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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): Ninilchik Unit
GL: 126.3' 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 1,356'
3-1/2"L-80 7,549'
3-1/2"L-80 1,233'
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
Surface
1,463'
9.2#
Surface
N/A
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
1,257'8,143'
Surface 9-7/8"
Driven
Surface L - 230 sx / T - 164 sx
6-3/4"
TOP HOLE SIZE
PACKER SET (MD/TVD)
Conductor
Tieback AssyTieback
TUBING RECORD
L - 802 sx / T - 121 sx
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
2/17/2025 224-145 / 325-052
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
209904 2233390
50-133-20731-00-00January 2, 2025
N/A
Kalotsa 9January 11, 20252216' FSL, 507' FWL, Sec 7, T1S, R13W, SM, AK
144.3'
Beluga/Tyonek Gas Pool
C061505, ADL 384372
8,145' MD / 7,551' TVD
7,515' MD / 6,925' TVD
1419' FNL, 868' FEL, Sec 12, T1S, R14W, SM, AK
CASING, LINER AND CEMENTING RECORD
1342' FNL, 891' FEL, Sec 12, T1S, R14W, SM, AK
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,
AMOUNT
PULLED
208571
208549
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.
CBL 1-26-25, Perf and GPT logs, LWD (PCG, ADR, PWD, DDSR, CTN, ALD), Geotap
N/A
N/A
N/A
SETTING DEPTH TVD
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2235080
2235158
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
9.2#
1,292'
1,206'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl:Water-Bbl:
0 01342417
3/3/2025 24
Flow Tubing
0
13,005
N/A13,0050
2/21/2025
Date of Test:Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
G
s d 1
0 p
dB P
L
s
(att
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By James Brooks at 8:16 am, Mar 25, 2025
Complete
2/17/2025
JSB
RBDMS JSB 032825
GDSR-4/15/23BJM 11/10/25
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval T 87 7,453' 6,864'
894' 885'
977' 964'
1188' 1149'
4255' 3695'
4334' 3781'
4505' 3942'
7444' 6855'
7515' 6925'
7805' 7233'
7882' 7290'
7987' 7394'
8025' 7432'
8070' 7477'
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:
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
T 118
T 120
T 135
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.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
INSTRUCTIONS
Wellbore Schematic, Drilling and Completion Reports, Csg and Cmt Reports, Definitive Directional Survey
Authorized Title: Drilling Manager
T 115
Beluga 136
Sterling 6
Tyonek Top
T 90
Beluga A
Beluga 1
T 5
T 87
Formation Name at TD:
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.
T 140
N
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.03.24 16:22:27 -
08'00'
Sean
McLaughlin
(4311)
Updated by CJD 3-17-25
SCHEMATIC
Ninilchik Unit
Kalotsa 9
PTD: 224-145
API: 50-133-20731-00-00
PBTD = 7,515’ / TVD = 6,925’
TD = 8,145’ / TVD = 7,551’
RKB to GL = 18.86’
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 GBCD 6.875”Surf 1,463’
3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”1,257’8,143’
3-1/2"Prod Tieback 9.2 L-80 EUE 2.992”Surf 1,257’
JEWELRY DETAIL
No.Depth ID OD Item
1 1,257’2.992”3.50”Liner hanger / LTP Assembly
2 1,257’2.992”3.50”Seal Stem
3 7,515’--Wireline Retrievable Plug
4 7,820’--CIBP w/ 10’ of cmt on top 2/20/25
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_87 7,453'7,473'6,864'6,884'20'2/27/25 Open
TY_90 7,520'7,586'6,930'6,996'66'2/21/25 Isolated
TY_90 7,599'7,625'7,009'7,035'26'2/21/25 Isolated
TY_115 7,862'7,868'7,270'7,276'6'2/18/25 Isolated
TY_118 7,932'7,948'7,340'7,356'16'2/18/25 Isolated
TY_118 7,968'7,980'7,376'7,387'12'2/18/25 Isolated
TY_120 7,988'8,017'7,396'7,424'29'2/17/25 Isolated
OPEN HOLE / CEMENT DETAIL
7-5/8"TOC @ Surface: 68 bbl 10.5 ppg spacer, 86 bbl 12.5 ppg class G lead cement followed
by 36 bbl 15.3 class G tail cement. Bumped plug at 63 bbls (calculated 64 bbls)
3-1/2”TOC @ 1,442’ (1-26-25 CBL) (Short joints @ 1949, 2971’, 3993’, 5014, 6034’ 7056’)
2
16”
7-5/8”
9-7/8”
hole
3-1/2”
6-3/4”
hole
1
RA 7567’
RA 6545’
RA 5523’
RA 4503’
RA 3482’
RA 2460’
3
4
Page 1/6
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:12/29/2024 End Date:1/19/2025
Report Number
1
Report Start Date
12/29/2024
Report End Date
12/30/2024
Operation
L/D top drive, Prep and scope down derrick, Remove wind walls on pits and rig floor, Slip off drilling line and Lay over derrick.
Winterize test pumps and pressure washer, lower gas buster and remove stack, Blow down steam and water, Rigged down choke house and removed, remove iron
roughneck and lower rig floor wind walls, crews travel to location, measure out rig foot print.
Lowered degasser into pit #4. R/D electrical cables to pits & pump room. Raised landings in pits and lowered roofs on all three pit modules. Laid over beaver slide and
R/D catwalk. R/D brake linkage and IR HPU. R/D remainder of electrical cables. Vacuumed out water tank. Lowered doghouse into rig water tank. Disconnected all fuel
lines. R/D CCI shack. Removed Handy Berm from around rig footprint.
Cont. working on misc. R/D projects, and loading out and hauling equip. & materials to Paxton Pad. Night rig crew traveled to Kalotsa pad, laid felt, liner, and set rig mats.
Report Number
2
Report Start Date
12/30/2024
Report End Date
12/31/2024
Operation
Rig movers on location pull catwalk and pit modules, pull pump skids and doghouse, pull gen skid and top drive HPU, Pull boiler complex and spot in cranes
Transport loads to location and stage, pick derrick off sub and transport to location, pull draw works and sub off well, load on trailers, transport cranes and sub to location,
spot pony subs over well and spot in cranes, set sub and draw works on sub, set derrick on sub and pin.
Spotted gen skid, and pit module #1. Rasied pit roof and doghouse. Hooked up electrical, water, and steam lines. Installed lights on top of modules. Set IR on rig floor.
Rasied V-door wind wall, lowered walk ways on gen skid, and water tank. Fired gen and power up lights.
Inspected & prepped derrick to raise, raised derrick. R/U IR HPU and IR. Connected koomey hoses to bulk head on koomey room wall. Prepped derrick to scope. Hooked
up air & HYD lines. Spooled on drill line. Cont. with R/U.
Report Number
3
Report Start Date
12/31/2024
Report End Date
1/1/2025
Operation
Continue rigging up, rig mover on location 0700 hrs set in pump and pit modules, set in top drive HPU and gen set, set in boiler, tear down offices and transport to
location, set rig mats for camp.
Spot in camps and offices trailers, hook up gens and power up camps, get coms up and going, continue rigging up spot catwalk and fold over ramp, prep to scope up
derrick, spot in mechanic and electricians shack.
Scoped up mast, installed lower torque tube and T-bar. Put steam traps in heaters. Spotted 3rd party shacks and plugged in. Hooked up hard lines to mud gas separator.
Hook up hard lines to choke manifold. R/U degasser. Replaced bushings in hole fill pump and put together. Bump test liner wash and lube pump.
P/U Top drive and torque busing. M/U kelly hose and hydraulics. Bring water on and move around pits to check for leaks. Function test euipment in pits. R/U centrifuge.
R/U bails, elevators and rig tongs.
Report Number
4
Report Start Date
1/1/2025
Report End Date
1/2/2025
Operation
Work on rig acceptance checklist, fuction test top drive, build spud mud, Install slip on wellhead, T and annular, attmpt to install bell nipple need to cut 6'' off riser, mobilize
welder and cut down riser, install riser
Continue building spud mud dress shakers, install diverter vent line and weights, tighen bolts on stack and vent line, hook up koomety lines to annular and knife valve.
Cont. to work on rig acceptance check list. Pressure test surface lines to 2000 psi. Check tubular torque between iron rough neck and rig tongs.
Perform Diverter function test and koomey draw down. Bag close in 25 seconds, knife vale in 7 seconds.
Rack, strap and tally 4.5" DP. P/U and rack back 20 jnts of 4.5" DP.
Cont to P/U and rack back 66 jnts (86 total) of 4.5" Dp and 16 jnts of 4.5" HWDP
Stage Sperry surface BHA on pipe racks and bring XO's and bit to rig floor.
Report Number
5
Report Start Date
1/2/2025
Report End Date
1/3/2025
Operation
M/U Surface BHA as per DD/MWD, upload MWD, shallow test tools and load sources.
Drill 9 7/8'' Surface hole f/ 130' t/ 247' 400 gpm 940 psi 30 rpm 3.1k tq 31k PUW 27k SOW 28k ROT
Continue Drilling 9 7/8'' Surface Hole f/ 247' t/680' 511 gpm 1879 ps 40 rpm 3.8k tq on bottom, 8.9 ppg MW 9.38 ppg ECZD
Drill 9-7/8” Hole F/ 680’ t/ 1123' MD Total (AROP 74') 500 GPM= 1685psi, 40 RPM=5.5k TRQ , 4-6k WOB, ECD 9.48. MW 8.9ppg P/U 46k, S/O 43k, ROT 45k. Pumped
sweep at 724' back on time with no signifacant increase in cuttings.
Drill 9-7/8” Hole F/ 1123’ t/ 1483' MD Total (AROP 74') 500 GPM= 1685psi, 40 RPM=5.5k TRQ , 4-6k WOB, ECD 9.48. MW 8.9ppg P/U 46k, S/O 43k, ROT 45k.
Pump sweep while waiting on geologist reviewed logs to call TD. 500GPM=1760PSI, 60RPM=4.2K. Sweep back on time with a 50% increase in cuttings.
Report Number
6
Report Start Date
1/3/2025
Report End Date
1/4/2025
Operation
POOH on elevators f/ 1483' t/ 683' with no issuses
Rack back HWDP unload sources, download MWD, L/D remaining BHA bit graded 1-1 in gauge, clear floor.
R/U Parker TRS, dummy run hanger, L/D on catwalk.
M/U shoe track Baker locking connections and check floats-good. RIH w/ 7 5/8'' Surface casing as per tally t/ 1454'. M/U hanger and landing jt land on hanger putting the
csing shoe at 1477'.
Circulate and condition f/ cement job, stage rate t/ 5 bpm, spot in and R/U cementers.
Shut down blow down top drive load plug in head and M/U cement head, PJSM.
Field: Ninilchik (NINU)
Sundry #:
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:224-145
Wellbore API/UWI:50-133-20731-00-00
Page 2/6
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Fox attempted to pump water ahead, but line froze up. Got thawed out and loaded lines with 5 bbls water and checked for leaks. Fox pressure tested lines at 460 low
2900 high, good tests. Fox pumped 68 bbls 10.5 ppg spacer at 4 to 3 bpm 60 to 10 psi, followed with 86 bbls (230 sx) 12.5 ppg Class G lead cement at 4 to 5 bpm 30 to
80 psi, followed by 36 bbls (164 sx) 15.3 ppg Class G tail cement at 1 to 1.5 bpm 0 psi. Loaded top plug while fox brought on mud and dropped top plug. Displaced with
9.1 ppg Spud mud at 4 bpm 0 to 480 psi. Slowed pump to 3 bpm-410 psi with 3 bbls to go. Bumped the plug 63 bbls into displacement (calculated 64 bbls). Held 2360 psi
(FCP of 410 psi) for 3 minutes, bled back 3/4 bbl to truck and floats held. CIP at 21:45 on 1-3-2025. Had 68 bbls of Spacer returns to surface and 43 bbls lead cement to
surface. Mix water temp 75 deg. Pumped 50% excess on both lead and tail. Lost 0 bbls throughout the job. Did reciprocate casing up until the star of displacement.
P/U-52K, S/O-48K. Washed up, RD and released Fox cementers.
N/D diverter, vent line, and flow line. R/D chains. Bleed down koomey. Install shipping beams.
Remove knife valve, riser, annular, tee and spacer spool. Lower catwalk and fly outannular, tee and spacer spool with crane. Hang BOP stack on bridge cranes with
crane. Raise catwalk. In stall slip loc well head as per well head rep and test seals to 5000psi/30min- good test. Installl spacer spool. Clean mud pits 1 and 6.
Disassemble MP 1 and 2 and inspect. re-assemble with 5" liners.
Report Number
7
Report Start Date
1/4/2025
Report End Date
1/5/2025
Operation
Connect accumulator hoses, open ram doors and install ram blocks, torque up ram doors, M/U choke hose, clean pit 7
Install kill line, manual chaoke valve and choke HCR. Install flow box and riser, Function test rams, install flow line
R/U test jt and test equipment flood stack and lines burp air out of system and vavles.
Perform shell test on system 250 low 5000 psi high, leaking flange on lower spool tighten and retest. Annular cap seal leaking, bleed off pressure and blow down top
drive, tighten annular cap and retest. Got a good test.
