. Had two o-
ring leaking this time. R/D e-line and change piping out.;Got e-line rigged back up again and test to 1k psi. Good test. Could get swab open. Called production,
applied pressure on top side and worked valve open.;RIH with Gyrodata tools t/2500' survey every 100' in the hole. POOH taking surveys every 300'.;RIH on
elevators t/686' with clean out assembly no set downs observed. CBU x2;While rig running in the hole, AK E-line rigged down off of BRU 241-34T and turned
well back over to production.;Held PJSM on running Gyro tools on E-line with AK E-line, Gyrodata, Toolpusher, and DSM. R/U AK E-line with gyrodata tools on
BRU 222-34.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 0 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
Flow checked well on bottom at 691' (static). POOH on elevator's F/691-T/427'. Had 30K over pull, attempted to work through on elevators w/ no luck. M/U TD,() p p g
and BROOH F/427'-T/320'. GPM-460 SPP-1150 psi RPM-45 TQ-3-11K P/U-35K S/O-35K ROT-35K.;Pumped OOH F/320'-T/200'. GPM-325 SPP-550 psi P/U-ppp
30K S/O-30K. Cont. POOH on elevators L/D and inspecting BHA for any signs on marring on MWD tools or mud motor (no indications), F/200'-T/Surface. B/O 9-pg yg g ( )
7/8" Kymera bit. Bit grade-in gauge;1-1-ER-G-X-I-CT-HP. Bit was in the same condition that it went in at. While grading bit noticed a round chunk of metalyggggg
about the size of a dime, stuck between a roller cone and the PDC blade. (See photos in well file).;Decision was made by drilliyng engineer to bring out AK E-line
and Gyrodata
gp
Function tested
diverter annular and knife valve with no issues.
g
Hit what seemed to be a "hard spot" oryggggggp
"boulder" at 652'. This correlated to where the Sperry survey tool was at survey depth.;Prior two surveys had showed a slight increase in magnetics but azimuthpy y yp y g g
was in line with slide direction.;Investigated ditch magnets and found some metal curly q's. Notified town drilling engineer. Decision made to pull up the holeggyqggpp
three stands and survey every 10' back to bottom for data density. Production was notified and nearest well (241-34T) was shut in for precaution.;According toyy y ( )p
Sperry surveys 241-34T should be 51' away. Surveys sent to Sperry survey management group and Sperry well planner to verify surveys and confirm anti-py y y y py y
collision.;BROOH t/512'. Saver sub and a HWDP box connection was damaged
ygggg
Held PJSM on running Gyro tools on E-line with AK E-line, Gyrodata, Toolpusher, and DSM. R/U AK E-line with gyrodata tools
Accepted rig at 12:00
pp p pg g pg y p
Witness of diverter function test was waived by Allie Schoessler with BLM at 08:33 on 8-1-22 and Jim Regg with;AOGCC at 09:25 on 8-1-22. y
8/4/2022 R/U AK E-line on BRU 222-34, M/U Gyrodata tools, RIH w/ logging tools taking shots every 100' T/680', POOH w/ E-line taking shots w/ Gyro tool every 30'. R/D
& released AK E-line/Gyro. Sent data to town.;CBU, GPM-400 SPP-550 psi RPM-45 TQ-3K MW-8.9 ppg P/U-38K S/O-38K ROT-38K. Flow check well 10 min
(static).;POOH on elevators F/685'-T/Surface w/ no issues. L/D cleanout BHA #2. Had calculated hole fill for the trip.;Cleaned & cleared rig floor. Staged 9-7/8"
directional BHA #3 on catwalk. Held PJSM on P/U BHA.;M/U 9-7/8” Kymera bit (RR), 1.5° motor (off set 171°), and MWD tools, uploaded data to MWD tools
(ok). Weighted mud system up to 9.2 ppg. Off line CCI rig movers/barge hands assisted coil with transporting equip. to Ivan River pad.;TIH F/87’ with remainder
of BHA T/691’, washing last std to bottom w/ no fill. Had calculated pipe displacement for the trip.;Cont. directional drilling 9-7/8" surface hole F/691'-T/1000' ,
keeping close eye on magnets for metal and or anything out of the ordinary. P/U-43K S/O-41K ROT-42K GPM-420 SPP-1214 psi WOB-1.5 RPM-45 TQ-2.1K
ECD=9.9 ppg MW-9.2 ppg;Directional drilling 9-7/8" surface hole F/1000'-T/1061'. P/U-43K S/O-41K ROT-42K GPM-420 SPP-1200 psi WOB-6k RPM-50 TQ-
4.3K ECD=9.5 ppg MW-9.2 ppg;Trouble shoot Sperry MWD. Unable to get raw survey data or TF. Tried mode switching tools. Did not work, decision made to
POOH.;CBU x1, Flow check well static. POOH on elevators t/1035' pull tight (40k over). BROOH f/1035' t/694'. GPM-450 RPM-30 TQ-3.9k. Observed torque
increase in slide areas TQ-6.2k.;Flow check well slight seepage (1.8 bbl/hr). Cont BROOH t/326'. POOH on elevators, rack back jars and flex collars. Plug in,
download MWD. Had calculated pipe displacement for trip.;L/D BHA #3 Change out EWR-M5 and DM. Break bit. Bit had two rocks wedged between cone and
blade. Bit Graded:1-1-ER-G-X-I-CT-DHF. DP stand #1 had radial scaring and so did stand #9 of HWDP. Severe radial scarring was observed on Sperry’s
tools.;P/U BHA #4 M/U 9-7/8” Kymera bit (RR) to same motor P/U DM and perform offset (168.25°) P/U rest of BHA, and download. RIH flex collars and 1 stand
HWDP and shallow hole test.;RIH on elevators f/200' t/1004' without issue P/U-43k S/O-41K;Dragon Boxes Loaded 160 bbls
Total Dragon Boxes 240 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
8/5/2022 Cont. RIH on elevators, washed last std down bottom w/ no fill, had calculated pipe displacement during trip. GPM-410 SPP-1140 psi RPM-55 TQ-4K P/U-45K
S/O-40K ROT-42K CBU, pumped sweep, sweep came back on time w/ no increase in cuttings.;Cont. directional drilling 9-7/8" surface hole F/1061'-T/1250'. P/U-
50K S/O-40K ROT-48K GPM-410 SPP-1171 psi WOB-4-8k RPM-55 TQ-5K ECD=10.1 ppg MW-9.2 ppg;Decision was made by drilling engineer to POOH. CBU
X2, shot on bottom survey. Racked back 1 std back in derrick. Flow checked well (static).;Attempted to POOH on elevators, had 30K over pull @ 1184'. BROOH
F/1184'-T/1124'. Re-attempted to POOH on elevators, POOH F/1124'-T/198' w/ no issues. Had calculated hole for the trip.;Crew change, held PJSM. Performed
rig service while monitoring hole on TT (static). Greased crown, TDS, DWKS, IR, wash pipe, and brake linkage.;L/D BHA #4 F/198'-T/surface. Racked back
HWDP, jars, and flex collars. plug in and down loaded tools. L/D MWD tools, bled motor, B/O 9-7/8" Kymera bit. Bit grade- 1/16" under gauge, PDC part- 1-1-LT-
S-X-1-ER-HP, Roller cone part- 1-1-LT-C-E-1-ST-HP.;Monitoring well on TT. Loss rate=1.2 bph. working on housekeeping, power washing and equip.
maintenance while waiting on plug back procedure.;P/U BHA #5 Clean out / Cement Assembly. RIH on elevators t/1120'. Displacement Calc-21.96bbl Act-
22.89bbl. Wash last two stnds t/ 1240'.;Continue to circulate on the hole . Cementers arrive on location, spot cement units and begin rigging up. Build sweep to
clean DP and fill trip tank with black water for any cement to surface.;PJSM w/ Cementers, Rig crew and DSM for pumping balanced cement plug. R/U
cementers ,M/U head pin, chicksin and Halliburton valve to cement line.;Pump 5 fresh water. Halliburton loaded lines with 5 bbls water and checked for leaks.
Halliburton pressure tested lines at 750 low 3200 high, good tests. Halliburton pumped 10 bbls 8.4 ppg water at 3 bpm- 200 psi, followed by 58 bbls (152 sx)
12.5 ppg Type I II lead cement at 4 bpm- 280 psi falling;falling to220psi, then 1.9 bbl 8.4ppg water then, displaced with 6.9bbl 9.2ppg Spud Mud at 4 bpm 90 psi.
Cement in place at 00:30.;R/D head pin, chicksin and Halliburton valve. Begin pulling on elevators assembly made it 7' before pulling tight. Pulled to 40k over.
Notified town engineer, screwed in began pumping and trying to rotate. Idle pump start at 750 psi going up to 1350 psi but couldnt get flow and couldn't
rotate.;Bleed pressure off. Begin working pipe, trapping torque, and working up to a max pull of 300k. Let brakes cool off. Apply 1000psi with mud pump and
begin working pipe up to 240k and S/O to 30k while applying right hand torque. Continue this procedure until e-line arrived.;AK E-line arrive on location. PJSM
w/ rig crew, AK e-line, and DSM. R/U E-line to go in with a drift run;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 240 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
gp p
Cont. directional drilling 9-7/8" surface hole F/1061'-T/1250'.
pgqp p
Cont.directional drilling 9-7/8" surface hole F/691'-T/1000' , g pp p
keeping close eye on magnets for metal and or anything out of the ordinary.
pg ppg y g g
Attempted to POOH on elevators, had 30K over pull
p g g
DP stand #1 had radial scaring and so did stand #9 of HWDP. Severe radial scarring was observed on Sperry’sggpy
tools.;P/U BHA #4 M/U 9-7/8” Kymera bit (RR) to same motor P/U DM and perform offset (168.25°) P/U rest of BHA, and download. RIH flex collars and 1 stand
HWDP and shallow hole test.;
yg gg p
working on housekeeping, power washing and equip. p
maintenance while waiting on plug back procedure yp
Cementers arrive on location, spot cement units and begin rigging up. Build sweep topggggp
clean DP and fill trip tank with black water for any cement to surface.;PJSM w/ Cementers, Rig crew and DSM for pumping balanced cement plug. R/Upygppgpg
cementers ,M/U head pin, chicksin and Halliburton valve to cement line.;Pump 5 fresh water. Halliburton loaded lines with 5 bbls water and checked for leaks.p p
Halliburton pressure tested lines at 750 low 3200 high, good tests. Halliburton pumped 10 bbls 8.4 ppg water at 3 bpm- 200 psi, followed by 58 bbls (152 sx) p
12.5 ppg Type I II lead cement
8/6/2022 RIH through TDS w/ E-line drift run- Drift 2.5", weights bar, and CCL tool. RIH F/surface-T/730', periodically checking P/U and S/O weights. At 660' did see a
decrease in S/O weight from 124 ft/lbs to 117 ft/lbs, P/U with no additional P/U weight. POOH and inspected;tool for signs of cement (no cement). L/D drifting
tool, M/U shot rod and 2-5' lengths of primer cord. RIH w/ back off tool, logged down below planned back off depth of 593' T/640', logged up to set back off tool
across DP tool jt at 593', set on depth.;E-line P/U-220 lbs S/O-120 lbs. Put 4K left handed TQ (1/2 wrap) as per AK E-line into drill string. Fired charge. Pulled up
hole w/ E-line tools, attempted to rotate to the left to back off (no luck). POOH w/ E-line tools, discussed options w/ town, decision was made to;make another
back off attempt putting 15K left handed TQ into drill string. Re-armed shot rod w/ 3-5' lengths of primer cord. RIH w/ Back off tool, logged down below planned
back off depth of 593' T/640', logged up to set back off tool across DP tool jt at 593', set on;depth. Went to put 15K left handed TQ into drill string. Pipe back off
at 11K . Called town, decision was made to re-torque drill string to M/U TQ (21K) and put only 11K left handed TQ into string. Re-torqued pipe, put 11K left
handed TQ into drill string (2-1/4 wraps);fired charge, seen good indication of back off. Had E-line pull up hole 45'. Attempted to rotate drill string to the left,
backed out 3 wraps (free rotation), screwed back in 1 wrap, POOH w/ E-line tools, R/D and released E-line.;Backed out string w/ 5 wraps, seen weight fall off
from 40K to 25K, P/U 2', brought MP on at idle, established circ. Brought both MP's on line, Staged up pump rate. CBU. GPM-342 SPP-90 psi RPM-45 TQ-2k
P/U-25K S/O-25K ROT-25K. No sign of cement at BU,;but did see a fair amount of course sand coming across the shakers. Pumped 22 bbl low-Vis sweep w/
walnut, sweep came back on time w/ no increase in cuttings. Cont. CBU while moving black water from TT to PP.;Crew change, held PTSM. Shut down pumps,
flow checked well (static). POOH racking back stds. in the derrick, recovered 619.7' of DP, L/D last 2 jts and flagged bottom jts to be sent in for inspection. TOF
@ 624.46'.;Performed rig service and another derrick inspection. Greased crown, IR, TDS, DWKS, wash pipe, and brake linkage.;Worked on general
housekeeping, and rig cleaning. While mobilizing Yellow Jacket fishing tools across to Beluga by means of helicopter. Monitoring well on TT, static loss rate=.4
bph.;Received the remainder of the fishing tool in Beluga. Staged fishing BHA and handling equip on the catwalk. Cont. monitoring well on TT, static loss
rate=.4 bph.;Held PJSM on P/U fishing BHA. M/U 8-1/8" wash pipe BHA #6- 8-1/8 wash pipe burn shoe dressed w/ carbides, 1-32' jt of 8-1/8' wash pipe, 8-1/8'
can field bushing, XO's X2, 6.5" drilling jars, XO, and 1 jt of HWDP. RIH on 4.5 DP F/106-T/572'. Wash down @ 40-RPM 2.7k-TQ 3/bbl min 0psi;Wash down @
40-RPM 2.7k-TQ 3/bbl min 0psi Tag TOF @ 609' continue to wash down t/645' with no WOB. CBU. No sign of cement at BU. Mud PH-9.2 P/U 28k S/O 28k ROT
27k;POOH L/D HWDP single and jars. P/U another jnt of wash pipe, jars and HWDP single. RIH t/572';Screw in establish parameters P/U 28k S/O 28k ROT 27k
and wash ream at 3bbl/min 0 psi 2.4k tq, f/572' t/676' no WOB was observed. CBU, no cement at bottoms up.;POOH on elevators f/676' t/surface. L/D wash
pipe assembly.;P/U Jar stand, M/U cut lip sub on bottom and RIH t/ 564'. Screw in and establish parameters. P/U 25k S/O 28k ROT 26k. Pump 1bbl/min 0 psi 10
RPM 1.9k tq. Tag fish at 609' screw in and caught pressure 360PSI. Put 5 wraps in and Torque up to 21K. P/U 5k over confirmed fish.;R/U E-line , M/U shot rod
and 3-5' lengths of primer cord and CCL and RIH. E-Line set down in top of jars at 577'. POOH inspect assembly. Straightened shot rod and took some tape off
of the primer cord. Run back in hole was able to pass through jars. RIH t/ 665'. Put 1 wrap 11k LH torque in string;Fired charge observed good indication at
surface. Open grabber box no torque at surface. Back out 2 wraps to make sure of good back off, put 1 back in. POOH w/ e-line and R/D;Backed out string w/ 5
wraps, seen weight fall off f/ 28k t/ 25k. Idle pumps and stage up to 8bbl/min. No cement seen at CBU. Pump sweep, circulate sweep out. Sweep back on time
with no increase in cuttings or cement at surface. Shut down flow check well-static.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 240 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
8/7/2022 Finished POOH w/ fish, L/D fish ( 2 jts of 4.5" DP. P/U-28K S/O-28K.;Performed rig service & derrick inspection. Greased crown, IR, TDS, DWKS, wash pipe,
brake linkage, and checked oil in DWKS. Found broken bolt on TD HYD goose neck line clamp, recovered both pieces. Replaced w/ same.;M/U wash pipe assy.
BHA #9, RIH F/137'-T/634'. P/U-28K S/O-28K ROT-28K .;Broke circ. GPM-81 SPP-41 psi . Washed down F/634', tagged TOF at 669', washed over TOF, kicked
in rotary. RPM-15, washed down full std T/695', CBU. GPM-221 SPP-51 psi RPM-20 TQ-2.2K . No signs of cement at shakers. Resumed washing down
F/695',;GPM-81 SPP-42 psi RPM-16 TQ-2.2. TQ increase @ 715' F/2.2K-T/3.3K T/736' were we tagged out on wash pipe No-Go.;CBU, seen Ph increase F/8.9-
T/10.1 at the shakers, w/ no increase in MW, but did see clabbered up mud and soft cement at surface.;Crew change, held PTSM. POOH F/736'-T/surface. L/D
BHA #9. P/U-25K S/O-25K;Cleared & cleaned rig floor. M/U cut lip screw in sub fishing BHA #10. RIH F/68'-T/626'.;M/U TDS, broke circ. Washed down w/ cut
lip sub. GPM-81 SPP-20 psi RPM-4 TQ-1.8K. F/626', tagged TOF at 669'. Screwed into fish, M/U connection to CDS-40 TQ-21K. P/U 5K over P/U weight,
confirming engagement of fish (Good).;Held PJSM w/ rig crew and AK E-line. R/U E-line, RIH w/ string shot. Set down w/ string shot in side of jars. POOH w/ E-
line, re-configured string shot rod. RIH w/ string shot, set down at 720' WLM, short of back off depth. Called drilling engineer, decision was made;to back off one
connection higher to fish 1 jt of 4.5" DP. While working to get on set depth, broke through barrier and were able to get down too 726' WLM. Went w/ original
plan, set on back off depth of 718' WLM to recover 2 jts of 4.5" DP. Put 11K left handed TQ;into drill string. Fired charges. Seen good indication at surface of
back off. Pulled up hole w/ E-line tools 45'. Confirmed back off w/ 2 LH wraps of free rotation. POOH w/ E-line, R/D and released E-line unit. Unscrewed back
off connection w/ 5 LH wraps and P/U 5'.;Broke circ. at a idle, established circ. Staged up pumps to 7 bpm, CBU X2, seen PH increase and clabbered
mud/cement at shakers.;POOH w/ fish (2 jnts of 4.5" DP) and L/D same.;P/U BHA #11 wash pipe assembly RIH t/725' was down 2bbl/min 0 psi, 20RPM, 2.2k tq
to TOF at 731 seen tq increase t/ 2.8k tq cont to wash down seen tq increase to 4.2k and started seeing WOB 4-5k with a max of 8k down to 741'.;Wash and
slow rotate down 2bbl/min 0 psi, 20RPM, 2.2k tq to TOF at 731 seen tq increase t/ 2.8k tq cont to wash down seen tq increase to 3.7k and started seeing WOB
2-5k with a max of 8k down to 741'. CBU, PH increase to 9.8 seen soft cement clabbered mud/cement. scattered firm cement.;Wash/ream t/747' tq increased to
4.2 with a steady 4-5k WOB. CBU, PH 10.2 with scattered soft and firm cement. P/U above fish 721', CBU clean hole up.;POOH f/721 t/ surface. L/D wash pipe
assembly.;P/U Mule shoe RIH t/681' stnd #11 P/U E-kelly screw in and wash down t/714';MU head pin, chicksin and Halliburton valve to cement line. Pump 5
fresh water. Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 400 low 3600 high, good tests.;Halliburton
pumped 10 bbls 8.4 ppg water at 3 bpm-150 psi, followed by 25 bbls (66 sx) 12.5 ppg Type I II lead cement at 3.5 bpm- 170 psi falling to 135psi, then 1.9 bbl
8.4ppg water 3.5bbl/min 135PSI then, displaced with 4.5 bbl 9.2ppg Spud Mud at 3.5 bpm falling to 56psi. Cement in place at 02:30;POOH 20'/min f/714' t/272'
3 stands above estimated TOC @ 480' P/U-22k S/O-22k .;Screw in idle pumps break circulation. CBU, @ 8bbl/min. No cement observed. Pump lo-vis walnut
sweep to clean the pipe.;Circulate on hole at 2bbl/min and work pipe make sure free every 30 min- WOC;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 240 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
RIH through TDS w/ E-line drift run- Drift 2.5", weights bar, and CCL tool. RIH F/surface-T/730', periodically checking P/U and S/O weights. At 660' did see agg pygg
decrease in S/O weight from 124 ft/lbs to 117 ft/lbs, P/U with no additional P/U weight. POOH and inspected;tool for signs of cement (no cement). L/D drifting ggpg()g
tool, M/U shot rod and 2-5' lengths of primer cord. RIH w/ back off tool, logged down below planned back off depth of 593' T/640', logged up to set back off toolgp gg p p gg p
across DP tool jt at 593', set on depth.;E-line P/U-220 lbs S/O-120 lbs. Put 4K left handed TQ (1/2 wrap) as per AK E-line into drill string.Fired charge. Pulled upjp (p)p g g
hole w/ E-line tools, attempted to rotate to the left to back off (no luck). POOH w/ E-line tools, discussed options w/ town,decision was made to;make anotherp() p
back off attempt putting 15K left handed TQ into drill string. Re-armed shot rod w/ 3-5' lengths of primer cord. RIH w/ Back off tool, logged down below planned pp g g gp gg p
back off depth of 593' T/640', logged up to set back off tool across DP tool jt at 593', set on;depth. Went to put 15K left handed TQ into drill string. Pipe back off pggp jpp
at 11K . Called town, decision was made to re-torque drill string to M/U TQ (21K) and put only 11K left handed TQ into string
p g
Backed out string w/ 5 wraps, seen weight fall off ww
from 40K to 25K
g
recovered 619.7' of DP,
y p p
Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 400 low 3600 high, good tests.;Halliburtonpgg
pumped 10 bbls 8.4 ppg water at 3 bpm-150 psi, followed by 25 bbls (66 sx) 12.5 ppg Type I II lead cement at 3.5 bpm- 170 psi falling to 135psi, then 1.9 bblp p ppg p p y ( ) ppg yp p p
8.4ppg water 3.5bbl/min 135PSI then, displaced with 4.5 bbl 9.2ppg Spud Mud at 3.5 bpm falling to 56psi. Cement in place at 02:30
ggj
Called drilling engineer, decision was made;to back off onegg
connection higher to fish 1 jt of 4.5" DP.
