ADNOC Offshore
Bu-sikeen Island (South SARB)
SR-45 CT Cleanout and Accessibility
Technical Program
Prepared for
Prepared By
:
Li Sima
SARB Well Operations Team, ADNOC Offshore
:
Sadaf Chishti
Account Manager- CT/Stimulation, BAKER HUGHES
June 15, 2022
Rev 0
© 2022 Baker Hughes. All rights reserved
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SR-45 CT Cleanout Proposal
Rev-0
Revision History
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Baker Hughes and ADNOC Offshore, Confidential
SR-45 CT Cleanout Proposal
Rev-0
Table of Contents
1. Objective .................................................................................................................................... 4
2. Well Data .................................................................................................................................... 5
3. Wellbore Volume Calculations ................................................................................................. 8
4. Completion Diagram ................................................................................................................. 9
5. Operation Procedures............................................................................................................. 10
5.1
Safety Procedure .................................................................................. 10
Health, Safety and Environment ................................................................................... 11
Acid Handling.................................................................................................................. 11
5.2
Operation Procedure for Coil Tubing ..................................................... 12
5.2.1
Rig-up & Pressure Test ....................................................................................... 12
5.2.2
RIH with Coiled Tubing to perform Well Cleanout ........................................... 15
5.2.3
Pull Out of Hole (POOH) Procedures:................................................................ 18
6. Recipes & Mixing Procedures ................................................................................................ 19
7. Total Chemical Requirement .................................................................................................. 20
8. Lessons Learnt (Starting with most recent).......................................................................... 21
9. Equipment List ........................................................................................................................ 23
10. Equipment Layout Schematic ................................................................................................ 25
11. CT BHA and PCE Stack up ..................................................................................................... 26
12. Coiled Tubing String Details .................................................................................................. 28
13. Coiled Tubing Engineering Analysis Simulations: ............................................................... 29
14. Coiled Tubing Emergency Procedures: ................................................................................ 30
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Baker Hughes and ADNOC Offshore, Confidential
SR-45 CT Cleanout Proposal
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1. Objective
The objective is to perform below in SR-45 :
 Run 2-in CT with WFD MacDrill Milling BHA and perform a cleanout for the well.
 Confirm accessibility by running 2-in CT to TD
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SR-45 CT Cleanout Proposal
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2. Well Data
Well Status
SR-045 is completed as a single horizontal oil producer in Arab-A2 reservoir through SOP4 completion
in August 2018 and currently not producing. The horizontal reservoir drain length is 4,945 ft. and
equipped with 10 Schlumberger PP2CD on/off type ICDs, 8 Swell Packers and 1,835 ft. of slotted liner
with close end bull nose. (Refer to completion diagram for compartments and ICDs depths).
Well History:
In Oct 2018, CT stimulation was performed and CT was able to RIH to TD.
In May 2019, CT interventions were performed as below:
1. In run#1,



CT unable to pass beyond 17710 ft and slacked several times.
BHA used was 2-1/8" spiral jet nozzle, length=7.6 ft. approx.
Found marks on BHA due to hard debris.
2. In run#2,




Uniarab Milling BHA used, MHA, Motor, Mill, length=14.5 ft.
Max depth run was 17860 ft.
Performed N2 lifting at 13,500 ft. after this by dropping ball to open side ports.
Part of BHA was lost in hole
3. In run#3,


Used 5 port jet nozzle BHA, length=6.3 ft.
Able to RIH to 17,900 ft, beyond max. milling depth interval. No drag observed (component left
downhole might be too small to see drag). Also the obstruction was confirmed to be cleaned
by milling. Solids (hard and soft) were obtained on surface.
In Nov 2020, 3 x CT runs were performed.




In run#1CT Run with WFD milling BHATagged many times. Milling doen from 18888 ft, . Slacked and stalled many times. Pumped ER
and reached max depth of 22145 ft after a total of 21 tags. Milling motor was not functioning
after rig down.
In run#2CT Run with backup WFD milling BHA.
Few tags and CT reached TD=23,400 ft. But was stuck while POOH at 1554 ft. Pumped in
annulus, produced, RIH CT and pumped, it was free after few trials. Drag observed during POOH
to surface.