Performed Initial BOP test with 4.5" test jt, as per AOGCC regulations. Had 1 F/P with a 4.5 hr. test time.
R/U test equipment and test 7-5/8" surface casing to 3500psi/30min-good test. Pumped 1.06bbl bled back 1.06bbl. R/D test equipment and blow down all surface lines.
Single in hole and rack back 24 joints of 4.5" DP. Single in the hole with 24 joints of 4.5" DP.
Report Number
8
Report Start Date
1/5/2025
Report End Date
1/6/2025
Operation
Continue P/U and racking back DP 22 stands.
Service rig and top drive, grease iron roughneck service blocks and crown, inspect draw works and brake linkage.
P/U Triple Combo BHA as per DD/MWD, attemt to upload unable to connect to all tools.
Continue to attempt to upload MWD and get tools to read, L/D ADL and P/U back up tools
Shallow pulse test MWD tools-good test. PJSM and load sources. RIH with 4 stands of HWDP. P/U jars and HWDP single. Cont to RIH w/ 5 stands of 4.5" HWDP t/ 680'.
Single in hole w/ 23 jnts of 4.5" DP t/1377' set down on plugs. P/U-45K, S/O-40K.
Drill FE plugs, float collar, and shoe track and cemented rat hole f/1377' t/1483'. 255GPM=1350PSI, 40RPM=3.9k TQ, 2-11K WOB, ECD=9.51ppg.
Drill 20' of new formation f/1483' t/1503'. 255GPM=1450PSI, 40RPM=4.4k TQ, 1-5K WOB, ECD=9.58ppg.
CBU x 2. Displace well over to 6% KCL mud system.
R/U test equipment and perform FIT to 690 psi for a 18.7ppg MWE. R/D test equipment and blow down choke.
Report Number
9
Report Start Date
1/6/2025
Report End Date
1/7/2025
Operation
Drill 6 3/4'' Hole Section f/ 1503' t/ 1962' 260 gpm 1600 psi 60 rpm 4.8k tq on bottom, 6k WOB max gas 70 units, MW 8.95 ppg, 51k PUW 44k SOW 48k ROT
Drill 6 3/4'' Hole Section f/ 1962' t/ 2552' 260 gpm 1530 psi 60 rpm 5.1k tq on bottom, 5k WOB, 340 units of gas, 55k PUW SOW 44k ROT 50k
Circulate bottoms up. Obtain SPR's. Flow check well-static. POOH on elevators f/2552' t/1428' without issue. P/U-70K, S/O-50K. 255GPM=1472PSI, 60RPM=5.2K TQ
Grease top drive, drawworks, brake linkage, and crown. Check oil in drawworks and top drive. Inspect saver sub, and brake linkage.
TIH f/1428 t/2552' without issue. P/U-70K, S/O-45K.
Pump hi-vis condet sweep at 2552' and circulate out of the hole. Sweep back on time with a 75% increase in cuttings.
Drill 6-3/4” Hole F/ 2522’ t/ 2649' MD 250 GPM= 1502 psi, 60 RPM=5.7k TRQ, 1-3k WOB, ECD 10.1 Max Gas 157u. MW 9.05ppg P/U-63k, S/O-50k, ROT-56K.
Drill 6-3/4” Hole F/ 2649’ t/ 3117' MD 265 GPM= 1690 psi, 60 RPM=6.1k TRQ, 1-3k WOB, ECD 10.7 Max Gas 420u. MW 9.05ppg P/U-75k, S/O-50k, ROT-58K. Pump
sweep at 3078'. Back 50 storkes late with 100% increase.
Report Number
10
Report Start Date
1/7/2025
Report End Date
1/8/2025
Operation
Cont drilling from 3117' to 3463', rot wob 1-3K, 257 gpm-1429 psi, 60 rpm-6300 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 5K, 258 gpm-1670 psi, 300 psi diff, 160
ft/hr ROP.
MW 9.1/vis 54, ECD 10.2+ ppg, BGG 25 units, max gas 380 units.
Cont drilling from 3463' to 3554', rot wob 4K, 254 gpm-1540 psi, 60 rpm-6900 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 2K, 254 gpm-1600 psi, 280 psi diff, 160 ft/hr
ROP.
MW 9.1+/vis 56, ECD 10.5 ppg, BGG 27 units, max gas 240 units.
CBU at 254 gpm-1378 psi, 50 rpm-6200 ft/lbs off bott torque. Obtained on bott survey and SPR's, 10 minute flow check = slight seepage.
Pulled up hole on elevators from 3554' to 2551'. Had to work through tight hole at 2884', 2665', 2620', 2606' and 2572' on elevators. Up wt 97K.
Serviced rig and topdrive.
RIH on elevators from 2551' to 3494' with no issue, saw nothing at previous tight spots. MU topdrive, filled pipe, washed/reamed to bottom at 3554' and started sweep.
Down wt 48K.
Pumped and circulated 20 bbl hi-vis nutplug sweep around at 257 gpm-1641 psi, 80 rpm-6640 ft/lbs off bott torque. Sweep back on time with 50% increase in cuttings.
Max gas at bottoms up 170 units.
Field: Ninilchik (NINU)
Sundry #:
State: ALASKA
Rig/Service:
Page 3/6
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Cont drilling from 3554' to 3933', sliding wob 1-2K, 260 gpm-1610 psi, 220 psi diff, 150 ft/hr ROP. Rot wob 4K, 264 psi, 1514 psi, 60 rpm-6700 ft/lbs on bott torque, 120
ft/hr ROP.
MW 9.1+/vis 55, ECD 10.3 ppg, BGG 30 units, max gas 329 units
Drill 6-3/4” Hole F/ 3933’ t/ 4308' MD 265 GPM= 1600 psi, 60 RPM=7.3k TRQ, 5-7k WOB, ECD 10.6 Max Gas 109u. MW 9.2ppg P/U-110k, S/O-64k, ROT-59K. Pump
sweep at 4056'. Back on time with 50% increase.
Report Number
11
Report Start Date
1/8/2025
Report End Date
1/9/2025
Operation
Cont drilling from 4308' to 4562', sliding wob 3-6K, 261 gpm-1699 psi, 230 psi diff, 90 ft/hr ROP. Rot wob 1-4K, 262 psi, 1713 psi, 70 rpm-8800 ft/lbs on bott torque, 120
ft/hr ROP.
MW 9.2+/vis 52, ECD 10.6 ppg, BGG 27 units, max gas 292 units
CBU twice at 251 gpm-1456 psi, 70 rpm-8000 ft/lbs off bott torque. Obtained on bottom survey and SPR's, 10 minute flow check = static.
Pulled wiper trip from 4562' up to 1556'. Pulled on elevators up to 2420' with a couple tight spots we worked through. At 2420' pulled 30K over 3 times, MU topdrive,
backreamed to 1855', then able to cont on elevators. Had a good amount of clay, sand and coal on shaker during backreaming.
CBU one time at 1556', 254 gpm-1227 psi, 50 rpm-4170 ft/lbs off bott torque. Very little gas but a good amount of clay and fine sand at bottoms up.
Pulled and parked bit at 1432' inside surface casing, blew down topdrive, serviced rig and topdrive, C/O grabber dies, racked and tallied 24 jnts DP.
PU singled in hole 24 jnts 4 1/2" DP from 1432' to 2179'.
MU topdrive, filled pipe while racking and tally 24 more jnts DP.
PU singled in hole 24 jnts 4 1/2" DP to 2906', then cont RIH on stands from 2906' to 4562'. Wash last stand down. Pump sweep and work pipe while circulating out of the
hole. Sweep back on time with a 10% increase.
Drill 6-3/4” Hole F/ 4562’ t/ 4718' MD 265 GPM= 1600 psi, 70 RPM=9.1k TRQ, 4-8k WOB, ECD 10.46 Max Gas 415u. MW 9.25ppg P/U-115k, S/O-70k, ROT-86K.
Drill 6-3/4” Hole F/ 4718’ t/ 5125' MD 265 GPM= 1900 psi, 60 RPM=9.4k TRQ, 4-8k WOB, ECD 10.46 Max Gas 746u. MW 9.25ppg P/U-115k, S/O-70k, ROT-86K. Pump
tandem sweep at 5062' back 4.3 bbl late with a 50% increase.
Report Number
12
Report Start Date
1/9/2025
Report End Date
1/10/2025
Operation
Cont drilling from 5125' to 5566'. Rot wob 3-5K, 258 gpm-1787 psi, 60 rpm-9600 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 4-5K, 259 gpm-1683 psi, 187 psi diff, 80
ft/hr ROP.
MW 9.3+/vis 51, ECD 10.5 ppg, BGG 29 units, max gas 405 units.
Obtained on bottom survey, CBU twice at 258 gpm-1588 psi, 80 rpm-10,300 ft/lbs off bott torque. Obtained SPR's, 10 minute flow check fluid dropped 2'.
Pulled up hole on elevators from 5566' to 4495'. Up wt 160K. First stand pulled nice, second stand we had to break loose on down stroke then able to pull free.
Remainder of trip went well.
Serviced rig and topdrive, cleaned mud pump suction screens. Hole taking 1 bph on trip tank.
RIH from 4495' to 5499', down wt 75K with no issue. MU topdrive on last stand and attempted to S/O to check depth at crack. Could not break loose. Filled pipe and
began rotating with no issue. Washed and remaed to bottom at 5566'.
Pumped a 40 bbl tandem sweep (20 bbls lo-vis lo-wt, 20 bbls hi-vis hi-wt) around at 264 gpm-1727 psi, 80 rpm-8960 ft/lbs off bott torque. Had 195 units gas at bottoms up
with significant amount of small coal chips. Sweep back on time with 10% increase in clay and fine sand.
Cont drilling from 5566' to 5630'. Rot wob 4K, 257 gpm-1733 psi, 60 rpm-10,200 ft/lbs on bott torque, 119 ft/hr ROP. Sliding wob 3K, 262 gpm-1771 psi, 203 psi diff, 45
ft/hr ROP.
MW 9.3+/vis 50, ECD 10.4 ppg, BGG 32 units, max gas 334 units.
Drill 6-3/4” Hole F/ 5630’ t/ 6068' MD 265 GPM= 1695 psi, 60 RPM=11.2k TRQ, 3-5k WOB, ECD 10.47 Max Gas 336u. MW 9.35ppg P/U-150k, S/O-79k, ROT-104K.
Drill 6-3/4” Hole F/ 6068’ t/ 6476' MD 265 GPM= 1695 psi, 60 RPM=11.2k TRQ, 3-5k WOB, ECD 10.47 Max Gas 441u. MW 9.35ppg P/U-165k, S/O-84k, ROT-115K.
Pump hi-vis sweep at 6068' back 3.6 bbl early with a 50% increase.
Report Number
13
Report Start Date
1/10/2025
Report End Date
1/11/2025
Operation
Cont drilling from 6476' to 6569'. Rot wob 11K, 264 gpm-1846 psi, 60 rpm-11,300 ft/lbs on bott torque, 120 ft/hr ROP.
MW 9.3+/vis 54, ECD 10.5 ppg, BGG 37 units, max gas 296 units.
Surveyed on bottom, CBU twice at 260 gpm-1783 psi, 80 rpm-9747 ft/lbs off bott torque. Obtained SPR's and did a 10 minute flow check. Fluid dropped 1' in wellbore.
Pulled up hole on elevators from 6569' to 5565'. Up wt 185K. No issues.
Serviced rig and topdrive, greased crown, cleaned mud pump suction screens. Well on trip tank with a 2 bph loss rate.
RIH from 5565' to 6508', MU topdrive on last stand and filled pipe, washed and reamed to bottom at 6569'. Down wt 85K. No issues.
Pumped a 20 bbl hi-vis nutplug sweep around at 260 gpm-1776 psi, 80 rpm-12,500 ft/lbs off bott torque. Hole unloaded lots of coal chips, sand and clay at bottoms up
and a max of 1195 units gas. Sweep back on time with an additional 50% increase in cuttings.
Cont drilling from 6569' to 6905'. Sliding wob 3-5K, 259 gpm-1961 psi, 211 psi diff, 45 ft/hr ROP. Rot wob 5-9K, 257 gpm-2080 psi, 60 rpm-11,600 ft/lbs on bott torque,
110 ft/hr ROP.
MW 9.3+/vis 51, ECD 10.5 ppg, BGG 67 units, max gas 717 units.
Finished strap of 3 1/2" liner, received first load of lead cement in silo.
Drill 6-3/4” Hole F/ 6905’ t/ 7076' MD 260 GPM= 1760 psi, 60 RPM=12.4k TRQ, 6-8k WOB, ECD 10.61 Max Gas 690u. MW 9.35ppg P/U-180k, S/O-87k, ROT-119K.
Having to rock the pipe to slide. Experincing differential sticking after the connection. Having to pump and rotate to break it over. Increasing MW to 9.45ppg and bring lube
up to 0.5%. Spoke with town engineer about Directional target radius (200 foot target). Stop sliding for directional controp at 7076'.
Pump hi-vis condet nut plug sweep at 7076'. 260GPM=1760PSI, 80RPM=12.8K TQ. Sweep back on time with a 20% icrease in cuttings. Obtain SPR's.