8/8/2022 Cont. circulating hole & reciprocating pipe every half hour at 296’, while waiting on cement to reach its 200 psi compression strength. Rig hands worked on
housekeeping, scrubbing/pressure washing, maintenance projects, and EAM’s.;Crew change, held PTSM. Cont. circulating hole & reciprocating pipe every half
hour at 296’, while waiting on cement to reach its 200 psi compression strength. Monitoring well on TT the other 30 min. Loss rate=1.1 bph;Cont. w/
housekeeping, scrubbing/pressure washing, maintenance projects, and EAM’s. Organized XO's & subs and installed on peg board. Fixed leak on MP#2
transmission. Cleaned oil from under MP#2-Engine. Pressure washed exterior wall on rig modules.;Organized 40' C-can. Washed walls in lube room. Got
inventory for shakers & MP parts. Fixed leak on hopper #1 discharge line. Pressure washed hopper room and chemical loading dock area.;Staged cement
tagging BHA #13 on catwalk. Loaded catwalk racks with 20 jts of 2-7/8” PH-6 work string and strapped & tallied. Assisting welder w/ removing MP pop off lines
from PP and running them to suction pit #6.;Finish welding up popoff and bleed off extensions. Adjusted proximity sensor magnets on TD RPM sensor.;After
taking on fuel motor man noticed a sheen on the rig fuel tank located by the gen house door. Found a crack in a weld about 1' from the top of the tank. Pumped
fuel out of the tank below the crack into the boiler fuel tank. No fuel outside of containment.;Crew change, held PJSM, Cont. circulating hole & reciprocating
pipe every half hour at 296’, while waiting on cement to reach its 200 psi compression strength. Monitoring well on TT the other 30 min. Loss rate=1.1
bph;POOH with mule shoe assembly f/308' t/ surface. M/U dumb iron assembly on a single of DP to go in and tag cement. RIH t/415' P/U-24k S/O-24k ROT-
24K;Begin washing down at 3bbl/min 50 psi. Took weight at 517'. Ream to 521' where assembly took weight 3k. CBU got clabbered up mud and cement. PH
11.5 no mud weight increase. Set back down 5k at 521’ no rotary Circulate hole clean at 5bbl/min 90PSI;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 240 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 0 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
8/9/2022 POOH F/521-T/surface. L/D cement tagging BHA #13.;Cleared & cleaned rig floor. R/U Parker power tongs and handling equip. Moved drilling flex collars to
ODS;P/U and singled in the holew/ 2-7/8" PH-6 work string F/surface-T/513'. P/U-20K S/O-20K;M/U XO and TD. CBU GPM-130 SPP-58. Held PJSM w/ HES
cementer, rig crew, Baroid, CCI, and DSM.;R/U HES cementers. Pumped 5 bbls ahead to clear lines. PT'd cement lines, 750 psi Low / 3500 psi High. Pumped
& spotted a balanced cement plug , 20 bbls of 12.5 ppg cement @ 3.5 bpm , displaced w/ 1 bbl of H2O and 1 bbl of spud mud. FCP-145 psi.;Opened up to
cement truck (No flow). CIP @ 11:30 am. R/D cement lines.;POOH at 20' per/min L/D singles of 2-7/8" PH-6 F/513'-T/185' (11jts). Running pressure washer
Wessel through each jts of 2-7/8" PH-6 on catwalk racks and vacuuming them dry.;Crew change, held PTSM. M/U XO and TD, CBU GPM-210 SPP-45, seen no
cement at surface. Pumped 15 bbl Low Vis sweep to help scrub pipe.;POOH L/D remaining jts. of 2-7/8" PH-6 work string F/185'-T/surface. Cont. to run pressure
washer Wessel through each jts of 2-7/8" PH-6 on catwalk racks and vacuuming them dry.;P/U cement tagging BHA #14, RIH F/surface-T/160'.;Circulating hole
every 1/2 hr. and monitoring on TT the other half. Loss rate=.8 bph. Cont. w/ housekeeping, scrubbing/power washing and maintenance. Pressure washed
mast. Changed out valve in gun on pit #6. Tied in auxiliary diesel bulk tank to the fuel system to supply;supply fuel to day tanks and take Gen skid diesel bulk
tank out of service till its fixed.;Circulating hole every 1/2 hr. and monitoring on TT the other half. Loss rate=.8 bph, grease choke and inspect cmt manifold,
perform mast drops inspection, inspect and grease cat walk, pick up dunage and pallets on location. Prep rig crew change house conex under carriage
for;welder ( tin falling off ), Cont. pressure washing pump room and pits.;Circulating hole every 1/2 hr. and monitoring on TT the other half. Loss rate=.8 bph,
Pressure was shakers and inspect, pressure wash exterior walls and rig mats between pits, suck out standing water from rig containment. Pressure wash
shakers and inspect. Inventory and organize 40' conex;Cont. working on rig crew change house conex under carriage tin prepping for welder, stick pick around
location.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 400 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 208 bbls
ISO Tanks Total 312 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
8/10/2022 Cont. circ. hole at 160' every 1/2 hr. and monitoring well on TT. Static loss rate= .8 bph. Pressure washed exterior walls on rig modules. Repaired under liner on
rig crews change house conex. modified stairs so we can use them while pipe in loaded on catwalk pipe rack.;Converted koomey sight glass tube from
centimeter to inches. Premiered sub/XO peg rack and basket. Trouble shot degasser switch.;Crew change, held PTSM. Cont. w/ housekeeping/cleaning and
maintenance projects while WOC.;M/U TD and washed down F/163', GPM-137 SPP-30 psi, at 340' stated taking weight kicked in rotary, RPM-25, cont. washing
& reaming (cement stringer) T/352'. Had hard tag w/ 5-6K WOB, called TOC at 352'. CBU, seen clabbered mud and good hard chunks of;cement at shakers w/
11.2 PH. Cont. circ. till shakers cleaned up. GPM-210 SPP-87 psi RPM-25 TQ-2.3K;POOH F/347'-T/surface, L/D BHA #14 cement tagging assy. monitored
hole on TT.;R/U Parker power tong and handling equip.;P/U and singled in the hole w/ 2-7/8" PH-6 cement string T/329'.;M/U XO and TD, CBU, GPM-188 SPP-
55 psi. Held PJSM w/ HES cementers, rig crew, Baroid, CCI, and DSM on spotting cement plug.;Flush lines with 5 bbls of water and PT 387/3500 PSI for 5 min
each. Pump 5 bbls of water followed by 21 bbls of 15.8 ppg cement @ 2.5 bpm, 140 psi ICP- 154 psi FCP, Chased with 2 bbls of water 2.5 bpm, 75 psi, rig down
cement line and checked plug was balanced- good. CIP @ 18:35 hrs.;POOH laying down 9 jts of 2 7/8" PH-6 pipe to 60', pulled dry. GCI washing inside of pipe
with wizard nozzle on pipe rack while L/D;CBU @ 160 gpm, 0 psi with no signs of cement. PH did increase to 10.6, pumped 15 bbls walnut sweep sts.;POOH to
surface laying down remaining jts of 2 7/8" PH-6 pipe while GCI cleaned with wizard.;R/D and clean power tongs, flushed lines with black water. Made up jet-sub
and flushed stack, attempted to close annular observing bag not closing completely ( 75-80% closed ) continued to function bag and wash debris off top of
annular, increased annular pressure to 1250 psi observing full closure;around the dp. It was on this cycle that the floorhand in the cellar heard a pop and
hydraulic fluid began to run out of the upper housing cap.;Rigged down chain binders, hole fill and flow lines, pulled riser and removed upper housing cap. Seal
kit from Kenai yard was flown over from OSK. Removed element and Adaptor ring. Inspect Adaptor ring top and OD seals seeing a cut/wash in OD
seal;Mechanic inspected piston and piston seals-good, changed out Adaptor ring top seal and OD seal. Reassemble annular components and function test bag
multiple time- good. Make up riser, flow/hole fill lines and chain binders;Picked up 20 stands of 4.5" DP drifting off the catwalk racking back in derrick. Strapped
and tallied HWDP.;Dragon Boxes Loaded 80 bbls
Total Dragon Boxes 480 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 312 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
Pumped gp
& spotted a balanced cement plug , 20 bbls of 12.5 ppg cement @ 3.5 bpm
Cont. circulating hole & reciprocating pipe every half hour at 296’, while waiting on cement to reach its 200 psi compression strength
p
Cont.circulating hole & reciprocating
pipe every half hour at 296’, while waiting on cement to reach its 200 psi compression strength.
pg gqp g
Held PJSM w/ HES cementers, rig crew, Baroid, CCI, and DSM on spotting cement plug.
8/11/2022 Cont. WOC, cleaned and organized tool room. Pressure washed inside sub base, vacuumed out cellar and power washed. Pason rep arrived in Beluga, took
inventory of Pason equip. and re-calibrated Pason pit sensors.;Crew change, held PTSM. Changed oil in generator for office trailers. Cont. power
washing/cleaning and organizing around the rig. Changed oil filter on DWKS and MP engines;P/U BHA #15 cement tagging assy. RIH T/90', circ. & conditioned
mud, cont. WOC, monitor hole on TT, Circ. hole every ½ hr.;Pressure washed in pump room and hopper houses and jig between pumps & pits. Staged 9-7/8"
directional BHA #16 on catwalk.;Wash down F/90' T/152' @ 170 gpm, 27 psi, no rotation setting 3K down, picked up started rotary @ 20 rpms and reamed
down to 157' tagging good hard cement, Cont. to ream/drill up cement to 192' @ 170 gpm, 130 psi, 20-50 rpm, 2.6-4K TQ, 4-6K wob;Circulate hole clean at 160
gpm, 100 psi, 50 rpm, 2.3K TQ while pulling up slowly;POOH F/192' T/surface laying down tag BHA #15.;M/U bit to motor, pick up and scribe DM collar with a
168.5 offset, cont. making up EWR and HOC. Perform download as per MWD. RIH with Flex collars T/134', make up first stand of HWDP and wash down to
190' performing shallow hole test. Attempted survey shot- bad, Drilled down to 202'- good survey;Directional drill 9 7/8" surface hole F/202' T/421', 330 gpm,
585 psi, 50 rpm, 3.8K Tq, WOB= 5-8K, Diff= 80 psi, MW in- 9.2 ppg, KOP @ 202', Time drilled F/202' T/213', displaced cement contaminated 9.2 ppg spud mud
with clean 9.2 ppg spud mud on the fly.;Dragon Boxes Loaded 80 bbls
Total Dragon Boxes 480 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 416 bbls
Losses Downhole 0 bbls
Total Losses Downhole 0 bbls
8/12/2022 Cont. drilling/sliding 9-7/8" surface hole F/400'-T/947'. P/U-50K S/O-44K ROT-47K GPM-400 SPP-1000 psi RPM-60 WOB-2K Diff-100 psi TQ-4.8K MW-9.2 ppg
ECD-10.0 ppg Max gas 0 units.;Crew change, held PTSM. Cont. drilling/sliding 9-7/8" surface hole F/947'-T/1191'. P/U-50K S/O-44K ROT-47K GPM-428 SPP-
1097 psi RPM-60 WOB-2-4K Diff-40-150 psi TQ-4.8K MW-9.2 ppg ECD-9.9 ppg Max gas 0 units.;Circ, till shakers cleaned up. GPM-429 SPP-1080 psi RPM-66
TQ-5.7K. Shot on bottom survey. Flow checked well (static).;POOH on elevators F/1191'-T/387' w/ no issues.;Performed rig service. Greased crown, IR, TD,
wash pipe, DWKS, and brake linkage. Cleaned MP suction screens. Measured out maximum elevator height for P/U Geo-Tap tool (72').;RIH on elevators F/387'
T/1132', with no issues. Washed and reamed last std to 1191', 274 GPM, 540 PSI, 50 RPM, 4.5K TQ.;Circ. Hi-vis/Walnut sweep around at 360 GPM, 760 PSI,
50 RPM, 4.5K TQ, 9.8 ECD, ROT= 42K, PU= 52K, SO= 40K, No increase in cuttings from sweep.;Resume directional drilling F/1191' T/1566', P/U-52K S/O-
42K ROT-48K GPM-435 SPP-1223 PSI, RPM-60 WOB-5-9K Diff-150 psi TQ-5.3K MW-9.2 ppg ECD-9.8 ppg Max gas 0 units.;Cont. directional drilling F/1566'
T/2184', P/U-70K S/O-50K ROT-56K GPM-452 SPP-1330 PSI, RPM-60 WOB-5-10K Diff-200 psi TQ-6.8K MW-9.2 ppg ECD-9.9 ppg Max gas 0 units. Distance
to plan 14.64', High- 13.68', Left-5.21';Dragon Boxes Loaded 340 bbls
Total Dragon Boxes 820 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 312 bbls
ISO Tanks Total 728 bbls
Losses Downhole 24 bbls
Total Losses Downhole 24 bbls
8/13/2022 Circ. till shakers cleaned up. GPM-400 SPP-1020 psi RPM-65 TQ-7.2K. Shot on bottom survey, flow checked well (static).;POOH on elevators F/2182'-T/1191'
w/ no issues. P/U-60K S/O-40K.;Performed rig service and monitored hole on TT. Greased TD, IR, DWKS, crown, blocks, wash pipe, brake linkage, and
cleaned suction screens. Loss rate=1.1 bph.;RIH F/1191'-T/2182' w/ no issues, washing last std to bottom w/ no fill. P/U-66K S/O-45K. Pipe displacement- Cal
Disp.=18.6 bbls Act Disp.=14.6 bbls Diff= -4 bbls;Resumed drilling/sliding F/2182-T/2402'.P/U-70K S/O-48K ROT-54K GPM-430 SPP-1240 psi RPM-65 WOB-
9K Diff-66 psi TQ-7.6K MW-9.2 ppg ECD-9.7 ppg Max gas 0 units. Pumped 20 bbl Hi-Vis sweep w/ walnut at 2200', sweep came back 25 bbls late w/ a 25%
increase in cuttings.;Crew change, held PTSM. Cont. drilling/sliding F/2402' to TD at 2813'.P/U-73K S/O-47K ROT-57K GPM-437 SPP-1337 psi RPM-75 WOB-
7K Diff-52psi TQ-7.6K MW-9.3 ppg ECD-9.6 ppg Max gas 0 units.;CBU- 435 GPM, 1233 PSI, 65 RPM, 7.7K TQ, 9.6 ECD, Max gas= 0 units. Monitor well= slight
seepage;POOH F/2808' T/2151', 30-40K overpull through 2 spots @ 2763' and 2645', No other issue POOH. Disp. Cal= 4.02 bbls, Disp. Act= 5.35, Diff-1.33
bbls;RIH F 2151' T/2773', with no issues. washed down to 2813', 300 GPM, 796 PSI, 30 RPM, 7.2K TQ, no fill.;Pumped 20 BBL Hi-vis/walnut sweep around,
426 GPM, 1250 PSI, 60 RPM, 7.3K TQ, 9.5 ECD. Observed 20% increase in cuttings at BU, Sweep back 18 BBLS late with 10% increase in cuttings. Monitor
well 10 min- 4.25 BPH loss rate;POOH F/2808' T/699', No issues, Cal Disp= 14.7, Act Disp= 24.06, Diff= 9.36;Rack back 8 stds of HWDP L/D jar std. L/D 2 flex
collars and perform download as per MWD. 2 BPH static loss rate while downloading, L/D remaining pieces of BHA. Bit Grade= 6-7-WT-A-E-1/16-WT-TD;Clear
and clean rig floor, remove small pieces and crossovers from BHA #16. Pick up jt. and pull wear ring.;R/U fill up hose and CSG elevators, Pick up landing
jt./hanger and perform dummy run.;Dragon Boxes Loaded 255 bbls
Total Dragon Boxes 1,075 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 832 bbls
Losses Downhole 50 bbls
Total Losses Downhole 74 bbls
@gp p
Cont. to ream/drill up cement to 192' @
p
L/D remaining pieces of BHA.
Cont. drilling/sliding 9-7/8" surface hole F/400'-T/947'.
pg g p
Cont. drilling/sliding F/2402' to TD at 2813'.
g
Resumed drilling/sliding F/2182-T/2402'.
Cont. WOC
p
Directional drill 9 7/8" surface hole F/202' T/421',
p
Resume directional drilling F/1191' T/1566
8/14/2022 R/U Parker casing tongs & handling equip. Loaded 7-5/8" casing on catwalk pipe racks. Held PJSM w/ Parker casing hands, rig crew, and DSM.;M/U and
Bakerloc 7-5/8" shoe track. attempted to tested shoe track floats w/ no luck, M/U XO and pumped through floats (ok). Retested floats w/ out pumping (ok).
Cont. running 7-5/8" 29.7# L-80 CDC surface casing as per run tally F/122'-T/1195', installing centralizer's on every other jt.;M/U XO and TD, broke circ. w/
pumps at and idle. Staged up MP, GPM-200 SPP-80 psi, CBU w/ reciprocating pipe. P/U-52K S/O-32K;Crew change, held PTSM. Cont. running 7-5/8" 29.7# L-
80 CDC surface casing as per run tally F/1195'-T/2776', had 10K set down, M/U XO and TD, broke circ. washed down F/2776'-T/2786' w/ no issues. Gpm-205
SPP-196 psi P/U-84K S/O-41K . B/O XO, P/U & M/U;XO, and working jt. Washed down F/2786' to bottom at 2813', CBU, GPM-132 SPP-106 P/U-89K S/O-49K
. L/D working jt. M/U landing jt, hanger, and pup, washed down landing hanger on seat, GPM-210 SPP-118 psi.;Circ. & conditioned mud for cement job while
reciprocating pipe 5'. 210 GPM, 110 PSI, R/D Parker casing equip. Moved in and R/U HES cementer.;Conduct PJSM with crew, haliburton cmtrs, mud engineer
and cci. MU plug launcher and hardline, Halliburton loaded lines with 2 bbls water and checked for leaks. Halliburton pressure tested lines at 300 low 4000 high,
good tests. Halliburton pumped 58 bbls 10.5 ppg Tuned Spacer at 4 bpm- 128 psi;dropped bottom plug and pumped 156 bbls (370 sx) 12.0 ppg Type I II lead
cement at 4.9 bpm- 280 psi, followed by 35.3 bbls (175 sx) 15.8 ppg Type I II tail cement at 3 bpm- 197 psi. Halliburton dropped top plug, then displaced with 9.3
ppg Spud Mud at 4.4 bpm 740 psi Halliburton dropped top plug;then displaced with 9.3 ppg Spud Mud at 4.4 bpm 740 psi. Slowed pump to 2 bpm with 10 bbls to
go. Did bump the plug at 123.5 bbls into displacement (calculated 125 bbls). Held 1316 psi (FCP of 720 psi) for 5 minutes, bled off and floats held. Bled back .5
bbls to truck.;Had 58 bbls of Spacer returns to surface and 35 bbls lead cement to surface. Added LCM to lead cement (Bridge Maker at 2.4 pps. Mix water temp
55 deg. Pumped 50% excess on both lead and tail. No losses throughout the job. Stopped reciprocating 20 bbls into tail cement.;CIP at 22:16, 8/14/2022.
Washed up, R/D, and released Halliburton.;L/D landing Jt., Pick up jet sub and flush stack with black water, cycle annular and wash off. Flutes packed off and
stack wouldn't drain.;Multiple attempts with jet sub to free floats, attempted air from bottom with no success. Ran a 2" hose from hurricane vac down and was
able to suck out stack and clean off hanger top free from gravel. R/D 16" vent line during this process.;Picked up 5" HWDP, make up pack-off and inspect as per
cactus rep. Set pack-off and P/T to 300 PSI low for 5 min and 3000 PSI for 15 Min- good test;Rig down Chain binders, flow line/hole fill lines and flow riser.
Break bolts on stack and pull annular and diverter-T. Remove 21 1/4" adapter flange from well head. Clear and clean cellar.;Dragon Boxes Loaded 170 bbls
Total Dragon Boxes 1245 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 832 bbls
Losses Downhole 25 bbls
Total Losses Downhole 99 bbls
8/15/2022 Assisted Cactus WHR w/ N/U of multi bowl, Tested P-seals to 3000 psi for 15 min (ok). Cont. working hauling off fluid, cleaning tank bottoms and building new
6% KCL PHPA mud.;Tailed in on bridge cranes and set on well head, singled gate & mud cross, double gate, and annular. Worked on hammering up BOP stack
components. Cont. working pit cleaning and building mud. Loaded out misc. and hauled to staging pads.;Crew change, held PTSM. Hammered up BOP stack
components. While N/U BOP's , IP was swinging sledge hammer, went to hit hammer wrench, not making full contact. The force of the hammer caused the IP'S
hand holding the handle of the sledge hammer to come;into contact with the BOP stack. In result smashing his finger. The hand was taken to the medic for
examination and told to rest for the night and keep it elevated.;Hooked up koomey line to stack. Inspected fluid end on both MP's. Installed cover plates on
diverter flanges, loaded diverter system onto trailers and hauled to J pad. Started building 2nd batch of new;6% KCL PHPA mud. Attempted to open ram doors
on rental double gate, unable to break all bolts loose. Broke hammer wrench trying. Had 2 new hammer wrenches flowing to Beluga.;Choke hose would not go
on in the position the mud cross was in, broke bolts turned mud cross and torqued flanges back up. Hooked up choke and kill lines. Changed out hydraulic
fittings on double gates with proper fittings. With hammer wrenches broke remaining bolts on ram doors inspected lower;With hammer wrenches broke
remaining bolts on ram doors inspected lower pipe rams- good. Cont. building second batch of 6% KCL PHPA mud.;Install blind rams and 2 7/8" x 5" upper
rams, close and tighten doors. R/U bell nipple on top of bag- R/U flow box and flow line.;Rig up BOP test equipment with 4.5" test Jt purge air from system and
attempt shell test. Observed leaking flange on the well head to LPR connection tightened and pressure back up for shell test. Bell nipple on top of bag began to
leak making it difficult to see any leaks on the stack. Bled pressure;off and fixed leaking bell nipple.;Dragon Boxes Loaded 170 bbls
Total Dragon Boxes 1415 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 624 bbls
ISO Tanks Total 1456 bbls
Losses Downhole 0 bbls
Total Losses Downhole 99 bbls
8/16/2022 Cont. chasing leaks on BOP stack. Noticed upper ram door service break on ODS leaking, hammered up ram door bolts (ok). Removed test jt. Functioned all
rams and choke valves , cont. to purge out air out of system. At 06:40 received phone call from medic about;personal needing attention for a cardiac issues.
Guardian was notified and flew into Beluga at 07:50 hrs. patient was transported to helicopter and put in care of Guardian at 7:55 am. Patient was flown to
Providence hospital in Anchorage. Cont with shell testing, BLM Rep Allie;Schoessler on location at 10:00, Quadco Rep on location at 11:00.;Quadco tested
audio and visual gas alarms with no issue and was released. Tested annular at 250 low, 5000 high at 5/10 min with no issues. Attempted to test upper and lower
pipe rams and not able to get a test low or high. Found and fixed a hydraulic leak on upper double gate, functioned both sets;rams numerous times and
attempted to test upper rams again. Fluid going right through rams (variables) and down flow line. Drained stack and opened ram doors. Lower rams sealing
elements were damaged, CO rams. Upper ram sealing elements did not look damaged but replaced same.;Re-installed rams and buttoned up ram
doors.;Pressure test Lower 4.5" Rams to 250/3500 psi and Upper 2 7/8" x 5" rams to 250/5000 psi for 5/10 min each good test. Cont. with remainder of test @
3500 psi high as per test order. Close blinds and P/T to 250/5000 psi 5/10 min each-good test. Perform draw down and record closing times and
pressures;Change out IBOP assembly from top drive, sim-ops rig up Halliburton Geo-Span. Hyd. actuator on Upper IBOP wouldn't cycle, had to remove and
take to shop for trouble shooting.;Pull test plug and install wear ring ( 9" I.D. );Rig up and P/T 7 5/8" CSG to 3500 psi for 30 mins- good test. Pumped 72.5 gal.
bled back 72.5 gal. Blow down choke and kill lines and R/D testing equipment;Drain MGS and choke manifold, blow down kill line, R/D testing equipment;P/U
and install IBOP assembly, P/T Upper IBOP to 250/3500 psi for 5/10 min each. Good test;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 1415 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 1456 bbls
Losses Downhole 0 bbls
Total Losses Downhole 99 bbls
pg p g
Halliburton pumped 58 bbls 10.5 ppg Tuned Spacer at 4 bpm- 128 psi;dropped bottom plug and pumped 156 bbls (370 sx) 12.0 ppg Type I II leadgppppg p p p pp p g p p ( )ppg yp
cement at 4.9 bpm- 280 psi, followed by 35.3 bbls (175 sx) 15.8 ppg Type I II tail cement at 3 bpm- 197 psi. Halliburton dropped top plug, then displaced with 9.3pp y ()ppg yp p p pp pp g p
ppg Spud Mud at 4.4 bpm 740 psi Halliburton dropped top plug;then displaced with 9.3 ppg Spud Mud at 4.4 bpm 740 psi. Slowed pump to 2 bpm with 10 bbls to ppg p p p pp pp g p
go. Did bump the plug at 123.5 bbls into displacement (calculated 125 bbls
Cont. chasing leaks on BOP stack
R/U Parker casing tongs & handling equip. Loaded 7-5/8" casing on catwalk pipe racks
SC cemented. Good returns. No losses. -WCB
)p(p)
Had 58 bbls of Spacer returns to surface and 35 bbls lead cement to surface. Added LCM to lead cement (Bridge Maker at 2.4 pps. Mix water temp
pg p (
p
55 deg. Pumped 50% excess on both lead and tail. No losses throughout the job.