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SR-45 CT Cleanout Proposal
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Horizontal Interval:
Interval (ft. BRT)
String
Zone
6” Horizontal Open
Hole
6” Reservoir Drain Length
4-1/2” Liner
1
Arab-A2
18,097’-23,470’
18,510’-23,470’
17,811’-23,440’
Well Data:
Slot
R.T.E.
Completion
Deviation @ 3.5” WLEG
Minimum ID
3.5” WLEG
4.5” Top of Liner
4.5” Bull Nose = TD
Correlation Log
B-2/63
61’ AMSL
SOP4
85 @ 17,820’ BRT
2.62”@ 17,777’ BRT (2.75” OTIS RN Nipple)
17,820’ BRT
17,811’ BRT
23,440’ BRT
SBT (11-July-2018)
Reservoir Data:
Reservoir Pressure (Psi)
Reservoir Temperature (F)
API
GOR (SCF/STB)
H2S (mole%)
CO2 (mole%)
Expected WHSIP (Psia)
Expected Flow Rate
5,123 psi @ 15,444’/10053’ MD/TVDSS
248
36
843
25
2.0
+/-2000
3000 BOPD
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SR-45 CT Cleanout Proposal
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3D Plot for Well:
3-D Plot Of Well Pr ofile
2000
0
-4000
TVD (ft)
Easting (ft)
-2000
-10000
-8000
-6000
-4000
-2000
-6000
MD:17200.00(ft)
0
-8000
-10000
2000
-12000
00
20
0
0
00
-20
-400
-6000
-8000
-12
00
0
-1
40
00
-100
00
4000
Nor thin g (ft)
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3. Wellbore Volume Calculations
Wellbore Calculations
Tubing, 4.5"
Tubing, 3.5"
Liner 4.5"
Vol, bbl/ft
0.015218
0.008696
0.014927
From (ft)
To (ft)
Capacity (bbl)
0
346
5.26
346
17820
151.9
17812
23440
85.5
Wellbore Vol (bbl)
242.7
Note: Annulus between 4.5” 12.6# Liner x 6” OH from 18614 ft. to 23440 ft.= 73.8 bbl
Table: B Completion Volume
Wellbore Calculations
2" CT x 3.5" Annulus
2" CT x 4.5" Annulus
Vol, bbl/ft
0.004811
0.011332
From (ft)
To (ft)
Capacity (bbl)
0
17820
85.7
17820
23440
63.7
Wellbore Vol (bbl)
149.4
Table: C CT/Annulus Volume
Volume Factors
Tubing Sizes, inch
Tubing, 5.5
Tubing, 4.5
Tubing, 3.5
Liner, 7
Liner, 4.5
7” X 3.5”
2” CT x 3.5” Annulus
2” CT x 4.5” Liner Annulus
6” OH x 4.5” Liner Annulus
6” OH
Vol, bb/ft
0.023248
0.015218
0.008696
0.037149
0.015218
0.025249
0.004811
0.011332
0.0153
0.034971
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4. Completion Diagram
Rig :
Well No.:
ND-80
ADMA - OPCO
SR-45
SINGLE OIL PRODUCER TYPE:
SR- SOP4
SINGLE 3 1/2" X 4 1/2" COMPLETION
SLOT NO.: XX
DRILLING RIG ORTE = 61 FT AMSL
MAX. OD.
Inch
Length
Ft.
Depth
BRT
FMC TUBING HANGER 5" LC TOP X 4 1/2" VAM TOP BTM W/4" BPV PROFILE.