Drill 6-3/4” Hole F/ 7076’ t/ 7139' MD 260 GPM= 1760 psi, 60 RPM=13 TRQ, 6-8k WOB, ECD 10.64 Max Gas 439u. MW 9.35ppg P/U-180k, S/O-87k, ROT-119K.
Field: Ninilchik (NINU)
Sundry #:
State: ALASKA
Rig/Service:
Page 4/6
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Drill 6-3/4” Hole F/ 7139’ t/7578' MD 260 GPM= 1760 psi, 60 RPM=14 TRQ, 8-10k WOB, ECD 10.64 Max Gas 1455u. MW 9.35ppg P/U-205k, S/O-95k, ROT-130K.
Increasing lube concentration to 1%.
Report Number
14
Report Start Date
1/11/2025
Report End Date
1/12/2025
Operation
CBU twice at 257 gpm-1773 psi, 80 rpm-13,500 ft/lbs off bott torque (1% lube), MW 9.4+, obtained SPR's, 10 minute flow check fluid dropped 1'.
Pulled up hole on elevators with no issue from 7578' to 6554', S/O and parked at 6565'. Up wt 120K.
Serviced rig and topdrive, cleaned mud pump suction screens. Well on trip tank showing .25 bph loss rate.
TIH from 6565' to 7202' and set down 3 times. MU topdrive, filled pipe, washed and reamed down through trouble spot to 7260' and saw nothing. Shut down pump and
rotary, pulled stand, S/O back down through trouble spot and saw nothing. Cont RIH to 7511' with no issue, MU topdrive, filled pipe and started 20 bbl sweep, washed and
reamed to bottom at 7578'.
Pumped sweep around while rotating/reciprocating. 266 gpm-1880 psi, 80 rpm-13,000 ft/lbs off bott torque. At bottoms up hole unloaded significant amount of pes size
coal chips and clay, max gas 1263 units. Sweep back 200 strokes late and had an additional 50% increase in clay, some coal chips and fine sand.
Cont drilling from 7578' md/6988' tvd, to 7947' md/7355' tvd. Rot wob 5-9K, 260 gpm-2343 psi, 60 rpm-13,300 to 14,700 ft/lbs on bott torque, 40 to 120 ft/hr ROP.
MW 9.4+/vis 53, ECD 10.6 ppg, BGG 50 units, max gas 800 units.
Received last of lead cement in silo (868 sx total)
Drill 6-3/4” Hole F/ 7947’ t/8078' MD 260 GPM= 1840 psi, 60 RPM=14.3 TRQ, 6-10k WOB, ECD 10.58 Max Gas 280u. MW 9.5ppg P/U-210k, S/O-93k, ROT-136K.
Pumped sweep around while rotating/reciprocating. 260 gpm=1980 psi, 80 rpm=15.5K TQ. Sweep back 100 strokes with a 10% increase in cuttings.
Drill 6-3/4” Hole F/ 8078’ to TD called by town Geo at 8145'. MD 255 GPM= 1830 psi, 60 RPM=14.8 TRQ, 6-10k WOB, ECD 10.58 Max Gas 516u. MW 9.5ppg P/U-215k,
S/O-95k, ROT-135K.
Take final survey. CBU x2 260GPM=1830PSI, 80PRM=15.5K TQ. MW=9.5ppg. Max gas=198u.
Obtain SPR's. Perform flow check-slight seepage. POOH on elevators f/8145' t/7578'-without issue. P/U-265k, S/O-105k. Observed 20-30k overpul when coming out of
slips.
TIH on elevators f/7578' t/8145'- no issues. P/U-260K, S/O-100K.
M/U e-kelly and wash to bottom-no fill. Pump hi-vis sweep around back 130 strokes late with a 20% increase in cuttings. Observed 534 units of trip gas on bottoms up.
Obtain SPR's. Perform flow check-slight seepage. POOH on elevators f/8145' t/5311'-without issue. P/U-265k, S/O-105k. Observed 20-30k overpul when coming out of
slips.
Report Number
15
Report Start Date
1/12/2025
Report End Date
1/13/2025
Operation
Cont POOH from 5311' to 2809' on elevators, up wt 140K. Had occasional overpulls of 30K that cleaned up after S/O. At 2809' had to MU topdrive and backream at 260
gpm-50 rpm due to overpull and swabbing. Backreamed to 2427', CBU and unloaded hole. Cont to pull on elevators to 1553' and CBU just below surface shoe to clean up
casing. Cont to pull to BHA at 680'.
Racked back HWDP and jars. Held PJSM and removed sources, plugged in and read tools, L/D all smart tools, drained and flushed motor. 5 blade HDBS bit graded 1-1
and in gauge. (drilled 6663')
Cleaned and cleared rig floor/catwalk. Staged next BHA on catwalk. Tied in GeoSpan unit plumbing and air.
MU 6 3/4" tri-cone, bit sub and 6.56" IBS, PCG-K, DM, ADR, GeoTap, TM and flex DC. Plugged in and download to tools, ran 1 stand HWDP, MU topdrive, pressure
tested GeoSpan plumbing, shallow pulse tested and downlinked to function test GeoSpan. Cont TIH remiander HWDP and jars to 679'.
RIH on DP to 1305', filled pipe.
Hung blocks, cut and slipped 90' drill line, serviced rig and topdrive while monitor well on trip tank. Well static
RIH on elelvators f/1305' t/4610'. P/U-110k, S/O-70k.
Cont t/ RIH on elevators f/4615' t/7365' set down 30k. M/U topdrive, wash and ream t/7450'. P/U-225k, S/O-90k.
Circulate a bottoms up due to high trip gas (1679u). Hole unloading during circulation, it slowed at bottoms up.
Cont t/ RIH on elevators f/7450' t/8145'. Wash last stand down. P/U-225k, S/O-110k.
Perform clean up cycle. CBU prior to pumping hi-vis sweep. 255GPM=1520PSI, 50RPM=13.5k tq
Report Number
16
Report Start Date
1/13/2025
Report End Date
1/14/2025
Operation
Finished sweeping hole, back 300 strokes late, 25% increase. L/D single and obtained new SPR's.
Pulled up hole on elevators from 8114', up wt 210K. No issues, pulled to 7704'.
Mad passed as per Sperry, parked and GeoTapped first 5 stations. Pulled up hole from 7418' to 6064' and GeoTapped next two stations. Pulled up hole to 5862' and
GeoTapped next station. (7 stations tested thus far)
POOH f/5682' t/5469'. Mad passed as per Sperry f/5469' t/5449'. GeoTapped 5 more stations stations. Pulled up hole f/5322' t/4999' (12 stations tested thus far)
Mad passed as per Sperry f/4969' t/4949'. Geo tapped 4 more stations. Mad passed f/4641' t/4590'. Geotapped 2 more stations (17 total so far).
Report Number
17
Report Start Date
1/14/2025
Report End Date
1/15/2025
Operation
Cont testing the Beluga 136 at 4310' (bit depth 4366'), pulled up hole and tested at 4275' 4251', 4062' and 3983. Up wt 110K, max gas 16 units.
Completed testing the Beluga 120 at 3983'.
Pulled up hole from bit depth 4044' to 3178' with no issue on elevators, up wt 105K.
Mad passed from 3159' to 3139' and parked at 3019'. Tested at 3110', 3022' and 2963'.
Pulled up hole from 2964' to 2824', mad passed to 2804', up wt 77K. Tested at 2742' and 2683'.
Field: Ninilchik (NINU)
Sundry #:
State: ALASKA
Rig/Service:
Page 5/6
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Cont pulling up hole, madd passing for set depth, and testing stations 29-40. Geo-Tap depths- 2681', 2646', 2585', 2442', 2421', 2406', 2136', 2036', 1952', 1750', 1692',
and 1644'. Finished Geo-Tapping @ 1706' MD.
RIH on elevators F/1704'-T/2053' with no issues, blew down TDS.
Servicing rig at report time.
Report Number
18
Report Start Date
1/15/2025
Report End Date
1/16/2025
Operation
Cont TIH from 2053' to 4929' with no issue, down wt 60K. Filled pipe at 3304'.
MU topdrive, filled pipe and CBU staging up to 256 gpm-1228 psi, 50 rpm-8300 ft/lbs off bott torque. Max gas at bottoms up = 78 units. Blew down topdrive.
Cont TIH from 4929' to 4993' and set down 3 times, MU topdrive, washed and reamed to 5055' at 256 gpm-50 rpm, cont TIH to 5444' and set down 3 times, washed and
reamed to 5497'. Cont TIH to 6437' and filled pipe, TIH to 6471' and set down 3 times, as we washed and reamed stand down gas started climbing and peaked at 2197
units.
Cont circulating out gas. Gas dropped from 2197 to 1725 units, climed to 2100 units, dropped to 1295 units, climbed to 1551, dropped to 1270, climbed to 1558, dropped
to 200, climbed to 1769, dropped to 1457 units, at which time we started dusing active system up to 9.6+. Gas climbed to 1880, dropped to just under 200 units, so shut
down to cont trip in hole. Circulated through all this at 256 gpm-50 rpm.
Cont RIH from 6504' to 6510' and set down 3 times. Washed and reamed to 6561', RIH to 7187' and set down 3 times, washed/reamed to 7195', RIH to 7248' and set
down, washed/reamed to 7258'. TIH on elevators from7258' to 8076'.
MU topdrive, filled pipe, washed and reamed to bottom at 8145', pumped a 20 bbl hi-vis nutplug sweep around at 261 gpm-22 rpm (less rpm due to off bott torque on 3
1/2" IF connections). Had good amount of quarter size coal chips prior to bottoms up, max gas 1732 units prior to bottoms up, max gas at bottoms up 1561 units. Started
dusting up active volume to 9.7 ppg to hold back coal and gas for POOH. Sweep back 500 strokes late (29 bbls) and had an additional 50% increase in cuttings consisting
of pea size coal and silt. Cont to circ until 9.7 ppg in and out. Obtained SPR's with new mud weight, 10 minute flow check = slight seepage.
POOH F/8145'-T/1421' with 12-15K drag throughout trip. Flow checked well inside casing shoe (static). Resumed POOH T/ BHA #3. Racked back HWDP, L/D jar std.
Held PJSM. Downloaded MWD data. L/D remainder MWD tools. Graded bit- 1-1 in gauge.
Cleaned & cleared rig floor. Serviced rig- Inspected & greased crown, blocks, TDS, wash pipe, IR, DWKS, brake linkage, and drive line. Inspected saver-sub.
Drained stack. Pulled wear ring. Set test plug with 3.5" test jt. Testing annular, UPR’s, and LPR’s on 3.5” test jt.
Report Number
19
Report Start Date
1/16/2025
Report End Date
1/17/2025
Operation
Finish testing stack with 3 1/2" test joint at 250 low, 3000 high for 5 min each, on chart, RD test equipment.
Stage casing equipment, RU casing tongs and elevators, staged centralizers and liner, RU fill up line, held PJSM with rig crew, YJ Rep and tong operators.
Inspected and MU shoe track, BakerLocking connections and filling each joint. Stroked pipe and verified FE working properly. Cont PU single in hole with 3 1/2" 9.2# L-80
Type 1 Wedge 563 liner pipe, torqued to 3200 ft/lbs. From 96' to 1460', just inside surface casing. Filling on the fly, topped off every 10 jnts.
MU drive sub and topdrive, CBU with no gas, blew down topdrive.
Cont PU single in hole and enter open hole from 1463' to 3408', down wt 28K. No issues in open hole.
MU drive sub and topdrive, CBU at 3 bpm-212 psi, max gas 93 units. Shut down and blew down topdrive.
PU singled in hole from 3408' to 5809' with no issues in open hole. Down wt 45K, up wt 63K.
MU drive sub and topdrive, CBU staging up to 206 gpm-540 psi. Max gas 140 units. Shut down and blew down topdrive.
Cont. running 3.5" liner F/5809'-T/6851' with no issues. P/u-76K S/O-53K
P/U & M/U YJ Ranger hanger/Scout packer, mixed & pour 8 gals of Xan-Star into hanger TBR and inspected the 12 shear screw in neutralizing ring.
P/U and ran in 3.5" liner assy. on 2 jts of 4-3/4" 47# DC's T/6959'. M/U XO, circ. string vol. P/U-90K S/O-60K GPM-187 SPP-545 psi Flow-13% MW-9.75 ppg. Blew down
TDS.
Cont. P/U & RIH w/ 4-3/4" DC's (32 jts total) on top of liner running tool, XO to 4.5" HWDP (4 stds). Set down 10K at 8119'. M/U TDS, broke circ. Washed down F/8070',
tagged bottom at 8145'. P/U-126K S/O-95K GPM-150 SPP-605 psi Flow-11.7% MW-9.75 ppg.
CBU X 1.5 to condition mud for cmt job, while R/U Fox energy cmt's. Stagged up MP. Held PJSM. GPM-170 SPP-761 psi Flow-14.4% MW-9.75 ppg Max gas- 227 units.
L/D tag jt. Blew down TDS. Currently P/U YJ cmt head.