M/U and g g
Bakerloc 7-5/8" shoe track. attempted to tested shoe track floats w/ no luck, M/U XO and pumped through floats (ok). Retested floats w/ out pumping (ok).
gg gqp g pp
pppg()
Cont. running 7-5/8" 29.7# L-80 CDC surface casing as per run tally F/122'-T/1195', installing centralizer's on every other jt
gyppg
Fluid going right through rams (variables) and down flow line. Drained stack and opened ram doors. Lower rams sealing pppggggg() p
elements were damaged, CO rams. Upper ram sealing elements did not look damaged but replaced same.;Re-installed rams and buttoned up ramgppg gp p
doors.;Pressure test Lower 4.5" Rams to 250/3500 psi and Upper 2 7/8" x 5" rams to 250/5000 psi for 5/10 min each good test. Cont. with remainder of test @ ppp p g
3500 psi high as per test order. Close blinds and P/T to 250/5000 psi 5/10 min each-good test. Perform draw down and record closing times andpg p
pressures;Change out IBOP assembly from top driv
8/17/2022 Tested IBOP at 250/3500 for 5/10 min, good test. RD test equipment while staging GeoSpan unit in cellar. Tied GeoSpan into mud line and ran dump line to pits.
Pressure tested Geo Span unit and plumbing at 3500 psi with no issues.;Racked and tallied 60 jnts 4 1/2" DP, staged mule shoe for PU.;MU mule shoe on
single, cont PU single in hole total 60 jnts 4 1/2" DP to 1862'.;MU topdrive and CBU one time at 209 gpm-146 psi.;POOH racking back 30 stands DP in
derrick.;Tallied 40 more joints 4 1/2" DP, PU singled in hole to 1324'.;MU topdrive and CBU one time, 112 gpm-53 psi.;POOH racked back 20 stands 4 1/2" DP,
LD mule shoe.;Held PJSM with Sperry and rig crew. PU 4 3/4" mud motor with 1.5° bend, MU 5 blade PDC, MU DM and PCG collars, scribed same with an RFO
of 194.02°. MU ADR, PWD and TM HOC collars. Plugged in and uploaded MWD tools. PU NM flex DC's, RIH with HWDP and shallow pulse tested.;Cut and slip
drilling line ( cut 43' ) Calibrated blocks and tested Crown-o-matic.;RIH with 6 3/4" drilling assembly F/718' T/2722' washing down F/2638', 200 gpm, 678 psi, 20
rpm, 6K TQ, tagging top of float @ 2722' with 8K WOB, PU- 58K, SO-39K, ROT- 44K.;Drill out shoe track and 20' of new formation F/2722' T/2833', 200 gpm,
1325 psi, wob 3-7K , 45 rpm, 6-7K TQ, ROT-45K, PU-60K, SO-40K, MW-9.2 ppg, Acquired SPR's 30/40 spm- #1-430/530 psi, #2-430/530 psi, worked through
float collar several times with no issues.;Displace well from 9.2 ppg spud mud to 9.0 ppg 6% KCL PHPA mud, 200 gpm, 1200 psi, 45 rpm, 6.5K TQ working
through shoe several times with no issues.;R/U and perform LOT to 706 PSI- 14.3 ppg EMW, pumped 17.5 gal, bled back 15 gal. Blow down choke and kill lines
and R/D testing equipment;Dragon Boxes Loaded 85 bbls
Total Dragon Boxes 1500 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 1560 bbls
Losses Downhole 0 bbls
Total Losses Downhole 99 bbls
8/18/2022 Drilled 6 3/4" hole from 2833’ to 3102'. Rot wob 3K, 248 gpm-1226 psi, 40 rpm-6300 ft/lbs on bott torque, 100 ft/hr ROP. Sliding wob 1K, 250 gpm-1125 psi, 66
psi diff, 26 ft/hr ROP. MW 9.0/vis 40, ECD’s at 9.8 ppg, BGG 4 units. Both shakers dressed at 170's.;Cont drilling 6 3/4" hole from 3102' to 3441'. Rot wob 3K,
248 gpm-1077 psi, 55 rpm-6923 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 1-2K, 245 gpm-1001 psi, 20 psi diff, 40 ft/hr ROP. MW 9.0/vis 46, ECD’s at 10.0
ppg, BGG 7 units, max gas 67 units.;Cont drilling 6 3/4" hole from 3441' to 3816', wob 3-5K, 230 gpm-1045 psi, 60 rpm-7.5-8K TQ on bott, 120 ft/hr ROP.
Sliding wob 1-3K, 235 gpm-962 psi, 42 psi diff, 80 ft/hr ROP. MW 9.2/vis 48, ECD’s at 10.1 ppg, BGG 6 units, max gas 75 units. Shoot survey, PU-70K, SO-40K,
ROT- 55K.;Pump #2 pod #1 discharge pod has washed out behind the seat in the same location. Applied JB weld- allowing it to cure up and smooth out and
utilize pump #2 as a back up.;CBU, 250 gpm, 1020 psi, 65 rpm, 7K TQ, ECD's-9.9 ppg, max gas- 8 units. Observed 30% increase in cuttings at BU, Circulated
until shakers cleaned up. SPR's 30/40 spm-#1 285/350, Monitor well- slight seepage.;POOH on elevators F/3816' T/2761', with no issues, PU-58K, So-40K, Cal
disp.=6.4 bbls, Act disp.= 8 bbls, Diff= 1.6 bbls.;Grease Top drive, Drawworks, Break linkage, Iron roughneck, Blocks, Crown. Static loss rate= 1 bph.;RIH on
elevators F/2761' T/3756', washed down last stand to 3816', 2 bpm, 350 psi no rotation. Tagged 8' of fill. Cal disp= 20 bbls, Act disp= 17.5 bbls, Diff=2.5
bbls.;Pumped a 20 bbl Hi-vis sweep STS, 200 gpm, 900 psi, increased pumps to 240 gpm, 956 psi @ BU, 65 rpm, 8.2K TQ, ECD's-9.8 ppg, max gas- 49 units.
Hole unloaded fines with 30% increase 600 stks before BU and didn't fall off until BU was achieved. Sweep back on time with 20% increase in cuttings.;Cont
drilling 6 3/4" hole from 3816' to 3900', wob 3K, 230 gpm- 1057 psi, 160 diff, 60 rpm-8.6K on bott, 120 ft/hr ROP. Sliding wob 1-3K, 250 gpm-1040 psi, 95 psi
diff, 30 ft/hr ROP. MW 9.0/vis 44, ECD’s at 9.8 ppg, BGG 6 units, max gas 84 units. PU-78K, SO-48K, ROT- 56K.;Distance to plan 4.95', Low 3.03', Left 3.92',
Pump #2 is put back together and will be used as a secondary pump.;Dragon Boxes Loaded 170 bbls
Total Dragon Boxes 1670 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 1664 bbls
Losses Downhole 0 bbls
Total Losses Downhole 99 bbls
8/19/2022 Cont to drill 6 3/4" hole from 3900' to 4187'. Sliding wob 5K, 244 gpm-1028 psi, 50 psi diff, 20 ft/hr ROP. Rot wob 2K, 227 gpm-915 psi, 65 rpm-8003 ft/lbs on
bott torque, 114 ft/hr ROP. MW 9.0/vis 44, ECD's at 9.6 to 9.8 ppg, BGG 22 units, max gas 252 units. At 4125' adjusted topdrive torque;up to 14,000 ft/lbs for
drilling. At 4165' md/3843' tvd we started losing return flow. Reduced to 150 GPM-720 psi, 65 rpm-8700 ft/lbs, reduced ROP to 50 ft/hr. Flow up and down, 0 to
12% returns. At 4187' backreamed one time with occasional returns, seeing fine sand/sandstone on shakers.;Backreamed one time while building 25 bbls LCM
pill consisting of baracarb 5, 25 and 150, vanguard fine and baratrol. Parked at 4157'. Pumped 22 bbls of 45 ppb LCM pill and spotted outside drill string. Have
lost 260 bbls total for the day at this point.;Pulled up hole on elevators from 4157' to 2818' parking the bit 10' outside surface shoe. First 5 stands pulled we
started getting returns with hole on trip tank, 5 to 8%. Hole fill went from 4.6 to 2.6 per 5 stands the more we pulled. Filling premix tank with water to build more
volume.;CBU one time at 206 gpm-727 psi with little to no losses. No increase in cuttings to surface at bottoms up. Shut down and put well on trip tank,
alternated from TT to rig pump every 15 minutes, crew building 150 bbls new mud in pre-mix. 1 bph loss rate on trip tank.;Eased in hole from 2818' to 4063' with
no issue. down wt 40K. Filled pipe and washed 2nd to last stand down at 83 gpm-420 psi to 4123'. MU last stand and washed/reamed down to bottom at 82 gpm-
402 psi, 20 rpm-7385 ft/lbs, 7% flow. Made hook and obtained survey on bottom.;Resumed drilling 6 3/4" hole from 4187' to 4246'. 2-8K wob, 151 gpm-840 psi,
60 rpm-8463 ft/lbs on bott torque, 50 ft/hr ROP, 11-12% return flow. At 4214' md/3895' tvd we started losing returns again. Seeing occasional returns as we
drilled stand down.;Back reamed std and stopped @ 4213', Pumped 22 bbls of 60 ppb LCM pill consisting of baracarb 5, 25 and 150, vanguard fine and Pac-L.
Have lost 573 bbls so far since encountering loss zone.;POOH F/4213' T2817', 10' outside of shoe. 5% returns once on hole fill and increased to 8% over the
first 5 stds. Hole fill went from 3.4 bbls first 5 stands to calculated the remaining stands.;CBU one time at 206 gpm-970 psi with little to no losses. No increase in
cuttings to surface at bottoms up. Shut down and put well on trip tank, alternated from TT to rig pump every 15 minutes, crew building 150 bbls new mud in pre-
mix. .5 bph loss rate on trip tank.;RIH F/2817' to 4122' with no issue. Down wt 40K. Filled pipe and washed last 2 stand down no rotation at 78 gpm-423 psi
setting 5K down stalling mud motor @ 4214'. Reamed F/4214' T/4246' 143 gpm, 689 psi, 20 rpm, 8.3K TQ, 15% flow taking 2-3K wob to work through F/4214'
T/4221'.;Resumed drilling 6 3/4" hole from 4246' to 4329'. 2-5K wob, 150 gpm-1060 psi, 50 rpm-7.8 ft/lbs on bott torque, 50 ft/hr ROP, 11-12% return flow. At
4329' ( 4002' TVD ) picked up off bottom in attempt to slide shut off rotary flow went to 0% loosing returns.;Turned rotary back on and went back to bottom and
regained returns at 10% flow. Distance to plan 4.84', High 1.01', Left 4.72';Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 1670 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 1664 bbls
Losses Downhole 573 bbls
Total Losses Downhole 672 bbls
@ 4213', Pumped 22 bbls of 60 ppb LCM pill
q ggp
Cont drilling 6 3/4" hole from 3102' to 3441'.
q
Turned rotary back on and went back to bottom and()pp p
regained returns at 10% flow. Distance to plan 4.84',
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At 4214' md/3895' tvd we started losing returns again
gy g gp
Drill out shoe track and 20' of new formation F/2722' T/2833',
Drilled 6 3/4" hole from 2833’ to 3102'.
Pu
Cont to drill 6 3/4"hole from 3900' to 4187'.
qg
Cont drilling 6 3/4" hole from 3441' to 3816',
8/20/2022 Cont drilling 6 3/4" hole from 4329' to 4434'. Rot wob 5-6K, 143 gpm-1012 psi, 50 rpm-8044 ft/lbs on bott torque, 10-30 ft/hr ROP, MW 9.0+/vis 56, ECD's at
9.7+ ppg, BGG 8 units, max gas 23 units, up wt 84K, dwn wt 78K. At 4329' md/4002' tvd return flow dropped from 11% to 0% when we;picked up off bottom and
stopped rotating attempt a slide. Resumed rotating and went back to bottom, started getting return flow back up to 9% then 10%. Made hook and resumed
drilling ahead with an initial loss rate of 25 bph that only got better as we drilled ahead.;Cont drilling 6 3/4" hole from 4434' to 4496'. Rot wob 6K, 147 gpm-958
psi, 50 rpm-8118 ft/lbs on bott torque, 15 to 30 ft/hr ROP. At 4489' md/4159' tvd return flow dropped from 11% to 4%, then up and down between 4 and 7%. As
we drilled last 7' down flow dropped to 0%. Backreamed;stand one time then parked at 4460' to spot LCM pill.;Pumped 22 bbls of 60 ppb LCM and spotted
outside drill string. Fluid on backside dropped out of sight. Attempted to fill hole with trip tank and could not. RU charge pump to hole fill and managed to top off
hole with charge pump from active system.;Pulled up hole from 4460' to 4432' with no issue, up wt 80K, fluid on backside dropped out of sight again, cont to fill
with charge pump from active system at higher rate. Cont to pull up hole on elevators to 3685' to get above initial loss zone, able to keep hole full and get
returns.;MU topdrive at 3685', bit parked in a sand/sandstone, attempted to CBU at 120 gpm-654 psi and getting 11% return flow. Shaker #1 went down with an
electrical issue. Shut down mud pump, hole static, put 4 140 screens on shaker #2 while electrician worked shaker #1, cont CBU at 120 gpm.;671 psi, no losses
during circ, no gas at bottoms up. Shut down and put hole on trip tank.;Rig electrician and mechanic cont working on shaker #1, crew building 150 bbls in pre-
mix pit, serviced rig and topdrive, worked pipe on occasion with no issue, alternated from rig pump to trip tank and cont to build the 150 bbls in pre-mix pit.;RIH
F/3687' T/4436', washed down F/4436' T/4492' setting down 5K stalling motor, Reamed through to btm-114 gpm, 684 psi, 20 rpm, 8.5K TQ, 11-12% flow, PU-
77K, SO 53K.;CBU, 140 gpm, 705 psi, 20 rpm, 8.5K TQ, 11% flow.;Resume drilling ahead F/4496' T/4638', 145 gpm, 990 psi, Diff- 150 psi, 50 rpm, 9K TQ,
wob-2-5K, max gas=9 units. PU-90K, SO-54K, ROT-65K. At 4620' flow dropped from 11% to 0 while coming down from a 30' back ream, slowed pumps down to
an idle and stopped rotation cont. messing with parameters.;with no success getting returns. While Crew was making a 25 bbl/60 ppb LCM pill, made a hook
and cont. drilling T/4638' observing flow slowly increasing to 8%, Due to fluid availability POOH to 4610' , Lost a total of 158 bbls while drilling.;Spotted a 22
bbl/60 ppb LCM pill, 89 gpm, 380 psi, once LCM pill was at the bit increased flow rate to 195 gpm, 970 psi, with 7% flow.;POOH F/4610' T/3969', no issues. PU
78K, SO 54K.;CBU, 200 gpm, 900 psi, 20 rpm, 8K TQ. Let pill soak while alternated from rig pump to trip tank while crew is building 150 bbls in pre-mix
pit.;Dragon Boxes Loaded 85 bbls
Total Dragon Boxes 1755 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 1664 bbls
Losses Downhole 225 bbls
Total Losses Downhole 897 bbls
8/21/2022 Bit parked at 3969', finished mixing up last of 150 bbls 6% KCL mud in pre-mix pit while alternating from mud pump to trip tank on hole, moving drill string on
occasion. 229 gpm-1142 psi.;Eased in hole on elevators from 3969' to 4576' with no issues. MU topdrive, filled pipe then washed and reamed to bottom at
4638'.;Resumed drilling 6 3/4" hole from 4638' to 4807'. Rot wob 2K, 207 gpm-1280 psi, 60 rpm-8186 ft/lbs on bott torque, 50 to 80 ft/hr ROP, MW 9.0/vis 51,
ECD's at 10.1 ppg, BGG 22 units. Bottoms up gas 44 units, trip gas 146 units. Dressed shakers with 140 screens to keep more LCM in active.;At these drilling
parameters BHA dropping slightly and walking left slightly. No losses.;CBU at 207 gpm-1191 psi, 60 rpm-8877 ft/lbs off bott torque, ECD's dropped to 9.8 ppg,
obtained SPR's and made hook.;Cont drilling from 4807' to 5078', rot wob 5K, 204 gpm-1157 psi, 50 rpm-8928 ft/lbs on bott torque, 30 to 50 ft/hr ROP (slowed
rpm to try and walk BHA to the right and drop Inc), MW 9.0/vis 51, ECD's 10.0 ppg, BGG 25 units, max gas 54 units. BHA cont to walk left. Sliding wob 1K, 194
gpm-1000.;psi, 43 psi diff, 20 ft/hr ROP. Resumed rotating at 206 gpm-1321 psi, 60 rpm-9750 ft/lbs on bott torque. Mudlogger saw the top of "G" formation at
5056' md/4714' tvd. Distance to well plan- 7.02', High- 3.58', Left- 6.04'.;CBU at 212 gpm-1097 psi, 60 rpm-9715 ft/lbs off bott torque. BGG 12 units.;POOH
F/5178' T/4615' with 5-10K drag up to 4645', PU-92K, SO-50K, Cal Disp.=3.2 bbls, Act Disp.=6 bbls, Diff-2.8 bbls.;RIH on elevators F/4615' T/5117', no issues,
washed down last std at 60 gpm, 520 psi= no fill Cal Disp= 9.9 bbls, Act Disp=8.8 bbls, Diff=1.1 bbls.;Circ. open hole volume 202 gpm,1120 psi, observing 1280
units of gas at 963 stks ( 1/2 OH Volume ). Pumped 20 bbls Hi-vis/walnut sweep STS starting out at 208 gpm, 1356 psi, 13% flow, 60 rpm, 10K TQ. At 1850 stks
( sweep half way up OH ) Flow decreased from 13% down to 4%, decreased parameters.;to 125 gpm, 25 rpm with no change in flow. Increased flow rate up to
180 gpm, 833 psi, 4% flow, 25 rpm, 9.8K TQ. Sweep back 1400 stks late ( 88 bbls ). Once sweep was at shakers flow slowly increased from 4% to 12%. Cont.
pumping observing minimal to no losses at full rate. Lost a total of 206 bbls.;Monitor well for 10 Min- slight seepage. POOH F/5178' T/719' with no issues.
Monitored well on TT at shoe for 10 min= No Gain/Losses, PU 94K, SO-56K off bottom. Cal Disp.= 29.4 bbls, Act Disp= 31.9 bbls, Diff= 2.5 bbls.;Rack back
HWDP and Jars F/719' T/157', Rack back 1 std of NM drill collars removed corrosion ring from top collar.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 1755 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 1664 bbls
Losses Downhole 18 bbls
Total Losses Downhole 915 bbls
Circ. open hole volume 202 gpm,1120 psi, observing 1280 gp p p p p gp p g
units of gas at 963 stks ( 1/2 OH Volume ). Pumped 20 bbls Hi-vis/walnut sweep STS starting out at 208 gpm, 1356 psi, 13% flow, 60 rpm, 10K TQ. At 1850 stksg( )p
( sweep half way up OH ) Flow decreased from 13% down to 4%,
gp
Cont drilling 6 3/4" hole from 4434' to 4496'.
q
BHA cont to walk left
gp p
Resumed drilling 6 3/4" hole from 4638' to 4807'.
Cont drilling 6 3/4" hole from 4329' to 4434
gg
Resume drilling ahead F/4496' T/4638',
yggy
Cont drilling from 4807' to 5078',
8/22/2022 Cont racking back HWDP and jars to TM HOC collar. Plugged in and down loaded MWD data. LD smart tools, flushed motor and broke off bit. Closed blind
rams. Bit graded a 1-1 and in gauge. Calc BHA hole fill = 9.8 bbls, actual hole fill = 10.7 bbls.;C/O Sperry encoder hardware on draw works, C/O saver sub,
serviced rig/topdrive/blocks and crown.;Held PJSM, opened blinds and MU cementing BHA (6 ¾” tri-cone, no jets, bit sub with float, 6 ½” integral blade stab, XO,
HWDP, jars, HWDP) to 569’. TIH to 1932’ and had to replace a hydraulic hose on iron roughneck, MU topdrive on drill string.;Rig mechanic replaced hydraulic
hose on iron roughneck, re-routed hoses to eliminate any further issues. Filled pipe and circulated during repair.;Cont TIH filling pipe at 2735’ prior to exit surface
shoe. Cont trip in open hole from 2808' to 4438' slowly. No issues. At 4438' LD top single of stand #63 and MU 15' pup joint. MU topdrive and filled pipe at 4450'.