(SN#: 2017-06-0284)
3.900
13.625
2.00
41.25
4 1/2" VAM TOP #12.6, T-95 PUP JOINT PIN X PIN (10 FT)
3.958
4.500
9.66
50.91
4 1/2" VAM TOP #12.6, T-95 TUBING (9 JOINTS)
3.913
4.937
274.10
325.01
4 1/2" VAM TOP #12.6, L-80 PUP JOINT (7 FT)
3.913
4.937
6.92
331.93
4 1/2" VAM TOP #12.6, L-80 FLOW COUPLING
3.958
4.920
3.74
335.67
BAKER HUGHES TRSV W/ 3.813" 'BA' profile, 4-1/2" VAM TOP, L-80,(SN#: 106157967 )
3.813
7.400
6.47
342.14
4 1/2" VAM TOP #12.6, L-80 FLOW COUPLING
3.958
4.920
3.73
345.87
X/Over 3 1/2" VAMTOP PIN X 4 1/2" VAM TOP BOX
2.992
4.960
1.98
347.85
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (5 FT)
2.959
3.907
4.97
352.82
2.959
3.907
8576.79
8929.61
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (7 FT)
2.959
3.907
6.96
8936.57
OTIS 2.75" R Nipple 3 1/2" VAM TOP, 9.2lb/ft, T-95 ( SN:SG3322631-03 )
2.959
2.750
1.16
8937.73
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (3 FT)
2.959
3.907
4.96
8942.69
2.959
3.907
8695.57
17638.26
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (7 FT)
3 1/2" VAM TOP 9.2#, L-80 - BAKER DOWNHOLE GAUGE CARRIER W/ BY-PASS
GROOVE (SN#: 13886344)
3 1/2" VAM TOP #9.2 , T-95PUP JOINT (7 FT)
2.959
3.907
6.96
17645.22
2.945
4.824
4.96
17650.18
2.959
3.907
6.76
17656.94
3 1/2" VAM TOP #9.2 , T-95 TUBING ( ONE FULL JOINT)
2.959
3.907
29.85
17686.79
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (7 FT)
3 1/2" VAM TOP 9.2#, L-80 - WEATHERFORD CHEMICAL INJECTION SUB W/BoD
VALVE AND CHECK VALVE. (SN#: 11061284-16 )
2.959
3.907
6.97
17693.76
2.900
4.880
4.07
17697.83
3 1/2" VAM TOP #9.2 , L-80 PUP JOINT (5 FT)
2.959
3.907
5.05
17702.88
3 1/2" VAM TOP #9.2 , T-95 TUBING ( ONE FULL JOINT)
2.959
3.907
30.55
17733.43
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (7 FT)
2.959
3.907
4.95
17738.38
WEATHERFORD LOCATOR
2.959
5.000
0.62
17739.00
2.908
4.000
28.80
17767.80
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (3 FT)
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (5 FT)
2.959
3.820
2.97
17770.77
3.959
3.820
4.96
17775.73
OTIS 2.75" 'RN'- Nipple, 3 1/2" VAM TOP 9.2#, L-80 S.C ( SN:3322626-14 )
3.620
3.820
1.30
17777.03
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (3 FT)
2.959
3.920
2.98
17780.01
3 1/2" VAM TOP #9.2 , T-95 TUBING ( ONE FULL JOINT).
2.959
3.920
30.35
17810.36
3 1/2" VAM TOP #9.2 , T-95 PUP JOINT (7 FT).
2.959
3.920
6.97
17817.33
3 1/2" Self-Indexing Half Mule Shoe
2.900
3.820
2.98
17820.31
ORTE TO T.H.S = 39.25 FT
ASSY # 6
MIN.ID.
Inch
Description
ASSY # 5
TOWER : SARB NORTH
10 3/8" X 9 5/8" CSG
ASSY # 4
CROSSOVER @ 541'
3 1/2" VAM TOP #9.2 ,T-95 TUBING ( 282 ) JOINTS
7" TOL @ 14708 FT
3 1/2" VAM TOP #9.2 ,T-95 TUBING ( 286 ) JOINTS
-
Bottom Of Items, BORT
All Tubing is T-95.
All Depth are Logger depth.
Logger depth = Driller depth + 15 FT.