Report Number
20
Report Start Date
1/17/2025
Report End Date
1/18/2025
Operation
Fox pumped 3 bbls water to flush and fill lines. Shut in at YJ cement head and PT lines at 250 psi low, 4500 psi high. Good tests. Lined up YJ cement head to Fox unit,
pumped 32 bbls 11 ppg FMP300 Spacer at 3.5 bpm-500 to 450 psi, followed with 300 bbls (802 sx) 12.5 ppg Class G Lead cement at 3.9 bpm-430 to 720 psi, followed
with 26.5 bbls (121 sx) 15.3 ppg Class G Tail cement at 3.5 bpm-600 to 620 psi, good returns throughout. Had 1/2 ppb of fibre LCM in first 40 bbls of lead cement. YJ
released dart, Fox then displaced with 9.7 ppg 6% KCL mud at 4 bpm-800 to 1600 psi. 15 bbls into displacement started losing returns. Worked pipe 1’ to 2’ but string
dragging both up and down, suspect hanger slips dragging. 50 bbls into displacement string jumped hard and string weight dropped from 133K to 50K. With 20 bbls to go,
reduced rate to 2 bpm-2000 to 2470 psi. String jumped again just as we bumped plug on landing collar 66.5 bbls into displacement (calculated at 66 bbls) and we lost
another 10K in string weight (now 40K). FCP 2470 psi. Fox increased to and held 2930 psi (430 over fcp) for 3 minutes, bled back ½ bbl to truck and floats held. CIP at
09:15 on 1-17-2025. Lost 69 bbls during the job. Could not rotate due to low liner pipe MU torque. Did reciprocate until start of displacement.
Slacked off on blocks from 40K to 15K, string jumped again, giving us good indication packer set. P/U to 50K with good indication of release. PU 8’ to release dogs,
rotated at 3 rpm and set down on liner top to 15K twice more, to ensure packer set. R/D cmt hose and L/D YJ cmt head. M/U TD to stump to circulate. Pressured up to
1194 psi on drill string, PU 2’ and pressure dumped. CBU x2 at 302 gpm-492 psi. Had no spacer and no cement or contaminated mud to surface. RD and released Fox
cementers. Cleared rig floor and catwalk.
POOH racking back 4 stands HWDP, cont POOH L/D 32 joints 4 2/3" DC's. Broke down liner run tool. Neutralizer ring shear screws were not sheared on run tool.
Staged and PU YJ polish mill assembly, MU XO, RIH 8 stands HWDP then on DP. MU topdrive and pumped at 146 gpm-209 psi, S/O and tagged no-go on liner top at
1257'. PU and started rotating at 3 rpm-2700. S/O and dressed liner top with 2K wob and 3100 ft/lbs torque for a minute. Pulled up hole and parked with bottom end of mill
10' deep in upper PBR.
Field: Ninilchik (NINU)
Sundry #:
State: ALASKA
Rig/Service:
Page 6/6
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Held PJSM, cleaned shakers and belly pans, lined up and pumped 20 bbls hi-vis spacer with pump 1, brought on both pumps and displaced well to inhibited 6% KCL
brine until clean at shakers, taking returns to cuttings box.
L/D top single and performed negative pressure flow check on wellbore for 30 minutes. Well static. Prepped vac hose, thread protectors and pipe dope for L/D DP.
POOH from 1267' L/D DP, CCI vac'd wiper balls on piperack, cleaned and dried threads, doped and installed thread protectors.
Cont. RIH w/ 4.5" DP out of the derrick. POOH and L/D same, using good pipe handling practices. Working on hauling mud off to G&I.
R/U testing equip. Flooded mud lines, CM, and stack. Purged out air. Tested casing/liner lap T/3000 psi on a chart for 30 min. Pumped- 1.25 bbls Bled back- 1.2 bbls. R/D
testing equip. & blew down mud lines & CM.
Resumed TIH w/ 4.5" DP out of the derrick. POOH and L/D same, using good pipe handling practices. Working on cleaning tanks bottoms in pit modules.
Report Number
21
Report Start Date
1/18/2025
Report End Date
1/19/2025
Operation
Cont RIH and L/D the last 3300' of DP in 1000' increments.
PU and removed XO's and pups from cement head, drained stack and pulled wear ring from wellhead, PU single jnt, MU cactus brush, flushed and brushed wellhead
landing profile, functioned variable rams to purge any air from ram cavities for testing casing, L/D single and brush.
RU test equipment on kill line, flooded and purged air, closed blinds. Pumped 52.75 gallons to achieve 3225 psi on 7 5/8" x 3 1/2" casing/liner lap and liner, held 30 min
on chart, good test. Bled back 52.7 gallons. RD test equipment.
RU tubing tongs and elevators, staged seal assembly and tubing, held PJSM.
MU YJ 10' seal assembly with four 4" seals, cont PU single in hole 39 jnts to 1251'. PU two extra joints, S/O and tagged no-go at1283.67' putting WEG at 1293.74'. L/D
two joints, installed 16.70' of spaceout pups (2), MU landing joint and hanger, drained stack, pulled bushings, S/O and landed hanger at 18.86', down wt 30K, up wt 27K,
no-go 1.33' off seat. Locked in hanger as per wellhead Rep, tested hanger seals T/5000 psi for 5 min. and pull tested to 40K.
RD tubing tongs. R/U testing equip. Flooded lines, CM, and stack, purged out air.
Tested MIT-T & MIT-IA T/3000 psi on a chart for 30 min with AOGCC witness Brian Bixby (good tests). R/D testing equip.
Flushed with Barakleen pill- Surface lines, TDS, CM, MGS, MP's, and blew down same.
WHR set TWC. De-energized accumulator. Opened rams doors, cleaned cavities. Removed chains on stack, pulled riser pipe. Winterized pump room test pump.
Vacuumed out MP suction lines, cleaned out rod wash. Started going through MP's and finishing cleaning pits 1 & 2.
Crew change, held PTSM. Obtained serial numbers on rams. Changed out 3 door seals. Removed flow line and short mouse hole, installed shipping beams. Removed
flow box, R/D drain hoses, R/D kill & choke lines from mud cross. Removed accumulator lines from stack and installed caps. Un-bolted stack from spacer spool, Hoisted
off stack with bridge cranes and set on mats in front of subase. Unbolted and removed spacer spool off wellhead. Prepped wellhead. N/U tree bonnet/master valve and
test void, neck seals and tree at 5000 psi for 10 minutes, vac out fluid down to 20', topped off with diesel, installed cap and closed valve.
Released rig at 06:00 on 1-19-25
Field: Ninilchik (NINU)
Sundry #:
State: ALASKA
Rig/Service:
Pumped 52.75 gallons to achieve 3225 psi on 7 5/8" x 3 1/2" casing/liner lap and liner, held 30 minqp
on chart, good test.
Tested casing/liner lap T/3000 psi on a chart for 30 min.
Tested MIT-T & MIT-IA T/3000 psi on a chart for 30 min with AOGCC witness Brian Bixby (good tests
Page 1/1
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-133-20731-00-00 Field Name:Ninilchik (NINU)State/Province:ALASKA
Permit to Drill (PTD) #:224-145 Sundry #:325-052 Rig Name/No:
Jobs
Actual Start Date:2/1/2025 End Date:
Report Number
1
Report Start Date
1/26/2025
Report End Date
1/27/2025
Last 24hr Summary
Ran SCBL, tag PBTD @ 8075', log from PBTD 8075'- 850'.
Report Number
2
Report Start Date
2/14/2025
Report End Date
2/15/2025
Last 24hr Summary
Mobilize Fox CTU to Kalotsa 9. Complete PJSM / PTW. MIRU CTU, crane, and support equipment. BOPE test 250 psi low / 3000 psi high as per sundry. AOGCC waived
witness, Jim Regg 2/14/25 (13:30 pm). SDFN.
Report Number
3
Report Start Date
2/15/2025
Report End Date
2/16/2025
Last 24hr Summary
Complete PJSM / PTW. MIRU Fox CTU 10. M/U Slick BHA = 2" CTC, 2' Stinger, 2" DJN. Shell test 250 psi / 3000 psi. RIH w/BHA. Tagged PBTD @ E-8,102' ctm /
M-8,054' ctm. Circulate STS w/100 bbls of FW. Returns cleaned up after 6% KCI was displaced from well. Blow well dry w/N2. Pumped 90,000 scf (967 gallons). Total
fluid returns = 86 bbls. Calculated CV + CTBS = 83 bbls. Pooh w/BHA. Pressure up tubing to 2500 psi w/N2 and secure well. Begin RDMO Fox CTU 10. SDFN.
Report Number
4
Report Start Date
2/17/2025
Report End Date
2/17/2025
Last 24hr Summary
PTW/PJSM. 2636 psi SITP. MIRU YJ E-line. PT lubricator to 3000 psi - good test. RIH w/ GPT and tag @ 8,076' and find fluid level ~ 7,945'. RIH w/ 29' x 2 3/8" 5 SPF
60 DEG guns and perf TY_120 (7,988' - 8,017'). RIH w/ GPT and find fluid level ~ 7,910'. Bleed well down in 200 psi increments @ 5 psi/min and monitor fluid level.
Last fluid level @ 2,080 psi was 7,895'. Secure well, SDFN.
Report Number
5
Report Start Date
2/18/2025
Report End Date
2/18/2025
Last 24hr Summary
PTW/PJSM. 2120 psi SITP. RU YJ E-line. RIH w/ GPT and tag @ 8,075' and find fluid level ~ 7,815'. RIH w/ 12' x 2 3/8" 5 SPF 60 DEG guns and perf TY_118 Lower
(7,968’ – 7,980’). RIH w/ 16' x 2 3/8" 5 SPF 60 DEG guns and perf TY_118 Upper (7,932’ – 7,948’). RIH w/ 6' x 2 3/8" 5 SPF 60 DEG guns and perf TY_115 (7,862’ –
7,868’). RIH w/ GPT and find fluid level ~ 7,775'. Bleed well down in 200 psi increments @ 5 psi/min and monitor fluid level. Last fluid level @ 1,350 psi was 7,704'.
Bleed well down to 1000 psi and shut in. Secure well, SDFN.
Report Number
6
Report Start Date
2/19/2025
Report End Date
2/19/2025
Last 24hr Summary
PTW/PJSM. 1145 psi SITP. RU YJ E-line. RIH w/ GPT and tag @ 8,073' and find fluid level ~ 7,386'. RD YJ E-line. Bleed well pressure to 425psi looking for LEL's-
none. RU Fox N2. PT lines to 5K psi and pressure up well from 460 psi to 4500 psi - did not see breakover. Pumped 164K SCF (1764 gals) N2. Shut in well, SDFN.
Report Number
7
Report Start Date
2/20/2025
Report End Date
2/21/2025
Last 24hr Summary
WHP 2810 psi. MIRU YJ E-line. PT lubricator to 3000 psi. RIH w/ GPT, tagged 8073' elm. See FL @ 8005'. Discuss plan forward. Set 2.75" CIBP @ 7,820' elm. Bleed
WHP to 930 psi. Dump 4 gallons of cement on top of CIBP. Calculated TOC = 7810'. SDFN.
Report Number
8
Report Start Date
2/21/2025
Report End Date
2/22/2025
Last 24hr Summary
PTW/PJSM. WHP 930 psi. MIRU YJ E-line. PT lubricator to 3000 psi. RIH w/ 2-3/8" x 26' gun (5 spf, 60 deg). Bleed WHP to 250 psi. Correlate and send logs to
OE/Res/Geo. Perforate TY_90 sands 7,599' - 7,625'. Run 2 more guns and tie in with CCL, shift .5' down as per Geo. Perforate TY_90 sands 7,520' - 7,586'. SDFN to
bleed & test well.
Report Number
9
Report Start Date
2/26/2025
Report End Date
2/27/2025
Last 24hr Summary
PTW/PJSM. MIRU Yellow Jacket E-line. P-test 250/3,000 psi. Run GPT - fluid level at 7,245'. Pressure up well to 3,040 psi with N2 and push fluid down to 7,550'. Set
WRP at 7,515'. GIH with guns to perf the TY-87 Sand - gamma tool not working properly while pulling correlation log. POH and SDFN.
Report Number
10
Report Start Date
2/27/2025
Report End Date
2/28/2025
Last 24hr Summary
PTW/PJSM. MIRU YJ E-line. PT PCE 250 psi low/3000 psi high. RIH w/2" x 20' x 10' switch guns (6 spf, 60 deg). Correlate and sent logs to Geo/OE/Res. WHP 2700 psi.
Perforated TY_87 sands 7453'-7463'. Perforated TY_87 sands overlap shots 7453'-7473'. WHP stabile 2412 psi. Confirm all shots fired, guns dry. Secure well and turn
well over to Ops. Bleed N2 off well and flow to production. SDFN.