Called out cementers.;Staged up pump rate to 187 gpm-332 psi. Had a max of 96 units prior to bottoms up. Lost 1 bbl over one hour circ time. Layed out liner for
trucks to park on. Halliburton staged pump and bulk trucks. Assembled cement head (5' pup, TIW, pump in sub, 15' pup). RU transfer hose and hardline.;Held
PJSM with Halliburton and rig crews. Shut down rig pump and broke off topdrive. Installed cement head and 2" cement hose.;Halliburton loaded lines with 5 bbls
water and checked for leaks, shut in at rig floor, pressure tested lines at 900 psi low, 2870 psi high, good tests, Halliburton pumped 15 bbls water at4 bpm-450
psi, followed with 20 bbls 15.8 ppg Type I II cement with 1 pps LCM at 4 bpm-580 psi, followed with;11 bbl water, then displaced with 45.8 bbls 9.0+ 6% KCL
mud at 4 bpm-104 to 580 psi at shut down, leaving 4 bbls cement in drill string. CIP at 17:30 on 8-22-22. Lost 8 bbls throughout the job.;Pump unit bled off with
no fluid back to truck, disconnected cement hose from cement head, removed Lo-Torque valve from pump in sub (no back flow), broke off cement head and LD
same, PU top single of stand #63 and MU, pulled up hole 8 stands at 15 ft/min from 4450' to 3973', up wt 78K.;First 7 stands were wet, 8th pretty much dry. At
3973' pulled 8 more stands to 3470' at 60 ft/min. No issues tripping up hole. Cal Disp.= 6.3 bbls, Act Disp= 7.2 bbls, Diff= .9 bbls.;Pump Lo-vis/walnut sweep
around 235 gpm, 335 psi, 20 rpm, 5.8K TQ. No cement at surface.;Alternate between MP's and hole fill every 15 min while WOC, pressure wash rig floor, stage
materials at hopper for cement contaminated mud.;RIH on elevators F/3475' T/4159', setting 3K down, PU- 78K, SO-48K, Cal Disp= 10.1 bbls, Act Disp= 9 bbls,
Diff= 1.1 bbls.;Drill up cement plug F/4159' T/4458', 202 gpm, 365 psi, 50 rpm, 7.7K TQ, wob-1-4K, ROP-100 observed good cmt at shakers BU stks Depth of
4159' over boarding 48 bbls . Observed wob fall off @ 4458'. PU- 78K, SO-48K, ROT-58K.;Cement returns at each depth 4200' 60% cmt, 4260' 80% cmt, 4350'
98% cmt, 4450' 100% cmt.;Washed & reamed F/4458' T/4782', 202 gpm, 375 psi, 64 rpm, 8.1K TQ, 300 fph. At BU depth of 4458' observed gas increase to 681
units.;CBU- 209 gpm, 360 psi, 20 rpm, 8.3K TQ, max gas 591 units at BU, CMTR's called out once circulating.;P/U cementing assembly and RIH T/4795', Hold
PJSM with CMTR's, crew, Mud engineer and CCI. Halliburton loaded lines with 5 bbls water and checked for leaks, shut in at rig floor, pressure tested lines at
840 psi low, 2853 psi high, good tests.;Dragon Boxes Loaded 180 bbls
Total Dragon Boxes 1935 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 1664 bbls
Losses Downhole 214 bbls
Total Losses Downhole 1129 bbls
8/23/2022 Halliburton pumped 15 bbls water at 4 bpm-440 psi, followed with 20 bbls 15.8 ppg Type I II cement with 1 pps LCM at 4 bpm-400 psi, followed with 11 bbl
water, then displaced with 50.5 bbls 9.0+ 6% KCL mud at 4 bpm-105 to 600 psi at shut down, leaving 4 bbls cement in drill string.;CIP at 06:30 on 8-23-22. No
losses throughout the job.;Pump unit bled off with 2 bbls fluid back to truck, disconnected cement hose from cement head, removed Lo-Torque valve from pump
in sub (no back flow), broke off cement head and LD same, pulled up hole 8 stands at 15 ft/min from 4794' to 4283', up wt 90K. 8th stand pulled dry. Cont pull
up;hole 7 more stands from 4283' to 3852' at 60 ft/min pulling dry. MU topdrive.;Broke circ staging up to 231 gpm-337 psi and pumped a 22 bbl lo-vis nutplug
sweep around. 20 rpm-7096 ft/lbs off bott torque, no cement to surface and no losses. Shut down pump.;Alternated between rig pump and trip tank every 15
minutes, pumping at 196 gpm-276 psi, 23 rpm-7050 ft/lbs off bott torque. No losses.;Eased in hole on elevators from 3852' to 4338', down wt 52K, and saw 1K
wob. Pulled up hole to 4312', MU topdrive and filled pipe. Welder and Inspector welded up gen skid fuel tank.;Staged pump rate up to 206 gpm-326 psi, 50
rpm-7300 ft/lbs off bott torque. Wash and ream down at 5 ft/min seeing 1-2K wob at 4343', 1-2K wob at 4408', 2K wob at 4543', 3.5K at 4569', 4K wob at 4741'.
Through bottom of plug at 4800' with little to no wob, at bottoms up had a max of 411 units gas.;20% cement at 4340', 15% cement at 4490', 30% cement at
4590', 80% cement at 4800'.;Cont to wash and ream down hole from 4839' to 5090' at 200 gpm-378 psi, 50 rpm-8716 ft/lbs off bott torque, 2-4K wob. MW up to
9.3 ppg/vis 45. 85% formation at 4900', 90% formation at 4950', max gas 286 units.;At 5090' CBU at 204 gpm-361 psi, 50 rpm-8900 to 9300 ft/lbs off bott torque,
up wt rotating 72K, dwn wt rotating 68K. Cementers on location, shut down pump, broke off topdrive.;PU and MU cement head on string, S/O to 5102'. MU Lo-
Torque valve and cement hose, lined up on mud pump and cont to circ at idle while holding PJSM with cement and rig crew. Shut down and lined up to pump
truck.;Halliburton loaded lines with 5 bbls water and checked for leaks, shut in at rig floor, pressure tested lines at 250 psi low, 3443 psi high, good tests,
Halliburton pumped 15 bbls water at4 bpm-400 psi, followed with 20 bbls 15.8 ppg Type I II cement with 1 pps LCM at 4 bpm-580 psi, followed with;11 bbl water,
then displaced with 55 bbls 9.3 6% KCL mud at 4 bpm-45 to 600 psi at shut down, leaving 4 bbls cement in drill string. CIP at 18:47 on 8-23-22. No losses
throughout the job.;Pump unit bled off with 0 bbls fluid back to truck, disconnected cement hose from cement head, removed Lo-Torque valve from pump in sub
(no back flow), broke off cement head and LD same, pulled up hole 8 stands at 15 ft/min from 5102' to 4592', up wt 92K. Cont to pull up hole at 60 ft/min.;from
4592' to 4030' (pulled 9 stands rather than 7 to get bit up above previous loss zone and coals), up wt 80K, pipe never pulled dry. Halliburton cementers washed
up and released, staging trucks for return barge to Kenai.;MU topdrive and staged up to 209 gpm-286 psi and pumped 22 bbls lo-vis nut plug sweep around with
20 rpm-7500 ft/lbs off bott torque. Saw no cement to surface at bottoms up or with sweep to surface.;Alternate between rig pump and trip tank every 15 minutes,
pumping at 209 gpm-297 psi, 20 rpm-7555 ft/lbs off bot torque. Giving cement 6 hrs to set up. No losses were observed.;P/U Cement head from catwalk and
break down.;RIH on elevators f/4029' t/ 4591'. Fill pipe and break circulation. Tag cement @4644'. P/U-78k S/O-52K.;Wash and ream f/4644' 200GPM 330PSI
60RPM 8.8k tq 1-2K WOB, at 4740' 2-4kWOB, at 4835' assembly taking a constant 4k WOB at 30-40'/hr. P/U-86k S/O-54K ROT-68K.;2% cement at 4650', 2%
cement at 4700', 3% cement at 4750', 5% cement at 4780', 98% cement at 4815', 99% cement at 4830', 99% cement at 4850', 100% cement at 4875', 100%
cement at 4885', 100% cement at 4900'. 100% cement at 4920'.;Dragon Boxes Loaded 160 bbls
Total Dragon Boxes 2095 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 208 bbls
ISO Tanks Total 1872 bbls
pp
Giving cement 6 hrs to set up. No losses were observed
pp
Drill up cement plug F/4159' T/4458
gp p p q
PU and MU cement head on string, S/O to 5102'. MU Lo-pg g pp p g
Torque valve and cement hose, lined up on mud pump and cont to circ at idle while holding PJSM with cement and rig crew. Shut down and lined up to pump qppp ggpp
truck.;Halliburton loaded lines with 5 bbls water and checked for leaks, shut in at rig floor, pressure tested lines at 250 psi low, 3443 psi high, good tests,gp
Halliburton pumped 15 bbls water at4 bpm-400 psi, followed with 20 bbls 15.8 ppg Type I II cement with 1 pps LCM
pp y pg ppj ppp
Called out cementers.;Staged up pump rate to 187 gpm-332 psi. Had a max of 96 units prior to bottoms up. Lost 1 bbl over one hour circ time. Layed out liner forgppp gp p p p y
trucks to park on. Halliburton staged pump and bulk trucks. Assembled cement head (5' pup, TIW, pump in sub, 15' pup). RU transfer hose and hardline.;Heldpgpp(pp p p pp)
PJSM with Halliburton and rig crews. Shut down rig pump and broke off topdrive. Installed cement head and 2" cement hose.;Halliburton loaded lines with 5 bblsggppp
water and checked for leaks, shut in at rig floor, pressure tested lines at 900 psi low, 2870 psi high, good tests, Halliburton pumped 15 bbls water at4 bpm-450gp p pgg pp p
psi, followed with 20 bbls 15.8 ppg Type I II cement with 1 pps LCM at 4 bpm-580 psi, followed with;11 bbl water, then displaced with 45.8 bbls 9.0+ 6% KCLp ppg yp pp p p p
mud at 4 bpm-104 to 580 psi at shut down, leaving 4 bbls cement in drill string. CIP at 17:30 on 8-22-22. Lost 8 bbls throughout the job.;
Halliburton pumped 15 bbls water at 4 bpm-440 psi, followed with 20 bbls 15.8 ppg Type I II cement with 1 pps LCM at 4 bpm-400 psi, followed with 11 bblppp p ppg yp pp pp
water, then displaced with 50.5 bbls 9.0+ 6% KCL mud at 4 bpm-105 to 600 psi at shut down, leaving 4 bbls cement in drill string.;CIP at 06:30 on 8-23-22. No p
losses throughout the job
8/24/2022 Cont drilling cement from 4920', wob 6K, 213 gpm-392 psi, 75 rpm-9100 ft/lbs torque, 40 to 60 ft/hr ROP, MW 9.2/vis 39, BGG 7 units. At 5051' ROP increased
from 1 ft/min to 5 ft/min. At 5100' wob dropped off, cont washing and reaming down to bottom at 5178'.;CBU at 203 gpm-377 psi, 45 rpm-9800 ft/lbs torque. No
increase in cuttings at bottoms up. Pumped a 20 bbl hi-vis nutplug sweep around that was back on time and maybe 10% increase in cuttings. BGG 2 units. No
losses. 10 minute flow check was static.;Racked back one stand then L/D top single of stand #74. Cont POOH on elevators, up wt 102K. No issues tripping in
open hole, no issue pulling into surface casing. Pulled to BHA at 569'.;Racked back HWDP, L/D jars, stab, float sub and bit. Tri-Cone bit graded at 1-2 and in
gauge. Closed blind rams.;Cleaned and cleared rig floor and catwalk, staged BHA and new jars. Held PJSM with Sperry and rig crew on PU BHA.;MU 6 3/4"
directional BHA as follows: 6 3/4" HDBS PDC 4 3/4" motor 1.5° bend, DM, PCG, ADR, ALD, CTN, Geo-Tap collars, 6 1/2" IBS, plugged in and uploaded MWD,
Shallow pulse test @ 235GPM 900PSI test good. Install nuclear sources. P/U flex collars and jars.;RIH on HWDP t/764', RIH on DP from derrick t/2622'. Fill
pipe and break circulation.;RIH f/2622' t/3920'. No issues. P/U-80k S/O-50K. Fill pipe and break circulation. 65GPM 950psi to get flow then pressure dropped to
540psi.;Continue RIH f/3920' t/5035' No issues. Fill pipe 70GPM 1025psi to get flow then pressure dropped to 650psi. Wash last two stands to bottom GPM-157
PSI-915 RPM-30 Tq-8.5k. Losses to hole during trip 5.5bbls. P/U-108 S/O-60 ROT-80k.;Resume drilling 6-3/4" production hole as per Sperry WP09. F/5178'
T/5232' GPM-200 PSI-1310 RPM-50 TQ-9k DIFF-175PSI.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 2095 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 1872 bbls
Losses Downhole 0 bbls
Total Losses Downhole 1129 bbls
8/25/2022 Cont drilling 6 3/4" hole from 5232' to 5628'. Rot wob 4-5K, 195 gpm-1330 psi, 50 rpm-9408 ft/lbs on bott torque, 50 to 75 ft/hr ROP. MW 9.1+/vis 45, ECD's at
9.8 ppg, BGG 13 units, max gas 120 units. At 5361' increased to 222 gpm-1666 psi, 100 ft/hr ROP. At 5486' increased to 70 rpm-;10,600 ft/lbs on bott torque.
Seeing no stick slip with BHA.;Cont drilling 6 3/4" hole from 5628' to 5842'. Rot wob 5-6K, 229 gpm-1661 psi, 80 rpm-11,300 ft/lbs on bott torque, 100 ft/hr ROP.
MW 9.1+/vis 49, ECD's at 10.6 ppg, BGG 16 units, max gas 120 units. Obtained SPR's at 5781' md/5422' tvd (30 spm = 462 psi).;With stand drilled down
pumped a 20 bbl hi-vis nutplug sweep around at 227 gpm-1470 psi, 80 rpm-11,000 ft/lbs off bott torque. Had 100% increase in cuttings at bottoms up (clay),
10% increase with sweep to surface (100 strokes early). ECD"s dropped from 10.6 to 10.1 ppg.;Cont drilling 6 3/4" hole from 5842' to 5883'. Sliding wob 8-9K,
220 gpm-1844 psi, 380 psi diff, 28 ft/hr ROP. Rot wob 3 to 9K, 70 rpm-10,700 to 11,600 ft/lbs on bott torque, 10 to 80 ft/hr ROP. MW 9.1+/vis 49, ECD's at 10.3
ppg, BGG 6 units, max gas 37 units. ROP slowed significantly at 5870'.;Cont drilling 6 3/4" hole f/ 5883' t/6151' GPM-225 PSI-1900 RPM-70 TQ-10.5-11.5k
WOB-3-8k. At 5889' ROP 10-15'/hr. Adjusted drilling parameters, ROP improved to 40'/hr then back to normal ROP 70-100'/hr at 5903'.;CBU x 1.5prior to wiper
trip GPM-235 PSI-1620 RPM-70 TQ-11-12k.;Obtain SPR's, Flow check well static. Begin 1000' wiper trip t/5178'. Pulled 30k over immediately out of the slips.
Had to pump and rotate to get free. Was able to pull on elevators but was over pulling 20-30k to get moving. Pulled 30k over @ 5808', 5703' was able to work
through. P/U-120k S/O-59.;Pull 30k over at 5678' was not able to work through. Pump OOH t/5560' GPM-210 PSI-1350. Begin backreaming f/5560' t/5344'
GPM-212 PSI-1450 RPM-40 TQ- 10-12K.;Pull on elevators f/5344' t/5101' P/U-110k S/O 58k.;Perform rig service while idling the mud pump on the hole.;RIH on
elevators f/5101' t/6091' with out issue. P/U 115k S/O 60k. Wash stand to bottom 6151' pump sweep around.;Dragon Boxes Loaded 160 bbls
Total Dragon Boxes 2255 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 0 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 0 bbls
Total Losses Downhole 1129 bbls
8/26/2022 At 6151', cont pumping 20 bbl hi-vis nutplug sweep around at 199 gpm-1326 psi, 73 rpm-11,750 ft/lbs off bott torque. Saw 100% increase in clay cuttings at
bottoms up and 112 units trip gas that dropped off quick. With sweep to surface saw a 10% increase in clay cuttings, back on time. Made hook.;Cont drilling 6
3/4" hole from 6151' to 6353'. Initial rot wob 15K, 219 gpm-1599 psi, 70 rpm-10,700 ft/lbs on bott torque, 8 to 30 ft/hr ROP. Reduced to 40 rpm- 4K wob and
increased to 220 gpm, feathered into drilling, seeing 50 to 60 ft/hr ROP. Increased to 50 rpm and seeing 70 to 90 ft/hr ROP.;Increased to 60 then 70 rpm seeing
90 ft/hr ROP, 11,900 ft/lbs on bott torque. MW 9.2/vis 44, ECD's at 10.1 ppg, BGG 5 units, max gas 53 units.;Cont drilling 6 3/4" hole from 6353' to 6710'. Rot
wob 5-10K, 239 gpm-2004 psi, 50 to 80 rpm-12,400 ft/lbs on bott torque, 20 to 110 ft/hr ROP, Sliding wob 7-9K, 237 gpm-1905 psi, 270 psi diff, 40 to 70 ft/hr
ROP. MW 9.2/vis 49, ECD’s at 10.5 ppg, BGG 10 units, max gas 71 units.;Pumped a 20 bbl hi-vis nutplug sweep around at 234 gpm-1629 psi, 80 rpm-12,130
ft/lbs off bot torque. Sweep came back 200 strks early with a 10% increase in cuttings.;Cont. drilling 6-3/4" hole f/6710' t/ 6867' GPM-230 PSI-1560 RPM-60
TQ-13k WOB-5-7k. Sliding GPM-235 PSI-1740 WOB- 1-3K Diff-80PSI ROP-15-20'/hr. DD having to rock the pipe. BGG 20 units, max gas 146 units.;Cont.
drilling 6-3/4" hole f/6867' t/ 7143' GPM-233 PSI-1640 RPM-60 TQ-1.5k WOB-7k. P/U-138k S/O-66k ROT-90k. MW-9.5ppg ECD-10.8ppg BGG 20 units, max
gas 297 units. At 6933' started increasing MW. Distance to plan 27' center to center 18.73' low 19.54' left;Obtain SPR's, CBU GPM-233 PSI-1660 RPM-80 TQ-
13.8k. Continue circulating weighting up to 9.5ppg mud weight.;Dragon Boxes Loaded 80 bbls
Total Dragon Boxes 2335 bbls
Cuttings Totes Loaded 72 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 0 bbls
Total Losses Downhole 1129 bbls
8/27/2022 At 7143' md/6760' tvd, cont circulating and increasing MW from 9.4 to 9.5 ppg prior to wiper trip. 233 gpm-1584 psi, 75 rpm-13,700 ft/lbs off bott torque. 10 min
flow check was static.;Pulled up hole slow on elevators from 7143’, up wt 150K, had to work through a 30K overpull at 6728’, then had to backream a stand from
6323’ to 6273', 193 gpm-40 rpm. Wiped to 6085’ and parked at 6148’, down weight 60K.;Serviced rig and topdrive.;RIH on elevators from 6148' to 7048’ with no
issues, MU topdrive, filled pipe, checked depth, washed/reamed last stand to bottom.;Pumped a 20 bbl hi-vis nutplug sweep around at 198 gpm-1441 psi, 70
rpm-14,700 ft/lbs off bott torque. Had 100% increase in clay cuttings at bottoms up along with 357 units trip gas. Sweep brought back an additional 15% increase
and with shakers clean, gas down to 4 units made hook.;Cont drilling 6 3/4" hole from 7143' md/6760' tvd to 7404'. Rot wob 5-7K, 233 gpm-1753 psi, 70 rpm-
13,800 ft/lbs on bott torque, 60 to 70 ft/hr ROP, increased MW from 9.5 to 9.7/vis 49, ECD's at 10.8 ppg, BGG 12 units, max gas 65 units. Sperry having tool
detection issues on;bottom at 7373', good detection off bottom. Had to mad pass stand from 7330' down to 7391'.;Cont drilling 6 3/4" hole from 7404' to TD at
7489' md/7101' tvd. Rot wob 7K, 240 gpm-2152 psi, 75 rpm-14,279 ftlbs on bott torque, 30 to 60 ft/hr ROP. MW 9.7/vis 49, ECD's at 10.9 ppg, BGG 9 units, max
gas 80 units. Connection gas 7 units.;MWD still having on bottom detection issues had to MAD Pass f/7391 TD at 7489'. Distance to plan at TD: 49.48’ 25.37’
low 42.48’ left.;CBU no noticeable increase in cuttings at BU. Start weighting up to 9.8PPG.;Wiper trip to check for gas f/7489' had to screw in pump and rotate
to get free at 7449'. Each stand after pulled 30k over before breaking over. Pulled t/7083', Disp: Calc 2.5bbl Act 2.3bbl. Then back to bottom with no issue.