Completion Fluid is filtered Inheb. Brine Wt. = 10.8 ppg
7" WEATHERFORD ULTRA PAK PACKER
ID
Top
MID
2.958
Bottom
X-Mas Tree Type
OD
5.875
Length
3.34
28.84
ASSY # 1C
ASSY# 2
@ 14065 FT
TOP 7" PERM PKR
17741 @FT
ASSY # 1B
ASSY # 1A
W/FORD SEAL ASSY (10 'ATR' SEAL UNITS)3 1/2" VAM TOP, ( SN: 67960188-5 )
ASSY#3
9 5/8" CASING SHOE
4 1/2" TOL @
17811.86 FT
Depth
17741.00
17744.34
17773.18
FMC 4 1/16", 5K SINGLE X-MAS TREE
W/HYDRULIC UMV & WV
7" LINER SHOE @
4 1/2" LINER SHOE @ 23440 FT
18097 FT
6" TD @ 23471 FT
ADMA - OPCO
ADMA - SINGLE OIL PRODUCER MODULE
Running Condition:
Without Blocks
Final Pick - up Wt :- 90 KLBS
Final Slack-Off Wt :- 70 KLBS
WELL NO.:
RIG.:
DATE OF RUN.:
ADMA REP.:
NOTE: DEPTH REFERENCE IS LOGGER DEPTH.
ADMA-OPCO
COMPLETION ENG.:
DRILLING DIVISION
TYPE SR- SOP4
SR-045
ND-80
26/08/2018
Mr. EHAB EL–SAIY / DARIO
MOHAMMAD AL HATHNAWI
DD-
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Baker Hughes and ADNOC Offshore, Confidential
SR-45 CT Cleanout Proposal
Rev-0
5. Operation Procedures
5.1 Safety Procedure
Prior to commencement of operations, a pre-job meeting to be held. This should be attended by, as a
minimum:
I.
The Company Man in charge,
II. The Baker Hughes Service Supervisors,
III. Third Party Representatives of other involved service companies,
IV. Others as necessary.
Safety meetings should be held at the start of every shift and risk assessments should be evaluated
during this time. Tool box talks should be held immediately prior to job execution.
Note: The safety meeting driven by Baker Hughes should address the following topics as a minimum:
I.
II.
Describe the job objective, fluids and volumes to be pumped, pressure expected during the job, and
others.
Review Baker Hughes Operations Policy and Procedure Manuals.
a) Ensure all steps carried out during the operations comply with this Manual.
b) Management of change MUST be applied any time there is a need to deviate from the steps
contained in this procedure.
c) A document MUST be created describing each the step of the deviation. This document shall also
include the deviation Risk Assessment and it MUST be approved and signed by ADNOC Offshore
representative and Baker Hughes-PP Service Supervisors.
III. Personnel responsibilities throughout the job.
IV. Spills, fire, blow out, unexpected well behavior.
V.
Muster point.
VI. Emergency shower station and eye wash station location.
VII. Working in height precaution.
VIII. Trap potential energy.
IX. Take list of personnel on site (Head count).
X.
Review risk assessment (ORA), safe to perform (STP) and job safety analysis (JSA).
XI. Discuss the well H2S, CO2, Hg (Mercury) content.
XII. This well has high H2S, so ensure all best practices are discussed and adopted on the job.
XIII. Emergency responses.
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SR-45 CT Cleanout Proposal
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Health, Safety and Environment
1. Evaluate possible risks than can arise during the job execution. Complete “safe to perform” checklist.
2. Evaluate risk assessment. Report any abnormal or insecure condition on site, taking into account all
the steps or procedures to follow. Discuss with ADNOC representative, the execution or suspension of
the job.
3. Review MSDS of each product that will be used. Verify that all personnel on location handling toxic or
corrosive products have the proper PPE.
4. Review the contingency plan for spills.
5. Other topics to be included as relevant.
Acid Handling
Perform Safety Operations meeting before to discuss and understand risks and assign functions and
responsibilities. Ensure the latest Chemical Transfer Procedures are applied (Refer to OPS-GLB-En-108803).
The work program requires the use of the following hazardous chemicals:
 Acid - Corrosive.
 Chemical additives- Corrosive, Flammable, Toxic (Refer to OPS-GLB-En-108803)
 Diesel - Flammable
The following precautions must therefore be taken to avoid the hazards:
 Barricade the mixing area.
 Use breathing/ protective equipment when working with the chemicals in order to avoid inhalation
of vapors.
 Ensure there is sufficient fresh water on site at all times to flush any accidental acid contact to the
body.