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Page 1/1
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025
WellViewAdmin@hilcorp.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
8,145.00 Original KB/RT Elevation (ft):
144.50
RKB to GL (ft):
18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
8,077.3
Casing
Casing Description:
Surface Run Date:
1/3/2025 Set Depth (ftKB):
1,463.00
Casing Weight on Slips (1000lbf):
33,000.0 Pick Up Weight (1000lbf):
52,000.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
3.50 Ft/Min (ft/min):
6.97
Run Job:
251-00001 Kalotsa 9 Drilling, Drilling -
Drilling, 12/29/2024 06:00
Set Depth (ftKB):
1,463.00 Set Depth (TVD) (ftKB):
1,356.3
Centralizer Detail:
17
Attribute Subtype: Value:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Casing Hanger 15 6.88 1.27 22.67 21.40
1 Casing Pup Joint 7 5/8 6.88 29.70 L-80 BTC 3.10 25.77 22.67
72 Casing Joints 7 5/8 6.88 29.70 L-80 GBCD-BTC 1,351.30 1,377.07 25.77
1 Float Collar 8 5/8 GBCD-BTC 1.44 1,378.51 1,377.07
2 Casing Joints 7 5/8 6.88 29.70 L-80 BTC 82.88 1,461.39 1,378.51
1 Float Shoe 8 5/8 BTC 1.61 1,463.00 1,461.39
Page 1/1
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025
WellViewAdmin@hilcorp.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 1,463.00ftKB
Wellbore
Original Hole
Job
251-00001 Kalotsa 9 Drilling, Drilling -
Drilling, 12/29/2024 06:00
Cementing Start Date
1/3/2025
Cementing End Date
1/3/2025
Top Depth (ftKB)
21.4
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
21.4
Bottom Depth (ftKB)
1,483.0
Top Measurement Method
Returns to Surface
Pump Start Date
1/3/2025
Cement in Place At
1/3/2025
Final Circulating Pressure (psi)
410.0
Plug Bump Pressure (psi)
2,360.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
43.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer)10.50 68.0 60.0 3 Fox Energy
Lead Slurry G 230 2.10 12.50 86.0 77.0 5 Fox Energy
Tail Slurry G 164 1.23 15.30 36.0 38.0 2 Fox Energy
Displacement 9.10 63.0 64.0 4 Fox Energy
Post Job Calculations
Subtype Value
Page 1/1
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025
WellViewAdmin@hilcorp.com
Casing
Siner
Welluore
Welluore Name:
Original Hole f otal bepth oTWelluore DTtK( B:8,145.00 ) riginal K( /Rf OleEation DTtB:144.50
RK( to v S DTtB:18.00 K( GCasing Llange bistance DTtB:K(Gf - uing Fanger bistance DTtB:
P( f bs
bepthDTtK( B:8,077.3
Casing
Casing bescription:
Liner R- n bate:
1/16/2025 Het bepth DTtK( B:8,143.00
Casing Weight on Hlips D1000luTB:PickUpWeightD1000luTB:133,000.0 ( lock Weight D1000luTB:15,000.0
MakeGUp Contractor:
Parker Casing N- muer Frs to R- n DhrB:19.75 Lt/Min DTt/minB:6.87
R- n Jou:
251-00001 Kalotsa 9 Drilling, Drilling -
Drilling, 12/29/2024 06:00
Het bepth DTtK( B:8,143.00 Het bepth DfVbBDTtK( B:7,549.3
Centralizer betail:
222 total spiral gliders
Attriu- te H- utype: Val- e:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Lloat Lailed?:
No
f est H- utype: Press- re DpsiB:
Casing D) r SinerBbetails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Liner Hanger 6.52 4.00 Ranger Hanger 35.48 1,292.51 1,257.03
1 Cross Over 5 1/2 2.99 17.00 VAM VAM 1.98 1,294.49 1,292.51
21 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 655.10 1,949.59 1,294.49
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.01 1,959.60 1,949.59
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.90 2,460.50 1,959.60
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.02 2,470.52 2,460.50
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.32 2,971.84 2,470.52
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.00 2,981.84 2,971.84
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.23 3,483.07 2,981.84
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.03 3,493.10 3,483.07
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.97 3,994.07 3,493.10
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.00 4,004.07 3,994.07
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.94 4,505.01 4,004.07
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.01 4,515.02 4,505.01
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.22 5,016.24 4,515.02
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.00 5,026.24 5,016.24
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 499.39 5,525.63 5,026.24
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.00 5,535.63 5,525.63
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.56 6,036.19 5,535.63
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.01 6,046.20 6,036.19
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.84 6,547.04 6,046.20
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.69 6,556.73 6,547.04
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.96 7,057.69 6,556.73
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.01 7,067.70 7,057.69
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 499.59 7,567.29 7,067.70
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 10.02 7,577.31 7,567.29
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.03 8,077.34 7,577.31
1 Float Collar 3 1/2 Wedge 563 Innovex 1.69 8,079.03 8,077.34
2 Liner 3 1/2 2.99 9.20 L-80 IBT 62.08 8,141.11 8,079.03
1 Float Shoe 3 1/2 IBT Innovex 1.89 8,143.00 8,141.11
Page 1/1
Well Name: NINU Kalotsa 09
Report Printed: 3/12/2025
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Siner Ceu ent
Ceu entef mtring
Sinerd, d1463..0tKB
Wellbore
Original Hole
Job
251-. . . . 1 Kalotsa 9 DrillingdDrilling -
Drillingd 12/29/2. 24 . : E..
Ceu enting mtart Date
1/1h/2. 25
Ceu enting ( nf Date
1/1h/2. 25
Top Dept) 80tKBM
1d4423.
Cement Stages
Stage Number: 1
Description
Siner Ceu ent
Top Dept) 80tKBM
1d4423.
Bottou Dept) 80tKBM
,d1453.
Top ReasPreu ent Ret) of
CBS1-2: -25
FPu p mtart Date
1/1h/2. 25
Ceu ent in Flace At
1/1h/2. 25
?inal CircPlating FressPre 8psiM
2d4h. 3.
FlPg BPu p FressPre 8psiM
2d4h. 3.
?Pll YetPrn%
Vo
YetPrns DPring Job 8L M
,.35
NolPu e to mPr0ace 8bblM
.3.
NolPu e Sost 8bblM
:93.
BPu p FlPg%
kes
?loat ?ailef %
Vo
Fipe Yeciprocatef %
kes
Fipe Yotatef %
Vo
mlPrry Type Class Au oPnt 8sac³sM kielf 80tQ/sac³M Dens 8lb/galM
ActPal NolPu e
FPu pef 8bblM
CalcPlatef
NolPu e FPu pef
8bblM v AUg 8bbl/u inM FPu p x sef
Fre0lPs) 8mpacerM ?RF6. . ?RF6. . 113.. 623.6.3.4?oG(nergy
Seaf mlPrry Seaf 7 , . 2 231. 1235. 6. . 3.29:3. 4 ?oG( nergy
Tail mlPrry Seaf 7 121 1326 1536. 2: 35243.4?oG(nergy
Displaceu ent : L KCS
RPf
93h. : : 35::3. 4 ?oG( nergy
Post Job Calculations
mPbtype NalPe
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, March 13, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Brian Bixby
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
KALOTSA 9
NINILCHIK UNIT KALOTSA 9
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 03/13/2025
KALOTSA 9
50-133-20731-00-00
224-145-0
N
SPT
1217
2241450 3000
0 3200 3185 3175
0 0 0 0
OTHER P
Brian Bixby
1/18/2025
MIT-T as per Drilling Program to 3000psi.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:NINILCHIK UNIT KALOTSA 9
Inspection Date:
Tubing
OA
Packer Depth
0 0 0 0IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitBDB250119094229
BBL Pumped:0.7 BBL Returned:0.7
Thursday, March 13, 2025 Page 1 of 1
9
9
9
9
9 9
999
9
9
9
MIT-T
James B. Regg Digitally signed by James B. Regg
Date: 2025.03.13 10:49:48 -08'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, March 13, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Brian Bixby
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
KALOTSA 9
NINILCHIK UNIT KALOTSA 9
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 03/13/2025
KALOTSA 9
50-133-20731-00-00
224-145-0
N
SPT
1217
2241450 3000
0 64 61 60
0 0 0 0
OTHER P
Brian Bixby
1/18/2025
MIT-IA as per Drilling Program to 3000psi.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:NINILCHIK UNIT KALOTSA 9
Inspection Date:
Tubing
OA
Packer Depth
0 3215 3150 3100IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitBDB250119095333
BBL Pumped:0.6 BBL Returned:0.6
Thursday, March 13, 2025 Page 1 of 1
9
9
9
9 999
9
9 9
9
9
9
*DVSURGXFHU
MIT-IA
James B. Regg Digitally signed by James B. Regg
Date: 2025.03.13 10:47:36 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 2/16/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250216
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset #
BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf
CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL
CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL
CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL
CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL
IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf
KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL
KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL
KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL
KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL
MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF
NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf
PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT
PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT
PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT
PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN
PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT
PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL
PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT
Revision Explanation: Annotations added to processed log.
Please include current contact information if different from above.
162-037 T40080
T40081
T40082
T40082
T40083
T40084
T40085
T40086
T40087
T40088
T40089
T40090
T40091
T40092
T40093
T40094
T40095
T40096
T40097
KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.18 13:06:47 -09'00'
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: 02/07/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: KALOTSA 9
PTD: 224-145
API: 50-133-20731-00-00
FINAL LWD FORMATION EVALUATION LOGS (01/02/2025 to 01/11/2025)
ROP, DGR, ADR, PCG-K, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL GEOTAP Subfolders:
Please include current contact information if different from above.
224-145
T40069
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.10 08:18:24 -09'00'
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, 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:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
8,145'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
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
LTP; N/A 1,257' MD/1,206' TVD; N/A
7,551'8,143'7,549'
Ninilchik Beluga-Tyonek Gas
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
NINU Kalotsa 9CO 701C
Same
7,549'3-1/2"
~2515psi
6,886'
N/A
Length
February 10, 2025
Tieback 3-1/2"
8,143'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,890psi
120'120'
1,463'
Size
120'
1,482'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
1,257'
10,160psi
1,356'
Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
CO61505; ADL 384372
224-145
50-133-20731-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Scott Warner, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
scott.warner@hilcorp.com
907-564-4506
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 1:57 pm, Jan 31, 2025
325-052
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.01.31 13:25:05 -
09'00'
Noel Nocas
(4361)
10-407
Perforate
CT BOP test to 3000 psi
SFD 2/6/2025 DSR-1/31/25
X
February 10, 2025
BJM 2/6/25*&:
2/7/2025Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.02.07 09:05:34 -09'00'
RBDMS JSB 021025
Well Prognosis
Well Name: Kalotsa 9 API Number: 50-133-20731-00-00
Current Status: New Drill Well Permit to Drill Number: 224-145
Regulatory Contact: Donna Ambruz (907) 777-8305
First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C)
Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C)
Maximum Expected BHP: 3254 psi @ 7395’ TVD (Based on 0.44 psi/ft gradient)
Max. Potential Surface Pressure:2515 psi (Based on 0.1 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.97 psi/ft using 18.7 ppg EMW FIT at the 7-5/8” surface casing shoe
Shallowest Allowable Perf TVD: MPSP/(0.97-0.1) = 2515 psi / 0.87 = 2890‘ TVD
Top of Applicable Gas Pool: 1575’ MD/1431’ TVD (Beluga-Tyonek)
Well Status: New Drill Initial Completion
Brief Well Summary
Kalotsa 9 is a new drill well targeting the Tyonek and Beluga sands. The objective of this sundry is to clean out
the liner with coil tubing/nitrogen and perforate the Tyonek 3-120.
Wellbore Conditions:
- Max Inclination – 48.4° at 1,508’ MD
- Max DLS °/100’ – 6.5° at 1,334’ MD
- Liner is full of ~9.1 ppg 6% KCl mud
- Tubing and IA are displaced to 8.4 ppg CIW
- T & IA have been pressure tested to 3000 psi
Pre-Sundry Work (Already Completed):
1. Review all approved COAs
2. MIRU E-line and pressure control equipment
3. Log well with CBL tool in 3-1/2” liner (send results to AOGCC to review prior to perforating)
a. CBL will be sent to AOGCC at the time of Sundry submittal
4. RDMO E-line
Procedure:
1. MIRU Coil Tubing and pressure control equipment
2. PT BOPE to 250 psi low / 3,000 psi high
a. Provide AOGCC 24hr notice for BOP test
3. RIH & clean out wellbore to ~8070’ MD (~7’ above landing collar), displace liner to 8.4 ppg water
4. Reverse out wellbore with nitrogen, trap ~2400 psi on wellbore
a. ~70 bbls total wellbore volume
5. RDMO Coil Tubing
6. MIRU E-line and pressure control equipment
7. PT lubricator to 250 psi low / 3,000 psi high
8. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically
targeting 20% underbalance)
9. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up:
Received CBL 2/6/25. TOC is well above planned
top perf.
-bjm
It is unlikely that formation strength
is 18.7 ppg from sc shoe to TD.
Use known FIT/LOT data in the area
to plot pore-pressure/frac gradient
curve and determine shallowest
allowable perf.
The shallowest planned perf in this
well 3815' TVD, which is approved.