Disp: Calc: 7.5bbl Act:4.2bbl Diff 3.3bbl.;Fill pipe caught pressure 2.7bbl early 0.6 bbl lost on trip in. CBU no noticeable increase in cuttings at BU. Pump sweep
around. Back 300 stokes early no increase in cuttings.;POOH on elevators f/7489' t/6055' P/U 130k S/O 68k pull 30k over to get moving. Pulled 30k over at
6055' not able to work past. Screw in try to pull with just pumps not able to work past Begin reaming f/6055' t/5839' GPM-235 PSI-1810 RPM-40 TQ-11.5k
spiking to 16.5k.;POOH on elevators f/5839' t/ 4413' P/U 116k S/O 60k.;Dragon Boxes Loaded 80 bbls
Total Dragon Boxes 2415 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 0 bbls
Total Losses Downhole 1129 bbls
8/28/2022 Cont pull up hole on elevators from 4413’ to surface shoe and parked bit at 2854’. Up wt 82K.;CBU with no increase in cuttings at 231 gpm-1309 psi, 30 rpm-
6260 ft/lbs off bott torque.;Serviced rig and topdrive, cut and slipped 96' drill line, installed load sensors on deadline, calibrated hookload and block height,
checked crown saver.;Started mad pass from 2837’ at 360 ft/hr, 226 gpm, 60 rpm, checking depth and getting survey on each connection. At 3085’ flow started
dropping off from 15 to 9%. Reduced pump rate to 170 gpm, turned water on in pits at 15 bph to start slowly reducing mud weight down to 9.7 ppg, maintaining
25;ppb background LCM. Lost 70 bbls 1st hour, 29 bbls 2nd hour, 17 bbls 3rd hour, 3 bbls 4th hour, 5 bbls 5th hour, 0 bbls 6th hour. At 3797' cont mad pass at
planned rate of 180 ft/hr down to 5200'. ECD's have dropped from 10.4 to 10.3 ppg, no gas. At 18:00 we are at 4106'. Sent BOP test notifications;Cont to mad
pass from 4106' to 5222' at 180 ft/hr, 170 gpm-839 psi, 60 rpm-8252 ft/lbs, BGG 1 unit, ECD's 10.3 ppg, MW 9.7+/vis 48. Little to no losses wile MAD passing at
these depths.;RIH on elevators f/5222' t/5704' with no issue. P/U-116k S/O 58k.;CBU while working pipe, GPM-160 PSI-950 RPM-40 TQ-10.5 Gas- 29 units at
BU.;RIH on elevators f/5704' t/6214' without issue P/U 120k S/O 64k.;CBU while working pipe prior to geotap logging. GPM-160 PSI-980 RPM-30 TQ-
11.4k.;Dragon Boxes Loaded 80 bbls
Total Dragon Boxes 2495 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 171 bbls
Total Losses Downhole 1300 bbls
8/29/2022 Cont to CBU at 6196', 154 gpm-963 psi, 30 rpm-10,742 ft/lbs torque. Had a max of 21 units gas at bottoms up.;Correlated log at 6208' and parked for 1st test
station at 6062' (probe depth). First three tests were flawless, 4th station Sperry had issues with tool. Changed choke orifice on Geo-Span twice to larger choke
and tool working again. Cont testing at 5992' 5944', 5719', 5653', 5613' and 5574'.;Guy Cook with AOGCC waived witness of upcoming BOP test at 13:47 on 8-
29-22. Have been regularly updating BLM and Quadco Rep.;Complete test at station #7, cont working up hole from 5682' to station #8 at 5442' (probe depth)
Cont test at 5365',5199',5143'. No issues downlinking or getting a good seal on the probe.;POOH on elevators /5251' t/4228'. No issues. P/U 100k S/O-60k Disp:
Calc-5.1bbl Act-8.24bbl 3.14bbl lost during trip.;Correlated log at 4160' and parked for test station #12 at 4052' (probe depth) take samples at:
4022',3994',3967',3913'. No issues downlinking. Good seals on test.;Flow check well static. POOH on elevators f/4046' t/3426' with no issues. P/U-90k S/O-
58k.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 2495 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 0 bbls
Total Losses Downhole 1300 bbls
8/30/2022 Cont. POOH from 3426', stopped at surface shoe and flow checked, slight seepage, cont POOH to BHA at 764'. Racked back HWDP and jars. L/D NM flex
collars. Removed sources, plugged in, down loaded MWD data. Static loss rate= 1.2 BPH.;Cont. L/D MWD tools, Geo-Tap, mud motor, and 6-3/4" bladed PDC
bit. Bit grade- In gauge 1-1-NO-A-X-I-NO-TD. BLM waived witness @ 08:49 hrs.;Drained stack, pulled wear ring, set test plug, flooded stack w/ water, and
flushed mud lines & Geo-span. R/D Geo-span. R/U testing equip. for BOP test. Actuated rams and choke manifold valves while purging air out of
system.;Performed bi-weekly BOP test on 4.5" as per AOGCC & BLM regulations. 250 psi Low/3500 psi High for 5/10 min.;R/D test equipment. Drained stack,
blow down mud lines and choke manifold, pull test plug and set wear ring. Clean and clear rig floor. Stage BHA #20 clean out assembly.;P/UBHA #20- M/U used
6-3/4" HDBS A1GR tricone bit to bit sub, stab and XO on bottom of 1st stand of HWDP.;RIH with Jars and HWDP from derrick t/569' Cont in hole on DP f/5969'
t/1251'.;Hold crew change PJSM. Cont in hole on DP f/1251' t/2788'.;Fill pipe CBU at the shoe. GPM-200 PSI-240 RPM-40 TQ-5.8k Max gas-0.;Cont in hole on
DP f/2788' t/4844'. Without issue. P/U62K S/O-44k.;Fill pipe CBU at 4844'. GPM-225 PSI-440 RPM-40 TQ-8.9k Max gas-17.;RIH on elevators f/4844'
t/5834'.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 2495 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 15 bbls
Total 1315 bbls
g py g
Cont drilling 6 3/4" hole from 7404' to TD
yg pg pg
Cont drilling 6 3/4" hole from 7143' md/6760' tvd to 7404
8/31/2022 Cont. RIH on elevators w/ cleanout BHA F/5761'-T/6826' w/ no issues.;CBU to break gel strengths and clean hole. GPM-225 SPP-460 psi RPM-35 TQ-12K P/U-
137K S/O-62K ROT-90K.;Cont. RIH on elevators w/ cleanout BHA F/6826'-T/7318'. Set down 30K, attempted to work through on elevators w/ no luck.;M/U TD,
broke circ. Washed/reamed F/7318'-T/7489'. GPM-225 SPP-875 psi RPM-35 TQ-13/14K P/U-160K S/O-70K ROT-98K. Pipe displacement Cal Disp.-137 bbls
Act Disp.- 129 bbls Diff-8 bbls.;CBU, hole unloaded w/ 100% increase in cuttings. GPM-225 SPP-700 psi RPM-35 TQ-12K Max gas 158 units. Pumped 20 bbl Hi-
Vis sweep flag w/ walnut. sweep came back 6 bbls early w/ no increase in cuttings. Circ. till shakers cleaned up. Obtained new SPR's. Flow checked well
(static).;Crew change, held PTSM. POOH F/7489'-T/7255'. Hole started swabbing. P/U-155K S/O-70K.;RIH F/7255'-T/7489', washed last std down w/ no
issues.;CBU. GPM-220 SPP-625 psi RPM-60 TQ-13.5K Max gas 12 units.;POOH on elevators F/7489'-T/7441', started to swab, made decision to BROOH
F/7441'T/7256' , didn't see anything on the back ream. GPM-218 SPP-600 psi TQ-12.6K RPM-40. Resumed POOH on elevators F/7256'-T/6513', had
calculated hole fill and no issues.;Obtained static loss rate= 1.2 bph. Pumped 10 bbl dry job. Started L/D 4.5" DP singles F/6513'-T/2776', using our good pipe
maintenance practices. Dropped hollow drift.;POOH on elevator f/2737' t/ surface racking back drillpipe and HWDP for liner run. L/D HWDP single, Jars and
XO's. L/D BHA #20 clean out assembly. Bit Graded:1-2-A-E-I-NO-BHA Trip Disp: Calc-51.88bbl Act-67.1bbl 15.22bbl loss for trip.;Held PJSM w/ Rig cew, Parker
casing hands, and DSM for rigging up casing equipment. R/U fill up line and Parker casing equipment. Bring centralizer to the rig floor.;M/U and baker loc 4.5"
shoe track a Fill up and test shoe track floats. Test good. M/U and baker loc landing collar. Cont running 4.5" L80 12.6lb liner as per liner tally f/ 128' t/1818'
running a centralizer every joint.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 2495 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 15 bbls
Total 1315 bbls
9/1/2022 Cont. RIH w/ 4.5" liner 12.6# L-80 DWC/C HT F/1850'-T/2807' at 40 fpm. Loss rate=1 bph.;M/U liner XO to stump. Staged pump up to GPM-210 SPP-195 psi.
CBU. Max gas-2 units CBU P/U-36K S/O-32K.;Cont. RIH w/ 4.5" liner 12.6# L-80 DWC/C HT F/2807'-T/3838' at 40 fpm. Loss rate=1 bph.;M/U liner XO to
stump. Staged pump up to GPM-209 SPP-258 psi. CBU Max gas-3 units P/U-48K S/O-40K.;Cont. RIH w/ 4.5" liner 12.6# L-80 DWC/C HT F/3838'-T/4863' at 40
fpm w/ no issues. Loss rate=1 bph.;Crew change, held PTSM. M/U liner XO to stump. Staged pump up to GPM-221 SPP-297 psi Max gas 1 unit. While
changing out handling equip and prepping to P/U hanger.;Lost all returns., slowed the pump to an idle attempting to regain return, no luck. Shut down pump.
Lined up hole fill, started filling hole down the back side. Started building 20 bbl 60 ppb LCM pill and building 200 bbl batch on new mud in premix
tanks.;Pumped 20 bbl LCM down backside, cont. top filling down back side to put pill across loss zone. Started building another 20 bbl LCM w/ 80 ppb. Cont.
transferring all mud to suction pit to keep mud going down back side. Prior to running out of drilling mud. Made call to;drilling engineer, decision was made to go
down hole with water if needed. Once the pits were empty of drilling mud, started filling hole w/ water. Finished second 20 bbl LCM pill, pumped LCM down back
side, chased w/ water. Decision was made by town to P/U;hanger and cont. RIH while cont. to fill back side. P/U Baker 7.625 ZXP-RS-Flex hanger, M/U dart to
bottom of running tool. Torqued up XO to bottom of hanger to 7K, M/U hanger to liner stump. Mixed up Zanplex and pored inside hanger top.;Started seeing flow
out at 2%, got the well stood up w/ moderate losses. Cont. circ. across the hole. M/U XO and 1 std of HWDP to top hanger running tool. Finished mixing first
200 bbl batch on new mud. Shut down the water and started circ. across the hole w/ 9.5;ppg mud. Lost a total of 498 bbl during this time period= 199 bph;Cont.
RIH w/ the 4.5" liner and hanger on 4.5" HWDP /4.5" DP at 10 fpm, while circ. across the hole F/4901'-T/6645. Started getting more metal displacement the
deeper we went. Displacement for 5 stds= Cal-6.5 bbls Act-1.2 bbls Diff- 5.3 bbls . Static loss rate=1 bph.;Attempt to break circulation started at 1bbl/min
staging up to 2bbl/min working pipe pumping on up stroke no pumps on down stroke. At 1183 strks losses got worse with minimal returns, continue circulation to
BU strks. Max gas was 1unit at bottoms up.;Lost 200bbl while circulating. Talked with Drilling engineer decision made to continue in the hole t/7140’ while
building more volume and attempt to circulate.;RIH 7 stnds 10'/min t/7140’ Disp- Calc: 2.8bbls Act: -6.3bbls. P/U 98k S/O 60k.;Monitor well on TT while building
more volume 3.5bbl/hr static loss rate. Build 300bbls @ 9.5ppg.;With 300 mor bbls built begin CBU at 1bbl/min 210PSI 3% return flow max gas 3 units. 400
strokes into bottoms up returns diminished to less than 1%. Worked pipe in an attempt to re-gain flow with no luck. Finished bottoms up strokes with max gas of
1unit. Lost 170bbls while circulating.;Cont to run liner on drill pipe f/7140' t/7337'.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 2495 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 2184 bbls
Losses Downhole 15 bbls
Total 1315 bbls
9/2/2022 Cont. RIH F/7336'-T/7485', while circ. across the hole and filling DP on the fly. lost rate= 6 bph. P/U-100K S/O-68K.;P/U & M/U Baker cmt head, washed down w/
minimal returns. GPM-40 SPP-258 psi P/U-110K S/O-68K. Tagged bottom at 7489'. P/U 1' off bottom. Attempted to get full returns w/ no luck. Called town,
decision was made to stage rate up to 3-4 bpm, attempting.;to establish full returns, pump and max volume of a 100 bbls away.;Staged pump up to 4 bpm, while
reciprocating pipe. Pumped away 103 bbls w/ minimal return.;Shut down MP. Lined hole up on PP, circulated across the hole. Loss rate=6 bph. R/U HES cmt
lines to Baker cmt head. P/U-110K S/O-70K.;Held PJSM w/ HES cmt, rig crew, Baroid, CCI, Baker tool hand, and DSM. Discussed the cement job and the plan
of action if we got high levels of gas to surface while pumping cmt job.;Halliburton pumped 2 bbls water to flush lines, then 3 bbls to fill lines. Shut in at Baker
cement head and PT lines at 280 psi low 4974 psi high. Lined up Baker cement head to Halliburton, pumped 30 bbls 10.8 ppg spacer at 3 bpm-462 psi, followed
with 155 bbls;( 370 sx) 12.0 ppg Type I II Lead cement at 3 bpm- 200 psi to 155 psi, followed with 19 bbls (100 sx) 15.5 ppg Type I II Tail cement at 3 bpm- 270
psi to 245 psi. Added 2 pps of Bridge Maker LCM to lead cement. Baker released dart, Halliburton then;displaced with 10 bbls of water followed by, 9.5 ppg 6%
KCL mud at 5 bpm-100 psi. 32 bbls into displacement saw dart latch wiper plug. With 20 bbls to go, reduced rate to 3 bpm-750 psi and bumped plug/landing
collar 104.5 bbls into displacement;(calculated at 105 bbls). FCP 1080 psi. Halliburton increased to and held 1580 psi (500 over fcp) for 1 minute, then increased
pressure to 2680 psi for 1 minute. Slacked off on blocks from 110K to 30K, giving us;a good indication hanger was set. Increased pressure to 3000 psi, seen
packer set. Bled back 1.5 bbls to truck and floats held. CIP at 11:43 on 9/2/-22. Lost 311 bbls throughout the job.;Applied 4100 psi and held 1 minute to shift
HRD-E and release run tool. Bled off and PU 2’- 58K, seen good indication running tool was released from hanger.;Flushed through cmt hoses, R/D & L/D Baker
cmt head. MU topdrive. Pressured up to 500 psi on drill string and PU slowly. Once psi started dropping, cleaned out PBR, rig started pumping and did one full
circ at 211 gpm- 215 psi Max gas 40 units.;Observed no spacer or cement at surface. Shut down pump, racked back one stand, installed wiper ball in drill
string, MU topdrive and pumped second circulation at 196 gpm- 166 psi. Flow checked (static).;POOH F/2530'-T/Baker hanger running tool. Inspected tool (ok).
L/D Baker hanger running tool. P/U Baker cmt head, Broke down pups and XO's off Baker cmt head and L/D same.;Clean and clear rig floor. Drained stack and
flushed w/ black water. Remove 90° from mud manifold and cleaned.;Performed rig service- Greased TD, blocks, IR, DWKS, crown, brake linkage, drive shaft,
and wash pipe.;P/U and M/U polish mill on a stand of HWDP and RIH t/ 2560'. Screw in establish parameters GPM-140 PSI-120 RPM-20 TQ-4.5k and RIH tag
liner top at 2599' bit depth (liner top at 2590'). P/U 9' increase parameters . Polish 3 times WOB-10k TQ-8.6K.;Held PJSM w/ rig crew, Baroid, CCI, and DSM.
Discussed the displacement and safety hazards associated with it.;Displace 9.5ppg 6%kcl phpa mud with 8.7ppg inhibited brine at 5bpm 245PSI. Monitor well
while cleaning under shakers and troughs. Well was out of balance M/U TD and pumped 20 more bbls. Well balanced.;POOH L/D 4.5" CDS-40 drill pipe singles
f/2590 t/1354' using our pipe maintenance best practice. RIH from derrick with 18 stnds of 4.5" drill pipe t/2469'. POOH L/D 4.5" drill pipe t/1916';Link tilt robotics
on top drive quit working. Trouble shoot. Bleed pressure off. Functioned valve and it started working again.;Cont. POOH L/D 4.5" drill pipe singles f/ 1916'
t/1031'.;Dragon Boxes Loaded 80 bbls
Total Dragon Boxes 2655 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 2573 bbls
Losses Downhole 621 bbls
9/3/2022 Cont. L/D 4.5" DP singles F/960'-T/Baker polishing mills using good pipe maintenance practices. L/D Baker mills, top mill had good impression marks on
carbides. Cleaned & cleared rig floor.;R/U testing equip. Performed casing test T/3000 psi on chart for 30 min. (Good Test). Pumped in 1.96 bbls Bled back
1.75 bbls. R/D testing equip. Cont. hauling off mud and cleaning tank bottoms.;M/U testing jt. to wear ring puller/test plug. Pulled wear ring and L/D same.
Loaded catwalk w/ Baker tie back seals and XO. M/U Landing jt. to hanger/ pup to XO. Loaded catwalk racks w/ 4.5" tubulars. Spotted control liner spooler. R/U
parker casing handling equip.;P/U & M/U Baker bullet seal assy. as per Baker Rep on 4.5" 12.6 L-80 DWC/C HT tubing F/17.45'-T/429'. Torque each connection
to 6,100 ft/lbs.;Crew change, held PTSM. Cont. running 4.5" 12.6 L-80 DWC/C HT tubing F/429'-T/2081'. as per run tally.;P/U chemical injection sub. R/U
Pollard control line & sheave in derrick. M/U 3/8" control line to injection sub. Pressure tested compression Farrell connection T/2500 psi (ok). Held 1000 psi on
line while RIH w/ remainder of the 4.5" tie back string installing a total of;28 band to tubing/control line. Cont. running 4.5" 12.6 L-80 DWC/C HT tubing F/2081'-
T/2588', M/U working jt w/ pump in sub, washed down, GPM-84 SPP-0 psi, seen pressure increase-350 psi, shut down MP, bled off pressure, eased down into
PBR, seen all the seals enter the liner top at 2590'.;No-Go set down at 2590' bottom of seal assembly at 2600'. POOH, L/D working jt and pump in sub. M/U
space out pups. M/U landing jt, tie back hanger, pup, and XO to tie back stump. terminated control line, ran control line through hanger port. Landed out 4.5" tie
back hanger.;hanger on seat, seen all three seals enter liner top again. No-go 2.7' off seat. RILD's. P/U-36K S/O-32K String weight on hanger -17K.;R/U and
perform MIT on tubing, test 3000PSI/30 min on chart, IA gauge 300psi, test good. 1.1bbl to pressure up 1.1 bled back. R/U and perform MIT on IA, test
2500PSI/30 min on chart tubing gauge 250PSI, test good. 0.7bbl to pressure up 0.7 bled back. R/D test equipment. Inst. 2 way check valve.;Flush surface lines
with barakleen. Empty pits of remaining fluid. Clear rig floor of pipe handling equipment and subs.;Suck fluid from BOP stack, Choke manifold, gas buster, blow
down mud pumps and mud lines. R/D choke manifold mud lines and hoses, Pump room jumper lines, Kill HCR/manual and choke HCR/manual. Nipple down
stack. Nipple up dry hole tree.;Dragon Boxes Loaded 80 bbls
Total Dragon Boxes 2655 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 104 bbls
ISO Tanks Total 2573 bbls
Losses Downhole 621 bbls
Total 2619 bbls
9/4/2022 Tested hanger neck seals T/5000 psi for 15 min, void T/5000 psi for 5 min, and tree shell test T/5000 psi for 15 min (Good tests). Pulled TWC and shut in
master valve. Checked end play on Tesco TD and change oil. Repaired Accumulator oil leaks in overhead lines.;Cont. cleaning and R/D in pits. Installed
shipping block in centrifuge. Worked on removing pod from MP #1. Positioned BOP's for crane pick with bridge cranes. Loaded out mud products and haul to J-
pad staging area.;Final report for BRU 222-34. Released and moved to well BRU 233-23 AFE @ 12:00 hrs.;Dragon Boxes Loaded 0 bbls
Total Dragon Boxes 2655 bbls
Cuttings Totes Loaded 0 bbls
Total Cuttings Totes 72 bbls
ISO Tanks Loaded 0 bbls
ISO Tanks Total 2573 bbls
Losses Downhole 0 bbls
Total 2619 bbls
p
Landed out 4.5" tieppp gj gpp p
back hanger.;hanger on seat, seen all three seals enter liner top again. No-go 2.7' off seat. RILD's
p
Discussed the cement job and the plangjp
of action if we got high levels of gas to surface while pumping cmt job.;Halliburton pumped 2 bbls water to flush lines, then 3 bbls to fill lines. Shut in at Bakergg g ppgj pp
cement head and PT lines at 280 psi low 4974 psi high. Lined up Baker cement head to Halliburton, pumped 30 bbls 10.8 ppg spacer at 3 bpm-462 psi, followedppg p pp ppgp pp
with 155 bbls;( 370 sx) 12.0 ppg Type I II Lead cement at 3 bpm- 200 psi to 155 psi, followed with 19 bbls (100 sx) 15.5 ppg Type I II Tail cement at 3 bpm- 270( ) ppg yp p p p ( ) ppg ypp
psi to 245 psi. Added 2 pps of Bridge Maker LCM to lead cement. Baker released dart, Halliburton then;displaced with 10 bbls of water followed by, 9.5 ppg 6%fpp ppg p y ppg
KCL mud at 5 bpm-100 psi. 32 bbls into displacement saw dart latch wiper plug. With 20 bbls to go, reduced rate to 3 bpm-750 psi and bumped plug/landingpp p
collar 104.5 bbls into displacement;(calculated at 105 bbls)
jp
RIH w/ remainder of the 4.5" tie back string installing a total of;28 band to tubing/control line
Activity Date Ops Summary
9/15/2022 SLB coil hold TBT and approve PTW. MU BOPs on well and function test. Last BOP test done at 9/11/22, within 1 week of last BOP test.
Pickup injector, lubricator and MU drift/nozzle BHA.
MU CTC and pull test to 30k
MU DFCV's, Disco, Circ Sub and PT to 3500 psi.
Go the well and PT lubricator to 3500 psi.,Open well and RIH. BHA: 1.75" coil, 2-1/8" CTC, 2-1/8" DFCVs, 2-1/8" Disco, 2-1/8" Circ sub and 3.74" drift/nozzle.
Tag at 7348' ctmd. circulate water at 1.5 bpm and 4120 psi.
POOH and stop at 7315' and paint flag.
POOH circulating wellbore to water.,Coil at surface, laydown nozzle BHA.
MU HES memory CBL toolstring. Open well and RIH. Stop at flag and wait for memory logging tools to begin recording.,Log from flag (7315') to 2500' at 40 fpm.
POOH to surface and close swab.,Laydown logging toolstring, stack down injector and set down injector. Install night cap on BOPs to secure well.
Download CBL data and confirm good data. Estimated TOC = 4510'.
9/16/2022 SLB coil arrive on location, hold TBT and approve PTW.
Pickup injector, lubricator and MU nozzle BHA.
Go to the well and PT low/high to 3000 psi.,Open swab and RIH with: 1.75" coil, 2-1/8" CTC, 2-1/8" DFCV's, 2-1/8" stinger, 2.75" big hole nozzle.
Cool down N2 pump and start pumping N2 down coil at 5000'. Tag bottom at 7348' ctmd. Park coil on bottom until N2 around nozzle.
POOH chasing fluid.,Tag in liner hanger at 2598' ctmd. Can move downhole, but not upward. Increase/decrease N2 pump rate, pull up to 30k.
Coil pulls free and continue to POOH to surface.,POOH pumping N2 and pressure up tubing to 1700 psi.
Shut in swab and bleed off pressure to tank.,Laydown nozzle BHA and lubricator.
RDMO.
Stage coil equipment at D pad.
11/13/2022 Morning meeting. PTW and PJSM. Standy for fuel. RDMO from 233-23.,Snow removal. MIRU on 222-34. Coordinate with construction crew to blind wing and
move other equipment out of the way.,Pickup lubricator and wireline valves. MU 1-11/16" GPT logging tools. WHP 1740 psi. RIH and find fluid level at7276' and
tagged at 7373'. POOH. Secure tree. Rig down from 222-34.
11/20/2022 Arrive Beluga. Warm up equipment on D pad. Open PTW & PJSM. Spot equipment at BRU 222-34. Prep location for perforating in the morning. LDFN.
11/21/2022 AK Eline on location. Open PTW & PJSM, discuss simops w/ construction crew. Rig up Eline on well, pick up lubricator and BHA #1. Ops finished working on
flowline. PT lubricator to 250/3000 psi. Pass.,WHP = 1644. RIH w/ 5' x 3 1/8" GR/CCL, 2.5' x 2 3/8" shock sub, 6' x 2 7/8" Geo Razor perf guns. CCL to top shot =
10'. Pull correlation pass from 5800' - 5000'. Send to Geo, shift down +3'. Shoot the Beluga H3 sand, 5611'-5617'. CCL stop depth = 5601'. Starting Pressure =
1648, 5 min = 1646, 10 min = 1644, 15 min = 1642. POOH. All shots fired, bull plug dry.,WHP = 1617. RIH w/ 5' x 3 1/8" GR/CCL, 2.5' x 2 3/8" shock sub, 6' x 2
7/8" Geo Razor perf guns. CCL to top shot = 10'. Pull correlation pass. Send to Geo, on depth. Shoot the Beluga H3 sand, 5594'-5600'. CCL stop depth = 5584'.