 SDS cards/ sheets of the chemicals to be used must be present onsite and displayed accordingly.
 Acid handling PPEs such as Acid suits, rubber hand gloves, full face shields, Chemical respirators,
etc to be provided by BHGE for use during acid handling operations.
 Written communication should be on the site regarding Acid handling and Tool Box meeting is to
be conducted by BHGE to inform personnel on the use of the correct PPE during handling of acid
if required.
 Neutralizing chemical (soda ash) should be available on site for acid transferring onshore, during
transportation and offshore offloading.
 The Acid handling operations and all other operations MUST be carried out in a SAFE and
PROFESSIONAL Manner.
 Fire extinguishers are to be in place prior the handling of inflammable / explosive material.
 Shower and eye wash stations are to be in place prior to handling of corrosive fluid.
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5.2 Operation Procedure for Coil Tubing
Note: This is general operational procedure. Procedure might change on the spot depending on the job
requirement.
Upon arrival on location, verify well head conditions, and treatment line rig-up. Report tubing head
pressure (THP), casing head pressure (CHP), production, and gas lift condition and supply pressure (if any).
Wellhead series and maximum working pressure should also be recorded and noted.
The treatment line layout should have enough control valves, bridges, check valves (dart type for nitrogen
and flapper type for fluid), pup joints, swivels, bleed off lines, surface filter, and should be secured by a
safety slings.
Refer section 11 for the Well Stack and section 10 for Treatment Line Schematic.
All depths must be specified based on completion diagram. The depth counters must be adjusted
according to the RTKB depth and casing head depth. Use the latest updated completion diagram
available.
5.2.1
1
2
3
4
5
6

7
8
9
10
11
12
Rig-up & Pressure Test
Conduct safety meeting and complete HSE and PTW requirements. Complete safety meeting
attendance sheet (use Form 1351).
Review the list of equipment received and check the equipment for any damage that may have
been incurred while in transit.
Spot CT and Pumping Equipment on Location according to the CT layout and refer to the lifting
plan. Make sure that it is accurately positioning wellhead.
Verify and annotate wellhead pressure at surface.
Check wellhead and connections on top to connect the CT stack and verify seal condition. Make sure
the wellhead is lined up and connected to the well testing setup. Observe and record the wellhead
pressure.
Rig up the coiled tubing / pumping equipment as per “Job Site Preparation and Rig-Up for Land
Based Coiled Tubing Operations” (S&P Section 2.5.1.2) & BAKER HUGHES international standards
and procedures (‘‘Coiled Tubing Operations Manual’ – Document No: OPS-GLB-En-101479”)
Confirm Tree Pressure & 3rd party pressure ratings
Connect all hydraulic hoses and function test reel, cabin, injector head, etc.
Connect all data acquisition cables and ensure that the parameters are correctly setup. Check and
verify all Jobmaster parameter settings. Upload CIRCA RT files and setup IICS correctly.
Stab CT through injector head.
Ensure calibration of the volume counter on JobMaster & pumping equipment based on pumping 10
bbls on the displacement tank.
Make up coil internal connector and pull test to 20,000 lbs.
Fill coiled tubing reel noting volumes on barrel counter / displacement tanks. Compare and record
with theoretical coiled tubing reel volume (+/- 73 bbl)
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13
14
Drift the CT string with the largest size of ball that will be used in the job.
Pressure test connector and coiled tubing to 200 PSI (low) & 6,500 PSI (high) gradually increasing the
pressure in increments and holding the final pressure for 10 minutes respectively.
Note: During rig-up and rig down operations, a no-go device must be present on the
end of the coiled tubing at all times to avoid inadvertently pulling out of the injector.
15
16
17
18
19
20
21
22
23
24
25
26
27
Make up BHA for the planned Well Intervention run as per section 11 with measured OD’s, IDs,
section lengths, ball sizes, rupture discs, mill type and characteristics, etc. Caliper the BHA and record
on treatment report. If using any ball activated tool, ensure ball diameter will pass through the BHA
including roll on in the presence of company representative on location.
Install wellhead X-over.