-bjm
Well Prognosis
Below are proposed targeted sands in order of testing
(bottom/up), but additional sand may be added depending on
results of these perfs, between the proposed top and bottom perfs
Sand Top MD Btm MD Top TVD Btm TVD Interval
TY_3 ±4,377' ±4,414' ±3,815' ±3,852' ±37'
TY_3 ±4,423' ±4,433' ±3,861' ±3,871' ±10'
TY_3 ±4,451' ±4,457' ±3,888' ±3,895' ±6'
TY_3 ±4,481' ±4,487' ±3,918' ±3,924' ±6'
TY_5 ±4,534' ±4,540' ±3,971' ±3,977' ±6'
TY_5A ±4,565' ±4,571' ±4,002' ±4,008' ±6'
TY_5B ±4,619' ±4,633' ±4,055' ±4,069' ±14'
TY_6 ±4,658' ±4,668' ±4,093' ±4,104' ±10'
TY_6 ±4,690' ±4,703' ±4,125' ±4,138' ±13'
TY_7 ±4,762' ±4,768' ±4,197' ±4,203' ±6'
TY_7 ±4,772' ±4,792' ±4,206' ±4,226' ±20'
TY_7 ±4,799' ±4,805' ±4,233' ±4,239' ±6'
TY_8 ±4,854' ±4,876' ±4,288' ±4,309' ±22'
TY_9 ±4,905' ±4,911' ±4,338' ±4,344' ±6'
TY_9 ±4,930' ±4,936' ±4,363' ±4,369' ±6'
TY_9A ±4,954' ±4,974' ±4,386' ±4,406' ±20'
TY_10B ±5,034' ±5,044' ±4,465' ±4,475' ±10'
TY_10B ±5,052' ±5,058' ±4,483' ±4,489' ±6'
TY_10B ±5,059' ±5,065' ±4,490' ±4,496' ±6'
TY_12 ±5,256' ±5,326' ±4,685' ±4,755' ±70'
TY_13 ±5,500' ±5,506' ±4,927' ±4,933' ±6'
TY_16 ±5,712' ±5,720' ±5,138' ±5,146' ±8'
TY_17 ±5,793' ±5,833' ±5,218' ±5,258' ±40'
TY_18 ±5,909' ±5,915' ±5,333' ±5,339' ±6'
TY_18 ±5,970' ±5,980' ±5,394' ±5,404' ±10'
TY_43 ±6,352' ±6,362' ±5,771' ±5,781' ±10'
TY_43 ±6,374' ±6,384' ±5,793' ±5,803' ±10'
TY_69 ±7,198' ±7,218' ±6,611' ±6,631' ±20'
TY_83 ±7,354' ±7,384' ±6,765' ±6,795' ±30'
TY_87 ±7,453' ±7,473' ±6,864' ±6,884' ±20'
TY_90 ±7,520' ±7,526' ±6,931' ±6,937' ±6'
TY_90 ±7,532' ±7,572' ±6,942' ±6,982' ±40'
TY_90 ±7,605' ±7,625' ±7,015' ±7,035' ±20'
TY_90 ±7,630' ±7,670' ±7,040' ±7,080' ±40'
TY_115 ±7,862' ±7,868' ±7,270' ±7,276' ±6'
TY_118 ±7,932' ±7,948' ±7,340' ±7,356' ±16'
TY_118 ±7,968' ±7,980' ±7,375' ±7,387' ±12'
TY_120 ±7,988' ±8,017' ±7,395' ±7,424' ±29'
Well Prognosis
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations
i. Pending well production, all perf intervals may not be completed
ii. Note: Note: A CIBP may be used instead of WRP if it is determined that no cement
is needed for operational purposes.
iii. If necessary, use nitrogen to pressure up well during perforating or to depress
water prior to setting a plug above perforations
10. RDMO
11. Turn well over to production & flow test well
12. Test SVS as necessary once well has reached stable flow rates
a. Notify state 48 hrs prior to testing within 5 days of stable production
Coil Procedure (Contingency)
1. MIRU Coil Tubing, PT BOPE to 250 psi low / 3,000 psi high
a. Provide AOGCC 24 hr notice for BOP test
2. PU wash nozzle and/or motor and mill, RIH and cleanout well to below perfs or proposed plug depth
3. PU CT jet nozzle and RIH, unload fluid from wellbore with nitrogen
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Coil Tubing BOP Schematic
4. Standard Well Procedure – N2 Operations
Updated by SRW 1-31-25
CURRENT SCHEMATIC
Ninilchik Unit
Kalotsa 9
PTD: 224-145
API: 50-133-20731-00-00
PBTD = 8,143’ / TVD = 7,549’
TD = 8,145’ / TVD = 7,551’
RKB to GL = 18.86’
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 GBCD 6.875” Surf 1,463’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 1,257’ 8,143’
3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf 1,257’
JEWELRY DETAIL
No. Depth ID OD Item
1 1,257’ 2.992” 3.50” Liner hanger / LTP Assembly
2 1,257’ 2.992” 3.50” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8"
Est. TOC @ Surface: 68 bbl 10.5 ppg spacer, 86 bbl 12.5 ppg class G lead cement
followed by 36 bbl 15.3 class G tail cement. Bumped plug at 63 bbls (calculated 64
bbls)
3-1/2” TOC @ 1,442’ (1-26-25 CBL)
2
16”
7-5/8”
9-7/8”
hole
3-1/2”
6-3/4”
hole
1
Updated by SRW 1-31-25
PROPOSED SCHEMATIC
Ninilchik Unit
Kalotsa 9
PTD: 224-145
API: 50-133-20731-00-00
PBTD = 8,143’ / TVD = 7,549’
TD = 8,145’ / TVD = 7,551’
RKB to GL = 18.86’
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 GBCD 6.875” Surf 1,463’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 1,257’ 8,143’
3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf 1,257’
JEWELRY DETAIL
No. Depth ID OD Item
1 1,257’ 2.992” 3.50” Liner hanger / LTP Assembly
2 1,257’ 2.992” 3.50” Seal Stem
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_3 ±4,377' ±4,414' ±3,815' ±3,852' ±37' Proposed TBD
TY_3 ±4,423' ±4,433' ±3,861' ±3,871' ±10' Proposed TBD
TY_3 ±4,451' ±4,457' ±3,888' ±3,895' ±6' Proposed TBD
TY_3 ±4,481' ±4,487' ±3,918' ±3,924' ±6' Proposed TBD
TY_5 ±4,534' ±4,540' ±3,971' ±3,977' ±6' Proposed TBD
TY_5A ±4,565' ±4,571' ±4,002' ±4,008' ±6' Proposed TBD
TY_5B ±4,619' ±4,633' ±4,055' ±4,069' ±14' Proposed TBD
TY_6 ±4,658' ±4,668' ±4,093' ±4,104' ±10' Proposed TBD
TY_6 ±4,690' ±4,703' ±4,125' ±4,138' ±13' Proposed TBD
TY_7 ±4,762' ±4,768' ±4,197' ±4,203' ±6' Proposed TBD
TY_7 ±4,772' ±4,792' ±4,206' ±4,226' ±20' Proposed TBD
TY_7 ±4,799' ±4,805' ±4,233' ±4,239' ±6' Proposed TBD
TY_8 ±4,854' ±4,876' ±4,288' ±4,309' ±22' Proposed TBD
TY_9 ±4,905' ±4,911' ±4,338' ±4,344' ±6' Proposed TBD
TY_9 ±4,930' ±4,936' ±4,363' ±4,369' ±6' Proposed TBD
TY_9A ±4,954' ±4,974' ±4,386' ±4,406' ±20' Proposed TBD
TY_10B ±5,034' ±5,044' ±4,465' ±4,475' ±10' Proposed TBD
TY_10B ±5,052' ±5,058' ±4,483' ±4,489' ±6' Proposed TBD
TY_10B ±5,059' ±5,065' ±4,490' ±4,496' ±6' Proposed TBD
TY_12 ±5,256' ±5,326' ±4,685' ±4,755' ±70' Proposed TBD
TY_13 ±5,500' ±5,506' ±4,927' ±4,933' ±6' Proposed TBD
TY_16 ±5,712' ±5,720' ±5,138' ±5,146' ±8' Proposed TBD
TY_17 ±5,793' ±5,833' ±5,218' ±5,258' ±40' Proposed TBD
TY_18 ±5,909' ±5,915' ±5,333' ±5,339' ±6' Proposed TBD
TY_18 ±5,970' ±5,980' ±5,394' ±5,404' ±10' Proposed TBD
TY_43 ±6,352' ±6,362' ±5,771' ±5,781' ±10' Proposed TBD
TY_43 ±6,374' ±6,384' ±5,793' ±5,803' ±10' Proposed TBD
TY_69 ±7,198' ±7,218' ±6,611' ±6,631' ±20' Proposed TBD
TY_83 ±7,354' ±7,384' ±6,765' ±6,795' ±30' Proposed TBD
TY_87 ±7,453' ±7,473' ±6,864' ±6,884' ±20' Proposed TBD
TY_90 ±7,520' ±7,526' ±6,931' ±6,937' ±6' Proposed TBD
TY_90 ±7,532' ±7,572' ±6,942' ±6,982' ±40' Proposed TBD
TY_90 ±7,605' ±7,625' ±7,015' ±7,035' ±20' Proposed TBD
TY_90 ±7,630' ±7,670' ±7,040' ±7,080' ±40' Proposed TBD
TY_115 ±7,862' ±7,868' ±7,270' ±7,276' ±6' Proposed TBD
TY_118 ±7,932' ±7,948' ±7,340' ±7,356' ±16' Proposed TBD
TY_118 ±7,968' ±7,980' ±7,375' ±7,387' ±12' Proposed TBD
TY_120 ±7,988' ±8,017' ±7,395' ±7,424' ±29' Proposed TBD
OPEN HOLE / CEMENT DETAIL
7-5/8"
Est. TOC @ Surface: 68 bbl 10.5 ppg spacer, 86 bbl 12.5 ppg class G lead cement
followed by 36 bbl 15.3 class G tail cement. Bumped plug at 63 bbls (calculated 64
bbls)
3-1/2” TOC @ 1,442’ (1-26-25 CBL)
2
16”
7-5/8”
9-7/8”
hole
3-1/2”
6-3/4”
hole
1
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.
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:Scott Warner
Subject:RE: Kalotsa 9 PTD 224-145 - Pre Completion Sundry CBL Approval
Date:Friday, January 24, 2025 10:00:00 AM
Scott,
Yes Hilcorp can run a CBL without a sundry. Thanks.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Scott Warner <Scott.Warner@hilcorp.com>
Sent: Friday, January 24, 2025 9:32 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Kalotsa 9 PTD 224-145 - Pre Completion Sundry CBL Approval
Bryan,
The Kalotsa 9 production liner cement job did not go exactly as planned and I am hoping to get on
the well as soon as possible to run a CBL and identify if a remedial squeeze will be necessary. We
have been waiting for drilling to complete the surface section on Kalotsa 10 and if we can get an
Eline unit rigged up on 9 while the rig is there, we would like to run the CBL prior to the rig finishing
drilling on Kalotsa 10.
Once the CBL is run and analyzed, the completion sundry will be submitted to include any
remediation cement work that is needed along with the perf intervals/strategy.
Please let me know if it is ok to proceed with the CBL prior to submitting the completion sundry.
Thanks,
Scott Warner
Kenai – Operations Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
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:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Subject:RE: Kalotsa 9 FIT (224-145)
Date:Monday, January 6, 2025 10:56:00 AM
Sean,
Hilcorp has approval to drill ahead to TD per the approved PTD.
Note that the Kick tolerance will decrease as mud weight increases, assuming swab kick
scenario. I calculate just under 20 bbls KTV assuming 9 ppg mud in the hole, but the KTV
decreases to 14 bbls if mud weight increases to 10 ppg.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Monday, January 6, 2025 6:01 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Kalotsa 9 FIT (224-145)
Bryan,
With the 18.7# FIT I calculate a 20 bbl KTV. We are currently drilling ahead.
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Manager
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of 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, 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________NINILCHIK UNIT KALOTSA 9
JBR 02/10/2025
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
Arrived on Location at 09:00 01/04/25 and was told they would be ready when I left Anchorage. Got on location and BOPE was
not completely together and nippled up to the well. They then had door closure problems on one side of blind rams that took
some time to fix chasing threads on BOPE and annular cap was also loose. This took until about 18:00 shell test had some
issues and finally started test at 20:00; had 1 Fail on upper kelly replaced and passed this was replaced while doing other tests
and tested later in the test. Used 4-1/2" TJ accumulator bottle precharge avg 15 @ 1020 psi.
Test Results
TEST DATA
Rig Rep:Kenneth PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Justin Gruenberg
Rig Owner/Rig No.:Hilcorp 169 PTD#:2241450 DATE:1/5/2025
Type Operation:DRILL Annular:
250/5000Type Test:INIT
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopKPS250106094150
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 4.5
MASP:
2674
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 FP
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 11"P
#1 Rams 1 2-7/8" x 5" V P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8" x 5" V P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8&2-1/16 P
Kill Line Valves 1 2-1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1700
200 PSI Attained P25
Full Pressure Attained P98
Blind Switch Covers:Pall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4@2462
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P11
#1 Rams P5
#2 Rams P5
#3 Rams P5
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9999
9
9
9
9Arrived on Location at 09:00 01/04/25
finally started test at 20:00 1 Fail on upper kelly
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Sean McLaughlin
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Ninilchik Unit, Beluga/Tyonek Gas Pool, NINU Kalotsa 9
Hilcorp Alaska, LLC
Permit to Drill Number: 224-145
Surface Location: 2116' FSL, 507' FWL, Sec 7, T1S, R13W, SM, AK
Bottomhole Location: 1223' FNL, 1051' FEL, Sec 12, T1S, R14W, SM, AK
Dear Mr. McLaughlin:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this 16th day of December 2024.