Starting Pressure = 1615, 5 min = 1612, 10 min = 1610, 15 min = 1609. POOH. All shots fired, bull plug dry.,WHP = 1593. RIH w/ 5' x 3 1/8" GR/CCL, 2.5' x 2 3/8"
shock sub, 20' x 2 7/8" Geo Razor perf guns. CCL to top shot = 10'. Pull correlation pass. Send to Geo, on depth. Shoot the Beluga H2 sand, 5563'-5583'. CCL
stop depth = 5553'. Starting Pressure = 1593, 5 min = 1589, 10 min = 1583, 15 min = 1578. POOH. All shots fired, bull plug dry.,WHP = 1535. RIH w/ 5' x 3 1/8"
GR/CCL, 2.5' x 2 3/8" shock sub, 10' x 2 7/8" Geo Razor perf guns. CCL to top shot = 10'. Pull correlation pass. Send to Geo, on depth. Shoot the Beluga G9
sand, 5360'-5370'. CCL stop depth = 5350'. Starting Pressure = 1522, 5 min = 1518, 10 min = 1514, 15 min = 1510. POOH. All shots fired, bull plug dry. Final
WHP = 1502 psi.,Lay down eline lubricator for the night and secure well with night cap.
11/22/2022 AK Eline on location. Open PTW & PJSM. Pick up lubricator and 13' gun BHA. Stab on to wellhead and open up to tubing pressure of 1464 psi.,WHP 1464. RIH
w/ 5' x 3 1/8" GR/CCL, 2.5' x 2 3/4" shock sub, 13' x 2 3/4" Geo Razor perf guns. CCL to top shot 9.8'. Pull correlation log and send to Geo, on depth. Shoot the
Beluga G5 sand 5193' - 5206'. CCL stop depth = 5183.2'. Initial Pressure = 1470, 5 min = 1478, 10 min = 1480, 15 min = 1480. POOH. All shots fired, bull plug
dry.,WHP 1479. RIH w/ 5' x 3 1/8" GR/CCL, 2.5' x 2 3/4" shock sub, 6' x 2 7/8" Geo Razor perf guns. CCL to top shot 10'. Pull correlation log and send to Geo, on
depth. Shoot the Beluga G3 sand 5163' - 5169'. CCL stop depth = 5153'. Initial Pressure = 1482, 5 min = 1471, 10 min = 1464, 15 min = 1460. POOH. All shots
fired, bull plug dry.,WHP 1457. RIH w/ 5' x 3 1/8" GR/CCL, 2.5' x 2 3/4" shock sub, 17' x 2 7/8" Geo Razor perf guns. CCL to top shot 12.9'. Pull correlation log
and send to Geo, on depth. Shoot the Beluga G3 sand 5137'-5154'. CCL stop depth = 5124.1'. Initial Pressure = 1461, 5 min = 1354, 10 min = 1338, 15 min =
1340. POOH. All shots fired, bull plug dry.,Rig down Eline and secure well. Spot up on BRU 244-27.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
BRU 222-34
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:221-00037 BRU 222-34 Completion
Spud Date:
AK Eline on location
AK Eline on location
SLB coil arrive on location
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Benjamin Hand Digitally signed by Benjamin Hand
Date: 2022.08.30 11:31:16 -08'00'Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2022.09.02 15:06:51 -08'00'
Definitive Survey Report
15 August, 2022
Hilcorp Alaska, LLC
Beluga River
BRU F-Pad
BRU 222-34 PB1
502832018670
Project:
Company:Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Beluga River
BRU F-Pad
Definitive Survey Report
Well:
Wellbore:
BRU 222-34
BRU 222-34 PB1 Survey Calculation Method:Minimum Curvature
As-Built @ 102.20usft (HEC 147)
Design:BRU 222-34 PB1 Database:NORTH US + CANADA
MD Reference:As-Built @ 102.20usft (HEC 147)
North Reference:
Well BRU 222-34
True
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Beluga River, Alaska, USA
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
usft
+E/-W
+N/-S
Position Uncertainty
usft
usft
usftGround Level:
BRU 222-34
usft
usft
0.00
0.00
2,624,231.580
316,499.980
83.70Wellhead Elevation:usft0.50
61° 10' 43.3173 N
151° 2' 22.6993 W
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
BRU 222-34 PB1
Model NameMagnetics
BGGM2022 8/5/2022 15.16 73.95 55,235.26001605
Phase:Version:
Audit Notes:
Design BRU 222-34 PB1
1.0 ACTUAL
Vertical Section:Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:18.50
225.000.000.0018.50
From
(usft)
Survey Program
DescriptionTool NameSurvey (Wellbore)
To
(usft)
Date 8/8/2022
Survey Date
3_Gyro-GC_Csg H049Gb: North seeking on wireline in casing50.00 675.00 gyrodata gyro (BRU 222-34 PB1)08/04/2022
3_MWD+AX+Sag A004Mb/ISC4: BGGM dec & axial + sag corr.715.04 1,210.77 MWD+AX+Sag (1) (BRU 222-34 PB1)07/23/2022
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
18.50 0.00 0.00 18.50 0.00 0.00-83.70 2,624,231.58 316,499.98 0.00 0.00 UNDEFINED
50.00 0.07 127.92 50.00 -0.01 0.02-52.20 2,624,231.57 316,499.99 0.22 0.00 3_Gyro-GC_Csg (1)
100.00 0.05 87.13 100.00 -0.03 0.06-2.20 2,624,231.55 316,500.04 0.09 -0.02 3_Gyro-GC_Csg (1)
140.00 0.06 48.60 140.00 -0.01 0.0937.80 2,624,231.56 316,500.07 0.09 -0.06 3_Gyro-GC_Csg (1)
170.00 0.15 65.94 170.00 0.01 0.1467.80 2,624,231.59 316,500.12 0.31 -0.11 3_Gyro-GC_Csg (1)
200.00 0.02 19.61 200.00 0.03 0.1897.80 2,624,231.61 316,500.16 0.46 -0.15 3_Gyro-GC_Csg (1)
230.00 0.10 71.66 230.00 0.05 0.21127.80 2,624,231.62 316,500.19 0.30 -0.18 3_Gyro-GC_Csg (1)
260.00 0.03 31.37 260.00 0.06 0.24157.80 2,624,231.64 316,500.22 0.27 -0.21 3_Gyro-GC_Csg (1)
290.00 0.09 255.98 290.00 0.06 0.22187.80 2,624,231.64 316,500.20 0.38 -0.20 3_Gyro-GC_Csg (1)
300.00 0.17 216.20 300.00 0.05 0.20197.80 2,624,231.62 316,500.18 1.16 -0.18 3_Gyro-GC_Csg (1)
320.00 0.72 217.10 320.00 -0.08 0.11217.80 2,624,231.50 316,500.09 2.75 -0.02 3_Gyro-GC_Csg (1)
350.00 1.68 219.56 349.99 -0.57 -0.29247.79 2,624,231.02 316,499.68 3.20 0.60 3_Gyro-GC_Csg (1)
380.00 2.11 219.44 379.98 -1.33 -0.92277.78 2,624,230.26 316,499.04 1.43 1.59 3_Gyro-GC_Csg (1)
8/15/2022 4:04:12PM COMPASS 5000.15 Build 91E Page 2
Project:
Company:Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Beluga River
BRU F-Pad
Definitive Survey Report
Well:
Wellbore:
BRU 222-34
BRU 222-34 PB1 Survey Calculation Method:Minimum Curvature
As-Built @ 102.20usft (HEC 147)
Design:BRU 222-34 PB1 Database:NORTH US + CANADA
MD Reference:As-Built @ 102.20usft (HEC 147)
North Reference:
Well BRU 222-34
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
400.00 2.45 219.05 399.96 -1.95 -1.42297.76 2,624,229.66 316,498.53 1.70 2.38 3_Gyro-GC_Csg (1)
410.00 2.55 219.27 409.95 -2.29 -1.70307.75 2,624,229.32 316,498.25 1.00 2.82 3_Gyro-GC_Csg (1)
440.00 3.05 218.43 439.91 -3.43 -2.62337.71 2,624,228.19 316,497.31 1.67 4.27 3_Gyro-GC_Csg (1)
470.00 4.00 220.11 469.86 -4.85 -3.79367.66 2,624,226.79 316,496.12 3.18 6.11 3_Gyro-GC_Csg (1)
500.00 4.76 221.36 499.77 -6.59 -5.28397.57 2,624,225.08 316,494.59 2.55 8.39 3_Gyro-GC_Csg (1)
530.00 5.37 221.71 529.65 -8.57 -7.04427.45 2,624,223.12 316,492.81 2.04 11.04 3_Gyro-GC_Csg (1)
560.00 6.00 221.90 559.50 -10.79 -9.02457.30 2,624,220.94 316,490.79 2.10 14.00 3_Gyro-GC_Csg (1)
590.00 6.92 222.43 589.31 -13.29 -11.29487.11 2,624,218.48 316,488.48 3.07 17.38 3_Gyro-GC_Csg (1)
600.00 7.40 223.18 599.24 -14.20 -12.13497.04 2,624,217.58 316,487.62 4.89 18.62 3_Gyro-GC_Csg (1)
620.00 8.17 223.45 619.05 -16.17 -13.99516.85 2,624,215.63 316,485.73 3.85 21.33 3_Gyro-GC_Csg (1)
650.00 9.22 223.75 648.71 -19.45 -17.12546.51 2,624,212.40 316,482.55 3.50 25.86 3_Gyro-GC_Csg (1)
675.00 10.26 223.88 673.35 -22.51 -20.05571.15 2,624,209.40 316,479.58 4.16 30.09 3_Gyro-GC_Csg (1)
716.04 12.07 225.57 713.61 -28.15 -25.65611.41 2,624,203.85 316,473.89 4.48 38.04 3_MWD+AX+Sag (2)
776.99 14.16 226.51 772.96 -37.74 -35.61670.76 2,624,194.41 316,463.78 3.45 51.86 3_MWD+AX+Sag (2)
838.86 16.37 227.43 832.65 -48.85 -47.52730.45 2,624,183.50 316,451.69 3.59 68.14 3_MWD+AX+Sag (2)
900.37 20.83 227.06 890.93 -62.17 -61.92788.73 2,624,170.41 316,437.09 7.25 87.74 3_MWD+AX+Sag (2)
963.00 22.99 227.05 949.03 -78.09 -79.02846.83 2,624,154.76 316,419.73 3.45 111.09 3_MWD+AX+Sag (2)
1,025.96 22.75 228.23 1,007.04 -94.57 -97.10904.84 2,624,138.57 316,401.39 0.82 135.54 3_MWD+AX+Sag (2)
1,087.75 25.05 226.31 1,063.53 -111.57 -115.47961.33 2,624,121.86 316,382.75 3.93 160.55 3_MWD+AX+Sag (2)
1,149.03 31.11 223.90 1,117.58 -131.96 -135.851,015.38 2,624,101.80 316,362.06 10.06 189.37 3_MWD+AX+Sag (2)
1,210.77 32.20 224.80 1,170.13 -155.13 -158.501,067.93 2,624,079.00 316,339.04 1.92 221.77 3_MWD+AX+Sag (2)
1,250.00 32.20 224.80 1,203.33 -169.96 -173.231,101.13 2,624,064.41 316,324.08 0.00 242.67 PROJECTED to TD
Approved By:Checked By:Date:
8/15/2022 4:04:12PM COMPASS 5000.15 Build 91E Page 3
8/30/22
TD Shoe Depth: PBTD:
Jts.
2
67
1
1
Yes X No X Yes No
Fluid Description:
Liner hanger Info (Make/Model):Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
1-2 370 2.44
1-2 175 1.16
4.9
20.78
Hanger 10 3/4 CDC 1.11 20.78 19.67
2,724.89 23.17
Pup 7 5/8 29.7 L-80 CDC USS 2.39 23.17
1.63 2,726.52 2,724.89
Casing 7 5/8 29.7 L-80 CDC USS 2,701.72
Float Collar 8 5/8 CDC Frontier
1 centralizer on every other Jt. except last 300' in case of top job
Casing 7 5/8 29.7 L-80 CDC USS 79.35 2,805.87 2,726.52
www.wellez.net WellEz Information Management LLC ver_04818br
3
Type of Shoe:Frontier bullnose Casing Crew:Parker
12 156
2,807.672,813.00
CEMENTING REPORT
Csg Wt. On Slips:48
Spud Mud
22:16 8/14/2022 0
15.8 35.3
Bump press
Returns to surface
Bump Plug?
123.5/125
500
35
Halliburton
FI
R
S
T
S
T
A
G
E
10.5Tuned 58
9.3 4.4
13
720
Csg Wt. On Hook:94 Type Float Collar:Frontier No. Hrs to Run:11
CDC Frontier Bullnose 1.80 2,807.67 2,805.87
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 222-34 Date Run 14-Aug-22
CASING RECORD
County State Alaska Supv.J. Richardson / C. Yearout
2,724.89
Floats Held
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.3
Shoe @ 2807 FC @ Top of Liner
Casing (Or Liner) Detail
Float Shoe 8 5/8
TD Shoe Depth: PBTD:
Jts.
1
1
116
Yes X No X Yes No 10
Fluid Description:
Liner hanger Info (Make/Model):Liner top Packer?:X Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type:Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type:Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Casing (Or Liner) Detail
Shoe 5
Rotate Csg Recip Csg Ft. Min. PPG9.5
Shoe @ 7489 FC @ Top of Liner 2587.977,444.66
Floats Held
6% KCL PHPA
CASING RECORD
County State Alaska Supv.J Richardson / J Gruenberg
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 222-34 Date Run 1-Sep-22
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Baker 2.15 7,489.00 7,486.85
Csg Wt. On Hook:110,000 Type Float Collar:Baker No. Hrs to Run:29.5
9.5 5
1080
FI
R
S
T
S
T
A
G
E
10.5Tuned 30
104.5/105
1580
294.63
Haliburton
15.3 19
Bump press
CBL
Bump Plug?
11:43 9/2/2022 4510'
7,489.007,489.00 741.86
CEMENTING REPORT
Csg Wt. On Slips:53,000
6% KCL PHPA
12 155
Type of Shoe:Baker Bull nose Casing Crew:Parker
Baker HRD-E ZXP
www.wellez.net WellEz Information Management LLC ver_04818br
3
I ran 116 Hydro form full body centralizers on every joint up to 2704'.
Liner 4 1/2 12.6 L-80 DWC/C HT Vam 40.66 7,486.85 7,446.19
Float collar 5 BTC Baker 1.53 7,446.19 7,444.66
Liner 4 1/2 12.6 L-80 DWC/C HT Vam 41.70 7,444.66 7,402.96
Landing collar 5 BTC Baker 1.10 7,402.96 7,401.86
4.5" L-80 12.6lb Liner 4 1/2 12.6 L-80 DWC/C-HT Vam 4,779.43 7,401.86 2,621.57
XO 5.5"TSH X 4.5"DWC/C-HT 6 12.6 L-80 5.5"TSH Baker 1.78 2,621.57 2,619.79
Liner Packer 6 5/8 5.5"TSH563 Baker 31.82 2,619.79 2,590.42
Type I II 370 2.39
Type I II 100 1.24
3
1
Regg, James B (OGC)
From:Regg, James B (OGC)
Sent:Thursday, December 29, 2022 9:31 AM
To:bbauer@hilcorp.com
Cc:Stjohn, Kam P (OGC)
Subject:Beluga SVS Testing
Inspector that witnessed SVS tests at Beluga River Unit (BRU) this past week made me aware of 2 online wells that were
not tested – BRU 222‐34 (PTD 2220390) and BRU 244‐27 (PTD 2220380). AOGCC regulation 20 AAC 25.265(h)(6)
requires all wells online at the time of a pad test to be performance tested. AOGCC Industry Guidance Bulletin 10‐004,
Section titled “Test Cycle” clarifies with the following: “All wells that require a functional SVS must be tested at the time
of a pad test, including any wells that have been brought on line since the previous pad test.”
I am aware that SVS tests on both were witnessed 12/6 after being placed in production. AOGCC will accept those SVS
tests as satisfying the well’s pad test requirement. For similar situations in the future, the decision to forego testing
wells that have been placed on production or injection since the previous pad test must be coordinated with AOGCC
when making notice for opportunity to witness.
Jim Regg
Supervisor, Inspections
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907‐793‐1236
From:Regg, James B (OGC)
To:AOGCC Records (CED sponsored)
Subject:SVS Testing - Beluga River Unit
Date:Thursday, December 29, 2022 9:38:09 AM
Attachments:SVS BRU 222-24 clarification 12-29-2022.pdf
SVS BRU 244-27 clarification 12-29-2022.pdf
BRU 222-24 (PTD 2220390)
BRU 244-27 (PTD 2220380)
Jim Regg
Supervisor, Inspections
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907-793-1236
Kyle Wiseman Hilcorp Alaska, LLC
Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: Kyle.Wiseman@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/28/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20221228
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BCU 14B 50133205390200 222057 11/27/2022 AK E-LINE GPT Fluid Sample
BRU 214-13 50283201870000 222117 11/9/2022 AK E-LINE Perf GPT
BRU 214-13 50283201870000 222117 12/2/2022 AK E-LINE Perf
BRU 222-34 50283201860000 222039 11/13/2022 AK E-LINE GPT
BRU 233-23 50283201360100 222050 11/10/2022 AK E-LINE GPT Plug Perf
BRU 244-27 50283201850000 222038 11/13/2022 AK E-LINE GPT
Please include current contact information if different from above.
By Meredith Guhl at 9:22 am, Dec 29, 2022
T37401
T37402
T37402
T37403
T37404
T37405
BRU 222-34 50283201860000 222039 11/13/2022 AK E-LINE GPT
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2022.12.29 09:31:43 -09'00'
Kyle Wiseman Hilcorp Alaska, LLC
Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: Kyle.Wiseman@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/19/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20221219
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
PBU Z-34 50029234690000 212061 12/5/2022 HALLIBURTON WFL-TMD3D
PBU W-08A 50029219060100 202090 12/12/2022 HALLIBURTON WFL-TMD3D
PBU_L-221 50029233850000 208031 12/13/2022 HALLIBURTON WFL-TMD3D
BCU-14B 50133205390200 222057 12/8/2022 HALLIBURTON PPROF
BRU 222-34 50283201860000 222039 12/11/2022 HALLIBURTON PPROF
PBU 09-41 50029220540000 190074 11/30/2022 READ Multi-Array-Pprof
Please include current contact information if different from above.
By Meredith Guhl at 1:47 pm, Dec 19, 2022
T37385
T37386
T37387
T37388
T37389
T37390
BRU 222-34 50283201860000 222039 12/11/2022 HALLIBURTON PPROF
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2022.12.19 13:56:07 -09'00'
Kyle Wiseman Hilcorp Alaska, LLC
Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: Kyle.Wiseman@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/02/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20221202
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BRU 222-34 50283201860000 222039 11/22/2022 AK E-Line Perf
BRU 233-23 50283201360100 222050 11/3/2022 AK E-Line GPT
BRU 244-27 50283201850000 222038 11/23/2022 AK E-Line Perf GPT
CLU 05RD2 50133204740200 222092 11/17/2022 AK E-Line Perf
MPU K-34 50029227120000 196169 11/10/2022 AK E-Line Punch
CLU 13 50133206460000 214171 11/12/2022 Halliburton SBHP
END 3-25B 50029221250200 203021 11/24/2022 Halliburton PPROF
PBU S-15 50029211130000 184071 11/24/2022 Halliburton RBT
PBU Z-221 50029237040000 221095 11/17/2022 Halliburton IPROF
PBU Z-221 50029237040000 221095 11/19/2022 Halliburton IPROF
Please include current contact information if different from above.
T37345
T37346
T37347
T37348
T37349
T37350
T37351
T37352
T37353
T37353
By Meredith Guhl at 12:25 pm, Dec 02, 2022
BRU 222-34 50283201860000 222039 11/22/2022 AK E-Line Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2022.12.02 12:24:17 -09'00'
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Subject:RE: [EXTERNAL] RE: BRU 222-34 (Sundry# 322-304)
Date:Thursday, November 10, 2022 10:42:00 AM
Jake,
Hilcorp has approval to perforate per Sundry 322-304, but only from 4675’ MD and deeper due to
the deeper than expected TOC, logged at 4510’ MD.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Thursday, November 10, 2022 10:06 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: BRU 222-34 (Sundry# 322-304)
Hello Bryan,
I couldn’t find your response to this CBL approval discussion. We are proposing to limit the highest
perf to 4675’, which is below the TOC at 4510’.
Let me know if you agree and we are OK to proceed, we will probably start on these two F-pad new
completions in early December.
From: Jacob Flora
Sent: Monday, September 19, 2022 2:58 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: BRU 222-34 (Sundry# 322-304)
Bryan,
For now for a top please use Beluga F5 ~4675-84’ MD, this puts us about 175’ into the cement and
is our next target down.
Thanks,
Jake
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, September 19, 2022 11:39 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>; Katherine O'Connor <Katherine.Oconnor@hilcorp.com>
Subject: RE: [EXTERNAL] RE: BRU 222-34 (Sundry# 322-304)
Jake,
You need some standoff from TOC to top perf. The BRU F1 mentioned below is definitely too
shallow unless you squeeze some cement above that point.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, September 19, 2022 8:57 AM
To: Katherine O'Connor <Katherine.Oconnor@hilcorp.com>; McLellan, Bryan J (OGC)
<bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: BRU 222-34 (Sundry# 322-304)
Hi Bryan,
Our highest proposed perf for now:
BRU F1 4509’ – 4517’ MD
Thanks, screenshot of CBL below
Jake
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.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: Katherine O'Connor <Katherine.Oconnor@hilcorp.com>
Sent: Monday, September 19, 2022 7:40 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Subject: FW: [EXTERNAL] RE: BRU 222-34 (Sundry# 322-304)
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, September 16, 2022 4:13 PM
To: Brad Gathman - (C) <Brad.Gathman@hilcorp.com>
Cc: Katherine O'Connor <Katherine.Oconnor@hilcorp.com>
Subject: [EXTERNAL] RE: BRU 222-34 (Sundry# 322-304)
Thanks Brad.
The Sundry is calling for perfs as shallow as 3903’ MD which is above TOC. What is the desired top
perf?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Brad Gathman - (C) <Brad.Gathman@hilcorp.com>
Sent: Friday, September 16, 2022 2:41 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Katherine O'Connor <Katherine.Oconnor@hilcorp.com>
Subject: BRU 222-34 (Sundry# 322-304)
Brian,
Please find attached CBL for well BRU 222-34 (Sundry# 322-304).
Estimated TOC = 4510’. No perforations are planned above this depth.
Please let me know if you have any questions.
Thanks,
Brad Gathman
WSM, Hilcorp AK
+1 (907) 297-8412
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 herebynotified 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.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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.
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 responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Subject:RE: [EXTERNAL] RE: Request for Perf Table Additions: 10-403 BRU 222-34 322-304 PTD 222-039 Approved 09-
07-22
Date:Monday, October 24, 2022 4:19:00 PM
Attachments:image001.png
Jake,
Hilcorp has approval to perforate the zones listed on the email below between 3914’ TVD and 6902’
TVD.
Include the report of all of these perf intervals in the 10-404 for sundry 322-304.
Regards
Bryan McLellan
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, October 24, 2022 12:20 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: Request for Perf Table Additions: 10-403 BRU 222-34 322-304 PTD 222-
039 Approved 09-07-22
You are correct, I was mistaken and looking at MD.