Remove BOP from unit and place on the ground.
Install BOP control lines.
Function test all BOP rams.
Install BOP on wellhead.
Lift down Injector from injector stand.
Function test injector in/out.
If required, hook up Risers long enough to hold all BHA inside.
Install injector and riser (if used) onto the BOP stack as per Section 11.
Tie down the injector to the cement blocks to minimize the bending movement on the wellhead /
connections.
All surface treating lines, CT and reel rotating joint should be pressure tested to 6500 psi (High). PCE
stack will be tested to a pressure equal the maximum anticipated treating pressure or potential kill
pressure plus 10 percent (which is limited to usually 4,500-4,800 psi-High for 5k psi X-mas tree and
to be decided by ADNOC Program or Company man). Low pressure tests are to be carried out at
200-300 psi for a duration of 5 minutes followed by the high-pressure test for 15 minutes.
The check valve shall be inflow tested to 4000 psi differential for 15 min before each CT run. The
Check Valves can be pressure tested with hand pump with Company Man as witness. Pressure test
using Water/Brine all lines and equipment as per Baker Hughes Services standard procedures. The
test pressure of the stripper/BOP should not exceed the pressure of the wellhead.
Note: The maximum CT pumping pressure during the job while dynamic will be restricted to a
maximum of 5000 psi. While static, the CT pumping pressure can be exceeded to a maximum value
up to 10% lower than pressure test value.
Note: During the pressure test, increase to Max Traction, Max Tension, and Stripper
pressure adjusted accordingly while ensuring that excessive stripper pressure is not
applied during this test which can cause pipe collapse scenarios.
A successful pressure test requires that 95% of the maximum test pressure is
maintained for 15 minutes.
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28 After pressure test is complete and bled off, zero counters and weight readings.
29 On completion of all tests re-pressure up via coiled tubing to equalize to swab valve and open up tree
valves and prepare to RIH.
30 Before beginning RIH, ensure adequate amount of water and diesel is available to meet job objectives.
31 Prior to CT RIH, fill the Coil with water and evaluate how many slugs of H2S inhibitor will be required to
be pumped internally for CT protection from H2S. If run objective do not allow continuous pumping,
then fill the CT accordingly with slugs of H2S slug mixture such that every 2 hours H2S inhibitor slug will
be pushed out of nozzle with minimal volume pumped from surface.
32 Prior to CT RIH, protection sleeve shall be installed by slickline.
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5.2.2
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
RIH with Coiled Tubing to perform Well Cleanout
Rig up CT as per section 5.2.1.
Makeup the WFD MacDrill Motor and Bear Claw Mill BHA as per diagram in section 11 and function
test the BHA as per WFD Engineer instructions.
After recording a successful pressure test, ask the customer for any last minute instructions and
obtain approval prior to opening master valve.
Request any pertinent information from the client (i.e. BHP, production, restriction depth, WHP,
etc.).
CIRCA RT files, CIRCA flow, force, and stress analysis predictions are required prior to the start of the
job. Do not exceed these limits without consulting BAKER HUGHES Coiled Tubing Services
engineering. Refer to simulations in section 13 attachment.
Verify and annotate static BHP and wellhead pressure at surface. Note the flowing WHP and
production rate prior to beginning RIH.
Measure and fix the Job Master Depth reading and the counter head to the RTKB depth.
If the Coiled Tubing was not drifted earlier on the same well, Drift CT Reel with Trip Ball. To be
completed with Max Trip Ball sizes for B-H-A. This completes two purposes, one the Coil-Tubing will
be drifted for Trip Ball access to the BHA and Chemical Cutter access.
Ensure the well conditions are within the Coiled Tubing pipe operating limits:
 Ensure H2S inhibitor is applied externally and internally as per the job requirements and is
active all the time as long as the CT is exposed to H2S in the well.
Use the high pressure pump to pressurize the coiled tubing equal to or above the wellhead pressure
and open up tree valves.
Start RIH at slow speed while the CT is filled with Water.
Start external H2S inhibitor injection at the stripper while RIH. HS-22 (H2S Inhibitor) solution
composed of 50 parts inhibitor and 50 parts of diesel. Injection to be maintained throughout RIH &
POOH.