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2024.12.16
08:30:32 -09'00'
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 8,413' TVD: 7,865'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 144.5 15. Distance to Nearest Well Open
Surface: x-209903 y-2233390 Zone-4 126.5 to Same Pool: 200' to Kalotsa 4
16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 37 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 GBCD 1,430' Surface Surface 1,430' 1,394'
6-3/4" 3-1/2" 9.2# L-80 Hyd 563 7,183' 1,230' 1,210' 8,413' 7,865'
Tieback 3-1/2" 9.2# L-80 EUE 1,230' Surface Surface 1,230' 1,210'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Kalotsa 9
Ninilchik Unit
Beluga/Tyonek Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
L - 1687 ft3 / T - 131 ft3
2674
2399' FSL, 340' FWL, Sec 7, T1S, R13W, SM, AK
1223' FNL, 1051' FEL, Sec 12, T1S, R14W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
2116' FSL, 507' FWL, Sec 7, T1S, R13W, SM, AK C061505, ADL 384372
18. Casing Program:Top - Setting Depth - BottomSpecifications
3461
GL / BF Elevation above MSL (ft):
Plugs (measured):
(including stage data)
Driven
L - 414 ft3 / T - 208 ft3
Effect. Depth MD (ft):Effect. Depth TVD (ft):
LengthCasing Size
Conductor/Structural
Authorized Title:
Authorized Signature:
Authorized Name:
Production
Liner
Intermediate
Drilling Manager
Sean Mclaughlin
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
12/25/2024
3588' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
Tieback Assy.
4762
Cement Volume MD
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s Nos No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Grace Christianson at 2:37 pm, Nov 18, 2024
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2024.11.18 09:57:22 -
09'00'
Sean
McLaughlin
(4311)
Minimum FIT of 18 ppg is required to drill to planned TD.
BOP test to 3000 psi. Annular test to 2500 psi.
Submit FIT/LOT results and obtain approval from AOGCC before drilling ahead.
BJM 12/13/24
50-133-20731-00-00
DSR-11/21/24A.Dewhurst 06DEC24
224-145
NINU
*&:
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.12.16 08:30:48 -09'00'
12/16/24
12/16/24
RBDMS JSB 121724
KALOTSA 9
PTD Program
Ninilchik Field
November 13, 2024
KALOTSA 9
Drilling Procedure
Contents
1.0 Well Summary................................................................................................................................2
2.0 Management of Change Information...........................................................................................3
3.0 Tubular Program:..........................................................................................................................4
4.0 Drill Pipe Information:..................................................................................................................4
5.0 Internal Reporting Requirements................................................................................................5
6.0 Planned Wellbore Schematic........................................................................................................6
7.0 Drilling / Completion Summary...................................................................................................7
8.0 Mandatory Regulatory Compliance / Notifications....................................................................8
9.0 R/U and Preparatory Work........................................................................................................10
10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11
11.0 Drill 9-7/8” Hole Section..............................................................................................................12
12.0 Run 7-5/8” Surface Casing..........................................................................................................14
13.0 Cement 7-5/8” Surface Casing....................................................................................................16
14.0 BOP N/U and Test........................................................................................................................18
15.0 Drill 6-3/4” Hole Section..............................................................................................................19
16.0 Run 3-1/2” Production Liner......................................................................................................22
17.0 Cement 3-1/2” Production Liner................................................................................................25
18.0 3-1/2” Liner Tieback Polish Run................................................................................................28
19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................29
20.0 Diverter Schematic ......................................................................................................................30
21.0 BOP Schematic.............................................................................................................................31
22.0 Wellhead Schematic.....................................................................................................................32
23.0 Anticipated Drilling Hazards......................................................................................................33
24.0 Hilcorp Rig 169 Layout...............................................................................................................35
25.0 FIT/LOT Procedure ....................................................................................................................36
26.0 Choke Manifold Schematic.........................................................................................................37
27.0 Casing Design Information.........................................................................................................38
28.0 6-3/4” Hole Section MASP..........................................................................................................39
29.0 Spider Plot....................................................................................................................................40
30.0 Surface Plat As-Built...................................................................................................................41
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1.0 Well Summary
Well KALOTSA 9
Pad & Old Well Designation Kalotsa Pad – Grassroots Well
Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore)
Target Reservoir(s)Tyonek / Lower Beluga
Planned Well TD, MD / TVD 8413 MD / 7865’ TVD
PBTD, MD / TVD 8313’ MD
AFE Number
AFE Drilling Days
AFE Drilling Amount
Maximum Anticipated Pressure
(Surface)2674 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3461 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB 144.50’
Ground Elevation 126.50’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
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Drilling Procedure
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 -
Surface
9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 GBCD 6890 4790 683
Prod
6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207
** Liner must overlap surface casing by at least 100’.
4.0 Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellView.
x Report covers operations from 6am to 6am
x Ensure time entry adds up to 24 hours total.
x Capture any out-of-scope work as NPT.
5.2 Afternoon Updates
x Submit a short operations update each day to kenaiciodrilling@hilcorp.com
5.3 Morning Update
x Submit a short operations update each morning by 7am in NDE – Drilling Comments
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855
2. Spills:
x Notify Drlg Manager
1. Sean McLaughlin: C: 907-223-6784
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com,and
cdinger@hilcorp.com
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Drilling Procedure
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
KALOTSA 9 is an S-shaped directional grassroots development well to be drilled from Kalotsa Pad.
Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the
Tyonek and Lower Beluga sands.
The base plan is an S-shaped directional wellbore with a kickoff point at ~500’ MD. Maximum hole angle
will be ~37 deg. and TD of the well will be 8413’ TMD/ 7865’ TVD, ending with 10 deg inclination.
Drilling operations are expected to commence approximately December, 2024. The Hilcorp Rig # 169 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to 1430’ MD / 1394’ TVD and cemented to surface to ensure protection of any
shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface
are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine
TOC. Necessary remedial action will then be discussed with AOGCC authorities.
All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste
Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial
reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 169 to wellsite
2. N/U diverter and test.
3. Drill 9-7/8” hole to 1430’ MD. Run and cmt 7-5/8” surface casing.
4. Test casing to 3500 psi. Perform 17.0# FIT
5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi
6. Drill 6-3/4” hole section to 8413’ MD.
7. GeoTap RFT interval identified by Geologist
8. Run and cmt 3-1/2” production liner.
9. Displace well to 6% KCL completion fluid.
10. POOH and LDDP.
11. RIH and land 3-1/2” tieback string in liner top.
12. Test IA to 3000; Test tubing to 3000 psi
13. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
Surface hole: GR + Res MWD
Production Hole: Triple Combo
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling of KALOTSA 9. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office.
x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the
conditions of approval are captured in shift handover notes until they are executed and complied
with.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only
6-3/4”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
(Annular 2500 psi)
Subsequent Tests:
250/3000
(Annular 2500 psi)
x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to testing BOPs.
x Any other notifications required in APD.
Additional requirements may be stipulated on APD and Sundry.
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Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
9.0 R/U and Preparatory Work
9.1 Set 16” conductor at +/-120’ below ground level.
9.2 Dig out and set impermeable cellar.
9.3 Install landing ring on conductor.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Layout Herculite on pad to extend beyond footprint of rig.
9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.8 Mix mud for 9-7/8” hole section.
9.9 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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10.0 N/U 21-1/4” 2M Diverter
10.1 N/U 21-1/4” Hydril MSP 2M diverter System.
x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure.
x NOTE:Ensure closing time on diverter annular is in line with API RP 64:
2..1.1.Annular element ID 20” or smaller: Less than 30 seconds
2..1.2.Annular element ID greater than 20”: Less than 45 seconds
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking.
x A prohibition on ignition sources or running equipment.
x A prohibition on staged equipment or materials.
x Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
10.5 Estimated Diverter line orientation on Kalotsa Pad:
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11.0 Drill 9-7/8” Hole Section
11.1 P/U 9-7/8” directional drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2” Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8” hole section to 1430’ MD/ 1394’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
x Utilize Inlet experience to drill through coal seams efficiently.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability.
x TD the hole section in a good shale
x Take MWD surveys every stand drilled (60’ intervals).
11.5 9-7/8” hole mud program summary:
Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start
with a simple gel + FW spud mud at 8.8 ppg.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-1430’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
System Formulation: Aquagel + FW spud mud
Product Concentration
FRESH WATER
SODA ASH
AQUAGEL
CAUSTIC SODA
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
X-TEND II
0.905 bbl
0.5 ppb
12-15 ppb
0.1 ppb (9 pH)
as needed
as required for weight
if required for <12 FL
0.1 ppb
0.02 ppb
11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe.
11.7 TOH with the drilling assy, handle BHA as appropriate.
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12.0 Run 7-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Parker 7-5/8” casing running equipment.
x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
12.5 Continue running 7-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top out job is needed.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
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12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
13.0 Cement 7-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
13.2 Document efficiency of all possible displacement pumps prior to cement job
13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded
correctly.
13.4 Pump 5 bbls spacer. Test surface cmt lines.
13.5 Pump remaining spacer.
13.6 Drop bottom plug. Mix and pump cmt per below recipe.
13.7 Cement volume based on annular volume + 75% lead and tail open hole excess. Job will
consist of lead & tail, TOC brought to surface.
Estimated Total Cement Volume:
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13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls.
x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 – 18 hours after CIP.
Verified cement calcs. -bjm
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13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
13.14 R/D cement equipment. Flush out wellhead with FW.
13.15 Back out and L/D landing joint. Flush out wellhead with FW.
13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
13.17 Lay down landing joint and pack-off running tool.
Ensure to report the following on WellView:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test
Packoff to 3000 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
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x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Land out test plug (if not installed previously).
x Test BOP to 250/3000 psi for 5/10 min.
x Test VBR’s with 3-1/2” and 4-1/2” test joints
x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint
x Ensure to leave side outlet valves open during BOP testing so pressure does not build up
beneath the test plug.
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 9.0 ppg 6% KCL PHPA mud system.
14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section.
15.0 Drill 6-3/4” Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4” hole section mud program summary:
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Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Ensure fluids are topped off and adequate lost circulation material is on location in anticipation
of losses in hole section.
System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
1430’- 8413’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0
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System Formulation:6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0–10ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
x Triple Combo LWD tools required (DEN, POR, RES)
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi.
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for FIT.
15.13 Conduct FIT to 17.0 ppg EMW. A 17# ppg FIT with 8.5 ppg BHP and 9.2 ppg MW will result
in a 16 bbl KTV.
15.14 Drill 6-3/4” hole section to 8413’ MD / 7865’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x Trip back to the 7-5/8” shoe about ½ way through the hole section
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Lost BHA on Kalotsa 8. Maintain good hole cleaning and add Black product to the
mud.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe.
15.16 TOH with the drilling assy, standing back drill pipe.
A 17# ppg FIT with 8.5 ppg BHP and 9.2 ppg MW will result
in a 16 bbl KTV.
18 ppg FIT is required to drill to TD under normal operating procedures. -bjm
Kick tolerance is 13 bbls based on above assumptions, which is not sufficient to drill to planned TD. Total depth
of the well may need to be curtailed and kick mitigation measures employed if KT is <15 bbls. Notify AOGCC
of LOT results and obtain approval before drilling ahead. -bjm
Page 22 Rev PTD November 13, 2024
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Drilling Procedure
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15.17 LD BHA
15.18 RIH to TD, pump sweep, CBU and condition mud for casing run.
15.19 POOH LDDP and BHA
15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint.
16.0 Run 3-1/2” Production Liner
16.1. R/U Parker 3-1/2” casing running equipment.
x Ensure 3-1/2” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while running.
x Ensure all casing has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with YJOC landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 3-1/2” production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 3-1/2” production liner
Page 23 Rev PTD November 13, 2024
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Page 24 Rev PTD November 13, 2024
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16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe.
16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe.
16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set casing slowly in and out of slips.
16.12. PU 3-1/2” X 7-5/8” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up
weights.
16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom.
Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the
shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and
thinners.
16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
Page 25 Rev PTD November 13, 2024
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Drilling Procedure
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17.0 Cement 3-1/2” Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Page 26 Rev PTD November 13, 2024
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Estimated Total Cement Volume:
17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating
and reciprocating liner throughout displacement. This will ensure a high quality cement job with
100% coverage around the pipe.
17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP
entering into liner.
17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
17.10. Bump the plug and pressure up to up as required by YJOC procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
17.11. Slack off total liner weight plus 30k to confirm hanger is set.
Verified cement calcs. -bjm
Page 27 Rev PTD November 13, 2024
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17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls.
17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner.
17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up
pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops
rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to
overcome hydrostatic differential at liner top).
17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
17.21. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes.
Ensure to report the following on WellView:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
Page 28 Rev PTD November 13, 2024
KALOTSA 9
Drilling Procedure
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x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 3-1/2” Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per YJOC rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC
procedure.