Please curtail the top perf to no higher than the Beluga E1 (3914’ TVD), which will stay below the
shallowest allowed (3749’ TVD).
Thanks,
Jake
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, October 24, 2022 12:07 PM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Subject: [EXTERNAL] RE: Request for Perf Table Additions: 10-403 BRU 222-34 322-304 PTD 222-039
Approved 09-07-22
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.
Jake,
It looks like these new perfs do affect the previously approved shallowest perf depth. You’ll have to
curtail either the deepest or shallowest perfs on your combined list.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, October 24, 2022 11:26 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Request for Perf Table Additions: 10-403 BRU 222-34 322-304 PTD 222-039 Approved 09-
07-22
Hi Bryan,
Hilcorp requests to add the below perorations in red font to the currently approved table. Per the
below math it does not affect the previously approved table.
Thanks,
Jake
New Max BHP 3103 psi @ 6897’ TVD (based on 0.45 psi gradient)
New MPSP 2414 psi (Based on 0.1 psi/ft gas gradient to surface)
New Shallowest Perf TVD = 3749’ TVD
REQUEST TO ADD:
Sand MD Top MD Bottom Total Footage
(MD)
TVD
Top
TVD
Bottom
Beluga H11 ±5,967'±5,978'11'±5,606'±5,617'
Beluga H12 ±5,984'±5,996'12'±5,623'±5,635'
Beluga H13 ±6,046'±6,070'24'±5,683'±5,707'
Beluga H15 ±6,179'±6,191'12'±5,813'±5,825'
Beluga I ±6,288'±6,298'10'±5,920'±5,930'
Beluga I7 ±6,566'±6,581'15'±6,193'±6,208'
Beluga I8 ±6,591'±6,609'18'±6,217'±6,235'
Beluga I9 ±6,736'±6,748'12'±6,360'±6,372'
Beluga I12 ±6,831'±6,856'25'±6,454'±6,479'
Beluga J1 ±6,926'±6,933'7'±6,547'±6,554'
Beluga J1 ±6,945'±6,954'9'±6,565'±6,574'
Beluga J2 ±7,000'±7,017'17'±6,620'±6,637'
Beluga J2 ±7,028'±7,041'13'±6,647'±6,660'
Beluga J4 ±7,272'±7,278'6'±6,888'±6,894'
Beluga J4 ±7,283'±7,288'5'±6,897'±6,902'
CURRENT APPROVED PERF TABLE:
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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.
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, pleaseimmediately 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.
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/18/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 222-34
- PTD 222-039
- API 50-283-20186-00-00
FINAL GEOTAP LWD PRESSURE SURVEY (08/29/2022 to 08/30/2022)
Reservoir Testing Studio GeoTap Summary Report
Color Time logs (1:1 Scale)
LAS Data Files
Folder Contents:
Please include current contact information if different from above.
PTD:222-039
T37165
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2022.10.20
11:07:02 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 10/04/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 222-34 + BRU 222-34PB1
- PTD 222-039
- API 50-283-20186-00-00
- API 50-283-20186-70-00 (PB1)
MUDLOGS - EOW DRILLING REPORTS (08/02/2022 to 08/27/2022)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
Formation Log
LWD Combo Log
Gas Ratio Log **** NOTE: Not Applicable for BRU-222-24PB1 Section Due to No Gas Presence
Drilling Dynamics Log
SFTP Transfer – Folder Contents:
Please include current contact information if different from above.
PTD:222-039
BRU 222-34: T37099
BRU 222-34 PB1: T37100
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2022.10.05
09:48:30 -08'00'
David Dempsey Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.dempsey2@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/3/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20221003
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 12A 501332053001 214070 8/10/2022 Halliburton CH PPROF
BRU 222-34 502832018600 222039 9/15/2022 Halliburton CH RBT
BRU 244-27 502832018500 222038 9/13/2022 Halliburton CH RBT
END 1-45 500292199100 189124 8/11/2022 Halliburton CH PERF
KBU 22-06Y 501332065000 215044 8/22/2022 Halliburton CH PPROF
KBU 43-07Y 501332062500 214019 9/7/2022 Halliburton CH PPROF
MPU C-24A 500292302001 209134 8/3/2022 Halliburton CH COILFLAG
MPU L-46 500292355100 215118 9/10/2022 Halliburton CH MFC24
MPU S-34 500292317100 203130 9/3/2022 Halliburton CH MFC24
NS-10 500292298500 200182 8/18/2022 Halliburton CH
WFL-
TMD3D
NS-32 500292317900 203158 8/17/2022 Halliburton CH
WFL-
TMD3D
PBU 04-30 500292134500 185089 9/17/2022 Halliburton CH RMT3D
PBU 05-24A 500292220401 204218 9/12/2022 Halliburton CH CAST
PBU 11-16 500292158100 186078 9/10/2022 Halliburton CH PPROF
PBU 11-27A 500292163801 222036 8/20/2022 Halliburton CH RBT
PBU C-24B 500292081602 212063 8/16/2022 Halliburton CH PPROF
PBU E-100A 500292281901 218157 9/20/2022 Halliburton CH LDL
PBU S-106 500292299900 201012 9/12/2022 Halliburton CH RBT
Please include current contact information if different from above.
T37103
T37104
T37105
T37106
T37107
T37108
T37109
T37110
T37111
T37112
T37113
T37114
T37115
T37116
T37117
T37118
T37119
T37120
BRU 222-34 502832018600 222039 9/15/2022 Halliburton CH RBT
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2022.10.05
11:39:32 -08'00'
1111 nrp Uit-k,.I'TA
Date: 10/03/2022
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 222-34
- PTD 222-039
- API 50-283-20186-00-00
RECEIVED
OCT 0 3 2022
AOGCC
Washed and Dried Well Samples (08/02/2022 to 08/27/2022)
B Set (4 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
BRU 222-34
BOX 1 OF 4
2790' - 4410' MD
BRU 222-34
BOX 2 OF 4
4410' - 5850' MD
BRU 222-34
BOX 3 OF 4
5850' - 7140' MD
BRU 222-34
BOX 4 OF 4 1
7140' - 7498' MD (TD)
Please include current contact information if different from above.
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received`BKM ' \ Date: l D l C 17
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/21/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 222-34
- PTD 222-039
- API 50-283-20186-00-00
FINAL LWD FORMATION EVALUATION LOGS (08/02/2022 to 08/30/2022)
ROP, PGC, AGR, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
BRU 222-34PB1
- PTD 222-039
- API 50-283-20186-70-00
FINAL LWD FORMATION EVALUATION LOGS (08/02/2022 to 08/05/2022)
ROP, AGR, EWR-M5 (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
PTD:222-039
T37026
T37027
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2022.09.21 11:53:02
-08'00'
1
Regg, James B (OGC)
From:Jesse Richardson - (C) <jesrichardson@hilcorp.com>
Sent:Sunday, September 4, 2022 9:05 AM
To:DOA AOGCC Prudhoe Bay; Regg, James B (OGC); Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:Hilcorp rig 147 casing/MIT test results
Attachments:BRU 222-34 casing test and MIT-T & MIT-IA tests 10-426 (5).xlsx
Please see the attached Hilcorp 147 BRU 222 34 casing test and MIT T/MIT IA test results.
Jess Richardson
Hilcorp Rig 147 DSM
Contact # 776 6776
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.
Some people who received this message don't often get email from jesrichardson@hilcorp.com. Learn why this is important
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.
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2220390 Type Inj N Tubing 0 3100 3090 3080 Type Test P
Packer TVD 2362 BBL Pump 1.1 IA 0 300 300 300 Interval I
Test psi 3000 BBL Return 1.1 OA Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2220390 Type Inj N Tubing 0 250 250 250 Type Test P
Packer TVD 2362 BBL Pump 0.7 IA 0 2600 2600 2600 Interval I
Test psi 2500 BBL Return 0.7 OA Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp Alaska, LLC
Beluga River Field / Beluga River Unit / F Pad
Witness wavied
Jess Richardson
09/03/22
Notes:
Notes:
Notes:
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Form 10-426 (Revised 01/2017)2022-0903_MITP_BRU_222-34_2tests
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Date: 2022.09.07 13:44:11
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ĞůƵŐĂ цϰ͕ϭϬϲΖ цϰ͕ϭϬϵΖ ϯΖ цϯ͕ϳϴϱΖ цϯ͕ϳϴϴΖ
ĞůƵŐĂ ϭ цϰ͕ϭϮϳΖ цϰ͕ϭϰϭΖ ϭϰΖ цϯ͕ϴϬϲΖ цϯ͕ϴϮϬΖ
ĞůƵŐĂ ϯ цϰ͕ϮϯϴΖ цϰ͕ϮϰϰΖ ϲΖ цϯ͕ϵϭϰΖ цϯ͕ϵϮϬΖ
ĞůƵŐĂ ϰ цϰ͕ϮϴϬΖ цϰ͕ϮϴϲΖ ϲΖ цϯ͕ϵϱϲΖ цϯ͕ϵϲϮΖ
ĞůƵŐĂ ϱ цϰ͕ϯϱϬΖ цϰ͕ϯϲϬΖ ϭϬΖ цϰ͕ϬϮϰΖ цϰ͕ϬϯϰΖ
ĞůƵŐĂ ϲ цϰ͕ϰϮϮΖ цϰ͕ϰϮϵΖ ϳΖ цϰ͕ϬϵϱΖ цϰ͕ϭϬϮΖ
ĞůƵŐĂ ϲ цϰ͕ϰϯϲΖ цϰ͕ϰϰϵΖ ϭϯΖ цϰ͕ϭϬϴΖ цϰ͕ϭϮϭΖ
ĞůƵŐĂ&ϭ цϰ͕ϱϬϵΖ цϰ͕ϱϭϳΖ ϴΖ цϰ͕ϭϴϬΖ цϰ͕ϭϴϴΖ
Ő>͕ƐƵďŵŝƚƌĞƐƵůƚƐƚŽK'
tĞůůWƌŽŐŶŽƐŝƐ
ĞůƵŐĂ&ϱ цϰ͕ϲϳϱΖ цϰ͕ϲϴϰΖ ϵΖ цϰ͕ϯϰϭΖ цϰ͕ϯϱϬΖ
ĞůƵŐĂ&ϲ цϰ͕ϲϵϯΖ цϰ͕ϳϬϮΖ ϵΖ цϰ͕ϯϱϵΖ цϰ͕ϯϲϴΖ
ĞůƵŐĂ&ϲ цϰ͕ϳϬϳΖ цϰ͕ϳϭϳΖ ϭϬΖ цϰ͕ϯϳϯΖ цϰ͕ϯϴϯΖ
ĞůƵŐĂ&ϲ цϰ͕ϳϰϬΖ цϰ͕ϳϱϬΖ ϭϬΖ цϰ͕ϰϬϱΖ цϰ͕ϰϭϱΖ
ĞůƵŐĂ&ϲ цϰ͕ϳϱϵΖ цϰ͕ϳϲϱΖ ϲΖ цϰ͕ϰϮϯΖ цϰ͕ϰϮϵΖ
ĞůƵŐĂ&ϳ цϰ͕ϴϮϱΖ цϰ͕ϴϱϰΖ ϮϵΖ цϰ͕ϰϴϴΖ цϰ͕ϱϭϳΖ
ĞůƵŐĂ&ϳ цϰ͕ϴϴϯΖ цϰ͕ϴϵϮΖ ϵΖ цϰ͕ϱϰϰΖ цϰ͕ϱϱϯΖ
ĞůƵŐĂ&ϳ цϰ͕ϵϯϰΖ цϰ͕ϵϱϱΖ ϮϭΖ цϰ͕ϱϵϱΖ цϰ͕ϲϭϲΖ
ĞůƵŐĂ&ϭϬ цϱ͕ϬϭϳΖ цϱ͕ϬϮϮΖ ϱΖ цϰ͕ϲϳϲΖ цϰ͕ϲϴϭΖ
ĞůƵŐĂ&ϭϬ цϱ͕ϬϯϭΖ цϱ͕ϬϯϲΖ ϱΖ цϰ͕ϲϴϵΖ цϰ͕ϲϵϰΖ
ĞůƵŐĂ'ϯ цϱ͕ϭϯϳΖ цϱ͕ϭϱϰΖ ϭϳΖ цϰ͕ϳϵϯΖ цϰ͕ϴϭϬΖ
ĞůƵŐĂ'ϯ цϱ͕ϭϲϮΖ цϱ͕ϭϲϵΖ ϳΖ цϰ͕ϴϭϴΖ цϰ͕ϴϮϱΖ
ĞůƵŐĂ'ϱ цϱ͕ϭϵϯΖ цϱ͕ϮϬϲΖ ϭϯΖ цϰ͕ϴϰϴΖ цϰ͕ϴϲϭΖ
ĞůƵŐĂ'ϵ цϱ͕ϯϱϵΖ цϱ͕ϯϳϬΖ ϭϭΖ цϱ͕ϬϬϵΖ цϱ͕ϬϮϬΖ
ĞůŐƵĂ'ϵ цϱ͕ϯϴϮΖ цϱ͕ϯϵϯΖ ϭϭΖ цϱ͕ϬϯϯΖ цϱ͕ϬϰϰΖ
ĞůƵŐĂ'ϭϬ цϱ͕ϰϯϲΖ цϱ͕ϰϱϳΖ ϮϭΖ цϱ͕ϬϴϲΖ цϱ͕ϭϬϳΖ
ĞůƵŐĂ,Ϯ цϱ͕ϱϱϵΖ цϱ͕ϱϴϯΖ ϮϰΖ цϱ͕ϮϬϲΖ цϱ͕ϮϯϬΖ
ĞůƵŐĂ,ϯ цϱ͕ϱϵϰΖ цϱ͕ϲϬϬΖ ϲΖ цϱ͕ϮϰϬΖ цϱ͕ϮϰϲΖ
ĞůƵŐĂ,ϯ цϱ͕ϲϭϭΖ цϱ͕ϲϭϳΖ ϲΖ цϱ͕ϮϱϳΖ цϱ͕ϮϲϯΖ
ĞůƵŐĂ,ϰ цϱ͕ϲϯϵΖ цϱ͕ϲϰϳΖ ϴΖ цϱ͕ϮϴϰΖ цϱ͕ϮϵϮΖ
ĞůƵŐĂ,ϰ цϱ͕ϲϱϬΖ цϱ͕ϲϱϴΖ ϴΖ цϱ͕ϮϵϱΖ цϱ͕ϯϬϯΖ
ĞůƵŐĂ,ϰ цϱ͕ϲϲϴΖ цϱ͕ϲϳϲΖ ϴΖ цϱ͕ϯϭϮΖ цϱ͕ϯϮϬΖ
ĞůƵŐĂ,ϱ цϱ͕ϲϵϲΖ цϱ͕ϳϬϮΖ ϲΖ цϱ͕ϯϰϬΖ цϱ͕ϯϰϲΖ
ĞůƵŐĂ,ϱ цϱ͕ϳϭϬΖ цϱ͕ϳϮϮΖ ϭϮΖ цϱ͕ϯϱϰΖ цϱ͕ϯϲϲΖ
ĞůƵŐĂ,ϳ цϱ͕ϳϵϭΖ цϱ͕ϴϬϭΖ ϭϬΖ цϱ͕ϰϯϯΖ цϱ͕ϰϰϯΖ
ĞůƵŐĂ,ϭϬ цϱ͕ϵϮϵΖ цϱ͕ϵϱϯΖ ϮϰΖ цϱ͕ϱϲϵΖ цϱ͕ϱϵϯΖ
Ă͘ůůƐĂŶĚƐůŝĞŝŶƚŚĞ >h'Z/s Z͕hE &/E '^WKK>
ď͘/ĨĂŶLJnjŽŶĞƉƌŽĚƵĐĞƐƐĂŶĚĂŶĚͬŽƌǁĂƚĞƌŽƌŶĞĞĚƐŝƐŽůĂƚĞĚ͕Z/,ĂŶĚƐĞƚƉůƵŐĂďŽǀĞƚŚĞ
ƉĞƌĨŽƌĂƚŝŽŶƐKZƉĂƚĐŚĂĐƌŽƐƐƚŚĞƉĞƌĨŽƌĂƚŝŽŶƐ͘
Đ͘&ƌĂĐĂůĐƐ͗hƐŝŶŐϭϰ͘ϯƉƉŐ Dt&/dĂƚƐƵƌĨĂĐĞĐĂƐŝŶŐƐŚŽĞ;Ϭ͘ϳϰϰƉƐŝͬĨƚĨƌĂĐŐƌĂĚͿ
Ě͘^ŚĂůůŽǁĞƐƚůůŽǁĂďůĞWĞƌĨdsсDW^Wͬ;Ϭ͘ϳϰϰͲϬ͘ϭͿсϭϵϲϬƉƐŝͬϬ ͘ϲϰϰсϯϬϰϯ͚ds
ϭϬ͘ZDK
ϭϭ͘dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶΘĨůŽǁƚĞƐƚǁĞůů
ƚƚĂĐŚŵĞŶƚƐ͗
ϭ͘ƐͲďƵŝůƚtĞůů^ĐŚĞŵĂƚŝĐ
Ϯ͘WƌŽƉŽƐĞĚtĞůů^ĐŚĞŵĂƚŝĐ
ϯ͘ŽŝůdƵďŝŶŐKWŝĂŐƌĂŵ
ϰ͘^ƚĂŶĚĂƌĚEŝƚƌŽŐĞŶKƉĞƌĂƚŝŽŶƐ
ϱ͘K'ZtKŚĂŶŐĞ&Žƌŵ
ůůƐĂŶĚƐůŝĞŝŶƚŚĞ >h'Z/s Z͕hE &/E '^WKK>
hƉĚĂƚĞĚďLJ&sZϬϴͲϮϵͲϮϬϮϮ
WZKWK^ ^, Dd/
ĞůƵŐĂZŝǀĞƌhŶŝƚ
ZhϮϮϮͲϯϰ
Wd͗ϮϮϮͲϬϯϵ
W/͗ ϱϬͲϮϴϯͲϮϬϭϴϲͲϬϬͲϬϬ
Wdсϳ͕ϰϬϲ͛Dͬdsсϳ͕ϬϮϰ͛
dсϳ͕ϰϴϵ͛Dͬdsсϳ͕ϭϬϭ͛
Z<ƚŽ'>сϭϴ͛
^/E' d/>
^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ
ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ
ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϯϴΖ
ϳͲϱͬϴΗ ^ƵƌĨƐŐ Ϯϵ͘ϳ >ͲϴϬ h^^Ͳ ϲ͘ϴϳϱ͟ ^ƵƌĨ Ϯ͕ϴϬϴ͛
ϰͲϭͬϮΗ WƌŽĚ>Ŷƌ ϭϮ͘ϲ >ͲϴϬ tͬͲ,d ϯ͘ϵϱϴ͟ΕϮ͕ϳϵϬ͛ ϳ͕ϰϴϲ͛
ϰͲϭͬϮΗ WƌŽĚdŝĞďĂĐŬ ϭϮ͘ϲ >ͲϴϬ tͬͲ,d ϯ͘ϵϱϴ͟ ^ƵƌĨ ΕϮ͕ϯϱϵ͛
ϭ
ϭϲ͟
ϳͲϱͬϴ͟
ϵͲϳͬϴ͟
ŚŽůĞ
ϰͲϭͬϮ͟
: t >Zz d/>
EŽ͘ ĞƉƚŚ / K /ƚĞŵ
ϭ ΕϮ͕ϳϵϬ͛ ϰ͘ϴϳϱ͟ ϲ͘ϱϰϬ͟ >ŝŶĞƌŚĂŶŐĞƌͬ>dWƐƐĞŵďůLJ
Ϯ ΕϮ͕ϳϵϬ͛ ϰ͘ϳϵϬ͟ ϲ͘ϯϰϬ͟ ^ĞĂů^ƚĞŵ
ϯ ΕϱϬϬ͛ ϯ͘ϵϱϴ͟ ϰ͘ϱϬϬ͟ ŚĞŵŝĐĂů/ŶũĞĐƚŝŽŶ^Ƶď
KW E,K> ͬ D Ed d/>
ϳͲϱͬϴΗ dKΛ^ƵƌĨĂĐĞ;ZĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞϴͬϭϰͬϮϮͿ
ϰͲϭͬϮ͟ Ɛƚ͘dKΛϮ͕ϯϲϰ͛;ϰϬйĞdžĐĞƐƐͿ
ϲͲϯͬϰ͟
ŚŽůĞ
Ϯ
ϯ
BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB
hƉĚĂƚĞĚLJ͗:>>ϬϵͬϬϭͬϮϮ
WZKWK^
ĞůƵŐĂZŝǀĞƌhŶŝƚ
tĞůů͗ZhϮϮϮͲϯϰ
Wd͗ϮϮϮͲϬϯϵ
W/͗ϱϬͲϮϴϯͲϮϬϭϴϲͲϬϬͲϬϬ
ĞůƵŐĂͲ,
Wdсцϳ͕ϰϬϲ͛Dͬdsсцϳ͕ϬϮϰ͛
dсϳ͕ϰϴϵ͛Dͬdsсϳ͕ϭϬϭ͛
Z<ƚŽ'>сϭϴ͛
ϰͲϭͬϮ͟
ϲͲϯͬϰ͟
ŚŽůĞ
ϳͲϱͬϴ͟
ϵͲϳͬϴ͟
ŚŽůĞ
ϭϲ͟
^/E' d/>
^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ
ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ
ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϯϴΖ
ϳͲϱͬϴΗ ^ƵƌĨƐŐ Ϯϵ͘ϳ >ͲϴϬ h^^Ͳ ϲ͘ϴϳϱ͟ ^ƵƌĨ Ϯ͕ϴϬϴ͛
ϰͲϭͬϮΗ WƌŽĚ>Ŷƌ ϭϮ͘ϲ >ͲϴϬ tͬͲ,d ϯ͘ϵϱϴ͟ΕϮ͕ϳϵϬ͛ ϳ͕ϰϴϲ͛
ϰͲϭͬϮΗ WƌŽĚdŝĞďĂĐŬ ϭϮ͘ϲ >ͲϴϬ tͬͲ,d ϯ͘ϵϱϴ͟ ^ƵƌĨ ΕϮ͕ϯϱϵ͛
: t >Zz d/>
EŽ͘ ĞƉƚŚ / K /ƚĞŵ
ϭ ΕϱϬϬ͛ ϯ͘ϵϱϴ͟ ϰ͘ϱϬϬ͟ ŚĞŵŝĐĂů/ŶũĞĐƚŝŽŶ^Ƶď
Ϯ ΕϮ͕ϳϵϬ͛ ϰ͘ϳϵϬ͟ ϲ͘ϯϰϬ͟ ^ĞĂů^ƚĞŵ
ΕϮ͕ϳϵϬ͛ ϰ͘ϴϳϱ͟ ϲ͘ϱϰϬ͟ >ŝŶĞƌŚĂŶŐĞƌͬ>dWƐƐĞŵďůLJ
KW E,K> ͬ D Ed d/>
ϳͲϱͬϴΗ dKΛ^ƵƌĨĂĐĞ;ZĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞϴͬϭϰͬϮϮͿ
ϰͲϭͬϮ͟ Ɛƚ͘dKΛϮ͕ϯϲϰ͛;ϰϬйĞdžĐĞƐƐͿ
W Z&KZd/KE d/>
ŽŶĞ dŽƉ
;DͿ
ƚŵ
;DͿ
dŽƉ
;dsͿ
ƚŵ
;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ
ĞůƵŐĂ
ʹ,
^ĂŶĚƐ
цϯ͕ϵϬϯ цϱ͕ϵϱϯ цϯ͕ϱϴϳ цϱ͕ϱϵϯ цϮ͕ϬϱϬ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ
^dEZt >>WZK hZ
E/dZK' EKW Zd/KE^
ϭϮͬϬϴͬϮϬϭϱ &/E>ǀϭ WĂŐĞϭŽĨϭ
ϭ͘Ϳ D/ZhEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘
Ϯ͘Ϳ EŽƚŝĨLJWĂĚKƉĞƌĂƚŽƌŽĨƵƉĐŽŵŝŶŐEŝƚƌŽŐĞŶŽƉĞƌĂƚŝŽŶƐ͘
ϯ͘Ϳ WĞƌĨŽƌŵWƌĞͲ:Žď^ĂĨĞƚLJDĞĞƚŝŶŐ͘ZĞǀŝĞǁEŝƚƌŽŐĞŶǀĞŶĚŽƌƐƚĂŶĚĂƌĚŽƉĞƌĂƚŝŶŐƉƌŽĐĞĚƵƌĞƐĂŶĚ
ĂƉƉƌŽƉƌŝĂƚĞ^ĂĨĞƚLJĂƚĂ^ŚĞĞƚƐ;ĨŽƌŵĞƌůLJD^^Ϳ͘
ϰ͘Ϳ ŽĐƵŵĞŶƚ ŚĂnjĂƌĚƐ ĂŶĚ ŵŝƚŝŐĂƚŝŽŶ ŵĞĂƐƵƌĞƐ ĂŶĚ ĐŽŶĨŝƌŵ ĨůŽǁ ƉĂƚŚƐ͘ /ŶĐůƵĚĞ ƌĞǀŝĞǁ ŽŶ
ĂƐƉŚLJdžŝĂƚŝŽŶĐĂƵƐĞĚ ďLJ ŶŝƚƌŽŐĞŶĚŝƐƉůĂĐŝŶŐŽdžLJŐĞŶ͘DŝƚŝŐĂƚŝŽŶŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĂƉƉƌŽƉƌŝĂƚĞ
ƌŽƵƚŝŶŐŽĨĨůŽǁůŝŶĞƐ͕ĂĚĞƋƵĂƚĞǀĞŶƚŝŶŐĂŶĚĂƚŵŽƐƉŚĞƌŝĐŵŽŶŝƚŽƌŝŶŐ͘
ϱ͘Ϳ ^ƉŽƚWƵŵƉŝŶŐhŶŝƚĂŶĚdƌĂŶƐƉŽƌƚ͘ŽŶĨŝƌŵůŝƋƵŝĚEϮǀŽůƵŵĞƐŝŶƚƌĂŶƐƉŽƌƚ͘
ϲ͘Ϳ ZŝŐƵƉůŝŶĞƐĨƌŽŵƚŚĞEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚƚŽƚŚĞǁĞůůĂŶĚƌĞƚƵƌŶƐƚĂŶŬ͘^ĞĐƵƌĞůŝŶĞƐǁŝƚŚǁŚŝƉ
ĐŚĞĐŬƐ͘
ϳ͘Ϳ WůĂĐĞ ƐŝŐŶƐ ĂŶĚ ƉůĂĐĂƌĚƐ ǁĂƌŶŝŶŐ ŽĨ ŚŝŐŚ ƉƌĞƐƐƵƌĞ ĂŶĚ ŶŝƚƌŽŐĞŶ ŽƉĞƌĂƚŝŽŶƐ Ăƚ ĂƌĞĂƐ ǁŚĞƌĞ
EŝƚƌŽŐĞŶŵĂLJĂĐĐƵŵƵůĂƚĞŽƌďĞƌĞůĞĂƐĞĚ͘
ϴ͘Ϳ WůĂĐĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐĚŽǁŶƐƚƌĞĂŵŽĨůŝƋƵŝĚĂŶĚŶŝƚƌŽŐĞŶƉƵŵƉƐƚŽĂĚĞƋƵĂƚĞůLJŵĞĂƐƵƌĞƚƵďŝŶŐ
ĂŶĚĐĂƐŝŶŐƉƌĞƐƐƵƌĞƐ͘
ϵ͘Ϳ WůĂĐĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐƵƉƐƚƌĞĂŵĂŶĚĚŽǁŶƐƚƌĞĂŵŽĨĂŶLJĐŚĞĐŬǀĂůǀĞƐ͘
ϭϬ͘Ϳ tĞůůƐŝƚĞDĂŶĂŐĞƌƐŚĂůůǁĂůŬĚŽǁŶǀĂůǀĞĂůŝŐŶŵĞŶƚƐĂŶĚĞŶƐƵƌĞǀĂůǀĞƉŽƐŝƚŝŽŶŝƐĐŽƌƌĞĐƚ͘
ϭϭ͘Ϳ ŶƐƵƌĞƉŽƌƚĂďůĞϰͲŐĂƐĚĞƚĞĐƚŝŽŶĞƋƵŝƉŵĞŶƚŝƐŽŶƐŝƚĞ͕ĐĂůŝďƌĂƚĞĚ͕ĂŶĚďƵŵƉƚĞƐƚĞĚƉƌŽƉĞƌůLJƚŽ
ĚĞƚĞĐƚ> >ͬ,Ϯ^ͬKϮͬKϮůĞǀĞůƐ͘ ŶƐƵƌĞEŝƚƌŽŐĞŶǀĞŶĚŽƌŚĂƐĂǁŽƌŬŝŶŐĂŶĚĐĂůŝďƌĂƚĞĚĚĞƚĞĐƚŽƌĂƐ
ǁĞůůƚŚĂƚŵĞĂƐƵƌĞƐKϮůĞǀĞůƐ͘
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37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bm it t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:147 DATE: 8/30/22
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2220390 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: Bi-Weekly: X Other:
Rams:250/3500 Annular:250/3500 Valves:250/3500 MASP:2415
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 11"P Pit Level Indicators PP
#1 Rams 1 2 7/8" x 5"P Flow Indicator PP
#2 Rams 1 Blind P Meth Gas Detector PP
#3 Rams 1 4.5"P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3 1/8"P Time/Pressure Test Result
HCR Valves 2 2 1/16" & 3 1/8"P System Pressure (psi)3000 P
Kill Line Valves 1 2 1/16"P Pressure After Closure (psi)1700 P
Check Valve 0NA200 psi Attained (sec)20 P
BOP Misc 0NAFull Pressure Attained (sec)93 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4 @ 2400 P
No. Valves 13 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 14 P
#1 Rams 4 P
Coiled Tubing Only:#2 Rams 4 P
Inside Reel valves 0NA #3 Rams 4 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:5.5 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 8/28/22 17:31
Waived By
Test Start Date/Time:8/30/2022 17:00
(date) (time)Witness
Test Finish Date/Time:8/30/2022 22:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Guy Cook
Hilcorp
Tested with 4 1/2" test joint. All tests were done at 250/3500 psi 5/10 min. Quadco Rep was on location at 10:30 on 8-30-22 and
tested all audio/visual gas alarms with no issues. Bottle Precharge - 1000 psi.
Jon Van Evera
Hilcorp Alaska, LLC
Richardson / Gruenberg
BRU 222-34
Test Pressure (psi):
jvan-evera@hilcorp.com
jesrichardson@hilcorp.com
Form 10-424 (Revised 08/2022) 2022-0830_BOP_Hilcorp147_BRU_222-34
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CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the
mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
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37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bm itt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:147 DATE: 8/17/22
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2220390 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: X Weekly: Bi-Weekly: Other:
Rams:250/5000 Annular:250/5000 Valves:250/3500 MASP:2415
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1FP
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 11"P Pit Level Indicators PP
#1 Rams 1 2 7/8" x 5"FP Flow Indicator PP
#2 Rams 1 Blind P Meth Gas Detector PP
#3 Rams 1 4.5"FP H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3 1/8"P Time/Pressure Test Result
HCR Valves 2 2 1/16" & 3 1/8"P System Pressure (psi)3200 P
Kill Line Valves 1 2 1/16"P Pressure After Closure (psi)1650 P
Check Valve 0NA200 psi Attained (sec)22 P
BOP Misc 0NAFull Pressure Attained (sec)90 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4 @ 2537 P
No. Valves 13 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 18 P
#1 Rams 4 P
Coiled Tubing Only:#2 Rams 6 P
Inside Reel valves 0NA #3 Rams 4 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:3 Test Time:19.5 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 8/13/22 09:49
Waived By
Test Start Date/Time:8/16/2022 11:30
(date) (time)Witness
Test Finish Date/Time:8/17/2022 7:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Jim Regg
Hilcorp
Tested with 4 1/2" test joint. Tested annular at 250/5000 due to having changed sealing element. Tested upper rams and blinds
at 250/5000 due to using a rental double gate. All other tests were at 250/3500 as per PTD. Topdrive IBOP failed low and high
test, replaced IBOP and re-tested OK. Both upper and lower rams failed low and high tests. Replaced sealing elements on both
sets of rams and re-tested OK. Quadco Rep was on location at 11:00 on 8-16-22 and tested all audio/visual gas alarms with no
issues. Bottle Precharge - 1000.
Kenneth Porterfield
Hilcorp Alaska, LLC
Pederson / Yearout
BRU 222-34
Test Pressure (psi):
kenneth.porterfield@hilcop.com
rpederson@hilcorp.com
Form 10-424 (Revised 08/2022) 2022-0817_BOP_Hilcorp147_BRU_222-34
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FP
FP
Topdrive IBOP failed
upper and lower rams failed
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:Frank Roach
To:McLellan, Bryan J (OGC)
Subject:BRU 222-34 7-5/8" Surface Casing FIT/LOT (PTD: 222-039)
Date:Thursday, August 18, 2022 10:23:28 AM
Attachments:BRU 222-34 7.625 Csg-Fit Test.xls
BRU 222-34 LOT at 7.625 Inch Shoe.pdf
BRU 222-34 KICK_TOL 8-18-22 15bbl min.xlsx
Bryan,
Attached are the table, chart, and kick tolerance calculations for BRU 222-34’s FIT/LOT we
performed this morning. Like our previous F-Pad well (BRU 244-27) we did achieve greater than a 15
bbl kick tolerance, but did not reach the 14.5 ppg EMW target we had in the program. As in the
previous well, surface hole was extended from plan to place the shoe in more competent rock. The
extended surface TD built on what we saw in BRU 244-27, as the extended gravels and soft sands we
were observing again while drilling. Ultimately, we drilled to ~2,813’ MD which correlated with what
we saw in BRU 244-27 in June, and BRU 241-34T back in 2020.
BRU 244-27’s 7-5/8” surface casing shoe is at 2,807’ MD (2,552’ TVD).
The FIT held consistent until the last data point where it looks to start breaking over between 706 psi
and 750 psi when the test was called. The 706psi calculates out to a 14.3 ppg EMW at the shoe and
with the new surface casing depth, provides a 17.2 bbl kick tolerance at planned TD.
If you have any questions, please don’t hesitate to reply or give me a call.
Regards,
Frank V Roach
Drilling Engineer
907.854.2321 (c)
907.777.8413 (o)
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
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CASING AND FIT TESTS
Well Name:BRU 222-34 Date:8/18/2022
Csg Size/Wt/Grade:7 5/8'' 29.7# L-80 Supervisor:Pederson/Yearout
Csg Setting Depth:2807 TMD 2552 TVD
Mud Weight:9.0 ppg LOT / FIT Press =706 psi
LOT / FIT =14.32 ppg Hole Depth =2833 md
Fluid Pumped=17.5 Gal Volume Back =15.0 Gal
Test Pump Tank 2.500 Gal/Inch
LOT DATA (test pump)CASING TEST DATA (test pump)
Enter Gal Enter Pressure Enter Gal Enter Pressure
Here Here Here Here
->1.3 35 ->0.0 0
->2.5 70 ->5.0 199
->3.8 106 ->10.0 443
->5.0 141 ->15.0 712
->6.3 203 ->20.0 982
->7.5 265 ->25.0 1251
->8.8 333 ->30.0 1484
->10.0 402 ->35.0 1739
->11.3 461 ->40.0 2012
->12.5 519 ->45.0 2252
->13.8 584 ->50.0 2517
->15.0 646 ->55.0 2790
->16.3 706 ->60.0 3062
->17.5 750 ->65.0 3312
-> ->70.0 3572
-> ->72.5 3721
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Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 750 ->0 3721
->1 738 ->5 3714
->2 733 ->10 3711
->3 728 ->15 3709
->4 723 ->20 3707
->5 718 ->25 3705
->6 713 ->30 3704
->7 709 ->
->8 705 ->
->9 701 ->
->10 698 ->
-> ->
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1.32.53.85.0
6.3
7.5
8.8
10.0
11.3
12.5
13.8
15.0
16.317.5
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
70.0
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0Pressure (psi)Gallons (# of)
LOT DATA (test pump)CASING TEST DATA
750738733728723718713709705701698
3721 3714 3711 3709 3707 3705 3704
0
100
200
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400
500
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700
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3600
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LOT DATA (test
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CASING TEST
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Kick Tolerance Actuals (2)
KICK TOLERANCE CALCULATIONS
WELL NAME BRU 222-34
Well Depth 7102 ft Hole Size 6.75 inches
Casing Depth 2552 ft Casing Size 7.625 inches ID =6.878 in
Fracture grad.14.3 ppg Casing Weight 29.7 lb/ft
Current LOP 571 psi HWDP Size 4.5 inches
Current mud weight 10.0 ppg DP Size 4.5 inches
Estimated Formation Grad.8.96 ppg DC Size 4.75 inches
Estimated formation pressure 3309 psi
Mud Hydrostatic pressure at TD 3693 psi Ann.Cap.Length Ann.Cap.
Est Friction Pressure 0 psi bbl/ft ft bbls
Choke Operator error 0 psi DC/Open Hole 0.0223 200 4.5
Influx Gradient 0.1 psi/ft HWDP/Open Hole 0.0246 330 8.1
Collar Length 200 ft DP/ Open Hole 0.0246 4020 98.8
HWDP Length 330 ft DP/ Casing 0.0263 2552 67.1
BOP/Wellhead rating 5000 psi Totals 7102 178.5
Casing Burst Rating 5880 psi
Max Influx length 1359 ft Max Allow. Ann. Surf.Press 571 psi
Max Influx Volume @Shoe 33.4 bbls Max. BHP 3693 psi
Max Influx volume @ TD 33.0 bbls
Max Influx Shoe Vol @ BHP 17.2 bbls KICK TOLERANCE 17.2 BBL
NOTES :
- Estimated formation gradient includes 0.5ppg EMW over expected pore pressure (illustrating swab kick scenario)
- Assumes the well is vertical
- Assumes influx is a gas obeying gas law regardless of the influx gradient used.
- Influx gradient used to calculate maximum influx length only.
- Volume adjustment from shoe to TD uses P1*V1 = P2*V2 and ignores T & Z.
- Assumes all BHA is outside the casing shoe
- In certain specific development areas known to have essentially gas free crude, the lesser of
TD or shoe influxes may be used.
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37'
Date: 8/1/2022 Development: X Exploratory:
Drlg Contractor: Rig No. 147 AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.: 2220390 Rig Phone:
Rig Email:
MMISCEL L ANEOUS:DIVERTER SYSTEM:
Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P
Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P
Warning Sign P Misc: NA No Threaded Connections? P
24 hr Notice: P Vent line Below Diverter? P
AACCUMUL ATOR SYSTEM:Diverter Size: 21 1/4 in.
Systems Pressure: 2950 psig P Hole Size: 9 7/8 in.
Pressure After Closure: 1600 psig P Vent Line(s) Size: 16 in. P
200 psi Recharge Time: 24 Seconds P Vent Line(s) Length: 107 ft. P
Full Recharge Time:97 Seconds P Closest Ignition Source: 81 ft. P
Nitrogen Bottles (Number of): 4 Outlet from Rig Substructure: 91 ft. P
Avg. Pressure: 2575 psig P
Accumulator Misc: NA
Vent Line(s) Anchored: P
MMUD SYSTEM:Visual Alarm Turns Targeted / Long Radius: NA
Trip Tank: P P Divert Valve(s) Full Opening: P
Mud Pits: P P Valve(s) Auto & Simultaneous:
Flow Monitor: P P Annular Closed Time: 22 sec P
Mud System Misc: 0 NA Knife Valve Open Time: 19 sec P
Diverter Misc: NA
GGAS DETECTORS:Visual Alarm
Methane: P P
Hydrogen Sulfide: P P
Gas Detectors Misc: 0 NA
Total Test Time: 1.5 hrs Non-Compliance Items: 0
Remarks:
Submit to:
SSTATE OF AL ASK A
AAL ASK A OIL AND GAS CONSERVATION COMMISSION
DDi v er t er Sys t em s In s p ec t i o n Rep o r t
GGENERAL INFORMATION
WaivedHilcorp
**Al l Di verter rep o r t s ar e d u e t o t h e ag en c y w i t h i n 5 d ays o f t est i n g *
jesrichardson@hilcorp.com
TTEST DATA
K Porterfield / P Lynch
phoebe.brooks@alaska.gov
Hilcorp Alaska, LLC
Function testedannular and knife valve with a joint of 4 1/2" DP in the hole. Verified annular was holding by slack off of blocks. Performed draw
down of koomey unit. Quadco Rep tested audio and visual gas alarms on 8-2-22 due to flight availability. Measured vent line and outlet from sub
base. Function tested PVT and flow show alarms both audio and visual. We have two "well on diverter signs posted. One at pad entrance, one
on drillers side of rig, Off side of rig is blocked off to vehicle access.
0
J Richardson / J Gruenberg
0
907-776-6776
TTEST DETAIL S
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
Beluga River Field, Beluga River Unit, Well BRU 222-34
Form 10-425 (Revised 05/2021)2022-0801_Diverter_Hilcorp147_BRU_222-34
9
9
9
9
9
-5HJJ
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: Beluga River Field, Sterling-Beluga River Gas Pool, BRU 222-34
Hilcorp Alaska, LLC
Permit to Drill Number: 222-039
Surface Location: 953' FNL, 1414' FEL, Sec 34, T13N, R1OW, SM, AK
Bottomhole Location: 2431' FNL, 2383' FWL, Sec 34, T13N, R1OW, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs
run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment
of this well.
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,
Jeremy M. Price
Chair
DATED this ___ day of May, 2022.
Jeremy
Price
Digitally signed by
Jeremy Price
Date: 2022.05.18
14:31:54 -08'00'
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3.29.2022
By Samantha Carlisle at 8:30 am, Mar 30, 2022
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Date: 2022.05.18 14:32:08 -08'00'
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Vertical Section at 225.00° (1000 usft/in)
BRU 222-34 TD
BRU 222-34 T1
7 5/8" Casing
4 1/2" Casing
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BRU 222-34 wp08
Start Dir 4º/100' : 350' MD, 350'TVD
End Dir : 1076.89' MD, 1046.09' TVD
Start Dir 2.5º/100' : 2824.44' MD, 2573.41'TVD
End Dir : 3508.37' MD, 3211.52' TVD
Total Depth : 7485.96' MD, 7102.19' TVD
A1 Coal
Sterling B
Sterling C
Beluga D
Beluga E
Beluga F
Beluga G
Beluga H
Beluga I
BRU Beluga J
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: BRU 222-34
83.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2624231.58 316499.98 61° 10' 43.317 N 151° 2' 22.699 W
SURVEY PROGRAM
Date: 2022-03-14T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 2560.00 BRU 222-34 wp08 (BRU 222-34) 3_MWD+AX+Sag
2560.00 7485.96 BRU 222-34 wp08 (BRU 222-34) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3230.20 3128.00 3527.47 Sterling B
3378.20 3276.00 3678.77 Sterling C
3576.20 3474.00 3881.20 Beluga D
3779.20 3677.00 4088.73 Beluga E
4025.20 3923.00 4340.23 A1 Coal
4166.20 4064.00 4484.38 Beluga F
4705.20 4603.00 5035.42 Beluga G
5083.20 4981.00 5421.87 Beluga H
5853.20 5751.00 6209.07 Beluga I
6421.20 6319.00 6789.76 BRU Beluga J
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: BRU 222-34, True North
Vertical (TVD) Reference:As-Built @ 102.20usft (HEC 147)
Measured Depth Reference:As-Built @ 102.20usft (HEC 147)
Calculation Method: Minimum Curvature
Project:Beluga River
Site:BRU F-Pad
Well:Plan: BRU 222-34
Wellbore:BRU 222-34
Design:BRU 222-34 wp08
CASING DETAILS
TVD TVDSS MD Size Name
2341.00 2238.80 2558.51 7-5/8 7 5/8" Casing
7102.19 6999.99 7485.96 4-1/2 4 1/2" Casing
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00
2 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 350' MD, 350'TVD
3 1076.89 29.08 226.04 1046.09 -125.30 -129.94 4.00 226.04 180.48 End Dir : 1076.89' MD, 1046.09' TVD
4 2824.44 29.08 226.04 2573.41 -714.79 -741.26 0.00 0.00 1029.59 Start Dir 2.5º/100' : 2824.44' MD, 2573.41'TVD
5 3508.37 12.00 223.29 3211.52 -883.15 -910.90 2.50 -178.05 1268.58 BRU 222-34 T1 End Dir : 3508.37' MD, 3211.52' TVD
6 7485.96 12.00 223.29 7102.19 -1485.10 -1477.96 0.00 0.00 2095.20 Total Depth : 7485.96' MD, 7102.19' TVD
-2000
-1833
-1667
-1500
-1333
-1167
-1000
-833
-667
-500
-333
-167
0
167
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South(-)/North(+) (250 usft/in)-1667 -1500 -1333 -1167 -1000 -833 -667 -500 -333 -167 0
West(-)/East(+) (250 usft/in)
BRU 222-34 T1
BRU 222-34 TD
7 5/8" Casing
4 1/2" Casing
250
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BRU 222-34 wp08
Start Dir 4º/100' : 350' MD, 350'TVD
End Dir : 1076.89' MD, 1046.09' TVD
Start Dir 2.5º/100' : 2824.44' MD, 2573.41'TVD
End Dir : 3508.37' MD, 3211.52' TVD
Total Depth : 7485.96' MD, 7102.19' TVD
Project: Beluga River
Site: BRU F-Pad
Well: Plan: BRU 222-34
Wellbore: BRU 222-34
Plan: BRU 222-34 wp08
WELL DETAILS: Plan: BRU 222-34
83.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2624231.58 316499.98 61° 10' 43.317 N 151° 2' 22.699 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: BRU 222-34, True North
Vertical (TVD) Reference:As-Built @ 102.20usft (HEC 147)
Measured Depth Reference:As-Built @ 102.20usft (HEC 147)
Calculation Method:Minimum Curvature
CASING DETAILS
TVD TVDSS MD Size Name
2341.00 2238.80 2558.51 7-5/8 7 5/8" Casing
7102.19 6999.99 7485.96 4-1/2 4 1/2" Casing
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