18.3. POOH, and LDDP and polish mill.
18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes
Page 29 Rev PTD November 13, 2024
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19.0 3-1/2” Tieback Run, ND/NU, RDMO
19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked
up per tally.
x No SSSV, CIM, or GLM required.
19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space
out tieback seals in PBR.
19.3 Circulate inhibited completion fluid.
19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance
of seals from no-go.
19.5 Install packoff and test hanger void.
19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes.24 hr notice required.
19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.24 hr notice required.
19.8 Install BPV in wellhead
19.9 N/D BOPE
19.10 N/U dry-hole tree and test
19.11 RDMO Hilcorp Rig #169
Page 30 Rev PTD November 13, 2024
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20.0 Diverter Schematic
Page 31 Rev PTD November 13, 2024
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21.0 BOP Schematic
Page 32 Rev PTD November 13, 2024
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22.0 Wellhead Schematic
Page 33 Rev PTD November 13, 2024
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23.0 Anticipated Drilling Hazards
9-7/8” Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 – 45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
Page 34 Rev PTD November 13, 2024
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Drilling Procedure
PTD xxx-xxx
6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022,
ensure all LCM inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 35 Rev PTD November 13, 2024
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Drilling Procedure
PTD xxx-xxx
24.0 Hilcorp Rig 169 Layout
Page 36 Rev PTD November 13, 2024
KALOTSA 9
Drilling Procedure
PTD xxx-xxx
25.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Page 37 Rev PTD November 13, 2024
KALOTSA 9
Drilling Procedure
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26.0 Rig 169 Choke Manifold Schematic
Page 38 Rev PTD November 13, 2024
KALOTSA 9
Drilling Procedure
PTD xxx-xxx
27.0 Casing Design Information
Page 39 Rev PTD November 13, 2024
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Drilling Procedure
PTD xxx-xxx
28.0 6-3/4” Hole Section MASP
See attached emails for revised table with corrected anticipated pressures. -A.Dewhurst 06DEC24.
Page 40 Rev PTD November 13, 2024
KALOTSA 9
Drilling Procedure
PTD xxx-xxx
29.0 Spider Plot w/ 660’
Page 41 Rev PTD November 13, 2024
KALOTSA 9
Drilling Procedure
PTD xxx-xxx
30.0 Surface Plat As-Built
!!"
# $
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750
Vertical Section at 320.00° (1500 usft/in)
7 5/8" x 9 7/8"
3 1/2" x 6 3/4"
500
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 00 0
550 0
6 00 0
6 50 0
7 0 0 0
7 5 0 0
8 000
84 13
Kalotsa 9 wp02
Start Dir 3º/100' : 500' MD, 500'TVD
End Dir : 1733.33' MD, 1649.38' TVD
Start Dir 3º/100' : 3313.33' MD, 2911.23'TVD
End Dir : 4213.33' MD, 3728.96' TVD
Total Depth : 8413' MD, 7864.83' TVD
BEL 10
BEL 53
BEL 82
BEL 134
T 5
T 16
T 65
T 83
T 142
T 146
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: Kalotsa 9
126.50
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2233390.14 209903.72 60° 6' 14.0503 N 151° 35' 23.2868 W
SURVEY PROGRAM
Date: 2024-11-12T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.00 1430.00 Kalotsa 9 wp02 (Kalotsa 9)3_MWD+IFR1+MS+Sag
1430.00 8413.00 Kalotsa 9 wp02 (Kalotsa 9) 3_MWD+IFR1+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
1461.50 1317.00 1507.60 BEL 10
2118.50 1974.00 2320.73 BEL 53
2708.50 2564.00 3059.49 BEL 82
3502.50 3358.00 3980.29 BEL 134
3932.50 3788.00 4420.01 T 5
5107.50 4963.00 5613.13 T 16
6465.50 6321.00 6992.08 T 65
6741.50 6597.00 7272.34 T 83
7577.50 7433.00 8121.24 T 142
7864.50 7720.00 8412.67 T 146
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Kalotsa 9, True North
Vertical (TVD) Reference:Permit RKB @ 144.50usft (HEC 169)
Measured Depth Reference:Permit RKB @ 144.50usft (HEC 169)
Calculation Method: Minimum Curvature
Project:Ninilchik Unit
Site:Kalotsa
Well:Kalotsa 9
Wellbore:Kalotsa 9
Design:Kalotsa 9 wp02
CASING DETAILS
TVD TVDSS MD Size Name
1394.00 1249.50 1430.36 7-5/8
7 5/8" x 9 7/8"
7864.83 7720.33 8413.00
3-1/2 3 1/2" x 6 3/4"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00
2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD
3 1733.33 37.00 320.00 1649.38 294.60 -247.20 3.00 320.00 384.58 End Dir : 1733.33' MD, 1649.38' TVD
4 3313.33 37.00 320.00 2911.23 1023.01 -858.41 0.00 0.00 1335.45 Start Dir 3º/100' : 3313.33' MD, 2911.23'TVD
5 4213.33 10.00 320.00 3728.96 1295.39 -1086.96 3.00 180.00 1691.01 End Dir : 4213.33' MD, 3728.96' TVD
6 8413.00 10.00 320.00 7864.83 1854.04 -1555.72 0.00 0.00 2420.27 Total Depth : 8413' MD, 7864.83' TVD
0150300450600750900105012001350150016501800South(-)/North(+) (300 usft/in)-2100 -1950 -1800 -1650 -1500 -1350 -1200 -1050 -900 -750 -600 -450 -300 -150 0 150 300 450 600West(-)/East(+) (300 usft/in)7 5/8" x 9 7/8"3 1/2" x 6 3/4"25050075010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506500675070007250750077507865Kalotsa 9 wp02Start Dir 3º/100' : 500' MD, 500'TVDEnd Dir : 1733.33' MD, 1649.38' TVDStart Dir 3º/100' : 3313.33' MD, 2911.23'TVDEnd Dir : 4213.33' MD, 3728.96' TVDTotal Depth : 8413' MD, 7864.83' TVDCASING DETAILSTVDTVDSS MDSize Name1394.00 1249.50 1430.36 7-5/8 7 5/8" x 9 7/8"7864.83 7720.33 8413.00 3-1/2 3 1/2" x 6 3/4"Project: Ninilchik UnitSite: KalotsaWell: Kalotsa 9Wellbore: Kalotsa 9Plan: Kalotsa 9 wp02WELL DETAILS: Kalotsa 9126.50+N/-S +E/-W Northing Easting Latitude Longitude0.00 0.002233390.14 209903.72 60° 6' 14.0503 N 151° 35' 23.2868 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Kalotsa 9, True NorthVertical (TVD) Reference:Permit RKB @ 144.50usft (HEC 169)Measured Depth Reference:Permit RKB @ 144.50usft (HEC 169)Calculation Method:Minimum Curvature
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0.001.503.004.50Separation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000Measured DepthKalotsa 2Paxton #4No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Kalotsa 9 NAD 1927 (NADCON CONUS)Alaska Zone 04126.50+N/-S+E/-W Northing EastingLatitudeLongitude0.000.002233390.14 209903.72 60° 6' 14.0503 N 151° 35' 23.2868 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Kalotsa 9, True NorthVertical (TVD) Reference: Permit RKB @ 144.50usft (HEC 169)Measured Depth Reference:Permit RKB @ 144.50usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-11-12T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 1430.00 Kalotsa 9 wp02 (Kalotsa 9) 3_MWD+IFR1+MS+Sag1430.00 8413.00 Kalotsa 9 wp02 (Kalotsa 9) 3_MWD+IFR1+MS+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000Measured DepthKalotsa 1Kalotsa 2Kalotsa 3Kalotsa 4Kalotsa 5Kalotsa 6Kalotsa 7Kalotsa 8Paxton #4GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 8413.00Project: Ninilchik UnitSite: KalotsaWell: Kalotsa 9Wellbore: Kalotsa 9Plan: Kalotsa 9 wp02Ninilchik UnitLadder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name1394.00 1249.50 1430.36 7-5/8 7 5/8" x 9 7/8"7864.83 7720.33 8413.00 3-1/2 3 1/2" x 6 3/4"
1
McLellan, Bryan J (OGC)
From:McLellan, Bryan J (OGC)
Sent:Friday, December 13, 2024 3:26 PM
To:Sean McLaughlin
Cc:Dewhurst, Andrew D (OGC); Lau, Jack J (OGC)
Subject:RE: [EXTERNAL] Kalotsa 9 PTD questions
Sean,
As discussed on the phone, the TD of the well may need to be cut short and kick mitigation measures may need to
be employed depending on the LOT results. I’ll add some conditions on the PTD.
It’s noted that the nearby Kalotsa 7 (PTD 220-067) had a 21.7 ppg LOT at the same depth horizon as you are
planning the surface casing shoe in Kalotsa 9, which will be suƯicient if duplicated in Kalotsa 9.
By my calculations you’ll need at least 18 ppg FIT/LOT to have 15 bbl kick tolerance with 9.4 ppg mud.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Friday, December 13, 2024 1:15 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] Kalotsa 9 PTD questions
Bryan,
There is potential for gas development ~67’ TVD below the surface casing shoe. That is why the surface casing is
not deeper.
At TD my calculations include 0.7 ppg intensity and MW is 0.9 ppg over Formation pressure.
2
At 6742’ TVD.
3
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, December 13, 2024 11:38 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] Kalotsa 9 PTD questions
Sean,
Even at 17 ppg and swab kick scenario, I’m not getting suƯicient KT.
x Could you send your inputs/outputs and I’ll see if I can Ʊnd the discrepancy?
x Is there a reason you can’t set the surface casing deeper? By setting surface casing shoe even 400’
deeper, you signiƱcantly improve the KT. It’s easy to do that now, but once you get your leakoƯ test results,
it’s too late to change.
I have some additional responses to your comments below in red.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, December 12, 2024 5:38 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] Kalotsa 9 PTD questions
Bryan,
I used a max formation pressure of 9.2 ppg at TD even though the maximum reservoir pressure is 8.5 ppg. The
gradients are what we carry for highest anticipated. We use those for MASP calculations. We use most likely
pressures for drilling. Due to depletion over time the highest anticipated pressure gives way to more recent
data. We drilled Kalotsa 7 and 8 with MW ranging between 9.0 and 9.4 ppg. There were no signiƱcant signs of
connection gas or swabbing to indicate those MWs were close to the actual pressure. A 0.5ppg over for intensity
kicks in development wells is overly burdensome. The standard by which we follow is that a combination of
overbalance plus kick intensity should be 0.5 ppg in development areas. For example, if you are drilling with 9.4
ppg mud in a 9.2 ppg reservoir, the kick intensity should be 0.3 ppg for KT calculations.
If I change the MW to 9.4 ppg (highest potential MW based on recent drilling) and hold the BHP at 9.2 ppg the KTV is
15.4 bbls. BHP can not be less than mud weight for KT calculations. If you swab in a kick, the BHP is equal to mud
weight because it has a column of mud above it. I suggest we get the FIT and go from there. It may be higher than
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attachments unless you recognize the sender and know the content is safe.
4
17 ppg, there was a 21.7 ppg LOT on Kalotsa 7. If it is less, we will have a conversation about swab risk and
mitigation.
We use Class G for all blends. For Kalotsa 9:
12.5 ppg lead - 2.1 cuft/sk
15.3 ppg tail - 1.23 cuft/sk
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, December 12, 2024 4:46 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] Kalotsa 9 PTD questions
Sean,
A couple questions regarding this permit application:
1. Please send your kick tolerance assumptions. Using a 9.2 ppg mud weight for your calculations when your
anticipated reservoir pressure is 9.23 ppg, you’ll need to add in a 0.5 ppg kick intensity to your
calculation. It’s too close to assume a swab kick scenario. I’m not getting a 16 bbl kick tolerance even
with the swab kick at 9.2 ppg. You might need to run the surface casing deeper.
2. Can you send the cement type and yield for the casing cement jobs on this well?
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
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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.
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5
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.
1
Dewhurst, Andrew D (OGC)
From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent:Thursday, 5 December, 2024 16:32
To:Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL] NINU Kalotsa-9 PTD (224-145): Request
Andy,
There appears to have been an overwriting issue. The updated pressures are below. There is no change to the
MASP or required MW. You will Ʊnd the same error in the Kalotsa 10 PTD.
Regards,
Sean
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Thursday, December 5, 2024 11:36 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: [EXTERNAL] NINU Kalotsa-9 PTD (224-145): Request
Sean,
I am compleƟng my review of the NINU Kalotsa-9 PTD and have one request:
x Would you please check the anƟcipated pore pressures provided in SecƟon 28; they do not agree with the
associated gradients.
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2
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas ConservaƟon Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
NINU Kalotsa-9
224-145
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:NINILCHIK UNIT KALOTSA 9Initial Class/TypeDEV / PENDGeoArea820Unit51432On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241450NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes C061505 and ADL3843722 Lease number appropriateYes3 Unique well name and numberYes NINILCHIK, BELUGA-TYONEK GAS - 562503 - governed by CO 701C4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1682 psi, BOP rated to 5000 psi (BOP test to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating max pore pressure of 9.23 ppg EMW.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate12/5/2024ApprBJMDate12/13/2024ApprADDDate12/5/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 12/16/2024