Internal H2S inhibitor slugs will be pumped every 2 hours as long as the CT is in hole and there is
H2S presence. Each slug to be composed of 1.5 bbl of 30:70 =HS-22: Diesel mixture.
Increase speed after running past 500 ft. The maximum run in speed shall not exceed 100 ft/min.
RIH speed shall be reduced to 10 ft/min through restrictions or changes in casing/tubing ID’s.
Perform pull tests and break circulations at minimum rate with diesel every 1000 ft. and at any
significant completion or well condition change. Compare RIH/POOH weights with CIRCA
predictions.
Note: 2” CT metal displacement will be 3.89bbls every 1000ft.
17. Mix 1000 bbls friction reduced water initially with 1 gpt FRW-14 and water. (More can be mixed as
job progresses as per requirement).
18. Continue RIH while performing frequent pull tests and break circulations with water. If any
abnormal weight trend is observed, evaluate if due to debris and increase pump rate. Consult with
town and DSL.
15
Baker Hughes and ADNOC Offshore, Confidential
SR-45 CT Cleanout Proposal
Rev-0
Note: In previous operations, CT slacked weight at around 17,710 ft due to hard obstruction that
was milled. Recently a logging run confirmed ID reduction to 2-in in interval 17000-17700 ft. .
Hence, keep track of weight behavior and match it with CIRCA predictions throughout the job.
19. When CT is at depth 16,500 ft, station CT and start pumping FR water at 1.2 bpm and Nitrogen at
300 scfm.
20. Gradually increase N2 rate to 500 scfm and stay within max. allowable CT pressure. Establish
circulation and note the parameters including return rates and pressures. Stop pumping.
21. Continue to RIH to obstruction depth (around 17000 ft as per previous logging run).
22. Tag top of obstruction and confirm again by picking up and tagging again to ensure its hard tag.
23. Pickup and station CT 10 ft. above the tag depth.
24. Mix 25 bbl of 7.5% HCL acid as per recipe.
25. Displace the acid to CT nozzle with Water at max. allowable rate and pressure and close the choke/
and CT-Tubing annulus.
26. With acid at the nozzle, pump 25 bbl of Water via CT at max allowable pressure to push the acid
out of nozzle.
27. Pick up CT 100 ft and allow acid to soak for 30 mins.
28. Open surface choke
29. Start RIH again while pumping 1.2 bpm / 300 scfm of Water/N2 and continue to RIH.
30. Slow down at tag depth and continue penetration at 10-15 ft/min while pumping Water / N2.
31. Observe weight trends and if any slack observed, slow down CT and follow instructions from WFD
engineer to continue to mill out the obstruction.
32. Gradually apply WOB as the CT circulating pressure increased indicating that milling is progressing.
Note: Ensure maximum CT operating pressure is not exceeded. Follow WFD Engineer
recommendation.
33. If there is no WOB observed, continue to increase the penetration rate as per WFD engineer
recommendation.
34. If motor stall occurs, follow WFD instructions. Stop pumping and the pressure allowed bleeding off,
ensuring that the motor has stopped, before pulling of bottom by 25 ft. Once clear of tag depth, reestablish pump rate and pressures before returning to working depth. Follow ADNOC/WFD
instructions.
35. During milling operations, keep close watch on below:
35.1.
CT set down weight and do no exceed CIRCA Operating Limit and WFD tool limit.
35.2.
CT pressure: Do no exceed CT operating limit.
36. Monitor returns and watch for lost returns.
37. Perform a 50 ft. pull test after every 500 ft. of milling penetration and monitor return rates.
38. After milling an interval of 2500 ft, pump a 5 bbl gel pill perform a Wiper trip until depth of 10500
ft. at speed 35 ft/min and while pumping continuously water/N2.
Note: Arrange gel additive from the AD-80/AD-79 ahead of the run.
16
Baker Hughes and ADNOC Offshore, Confidential
SR-45 CT Cleanout Proposal
Rev-0
39. At 10,500 ft, continue to pump at least 2 x bottoms up and then RIH back to continue milling
operations while maintaining returns.
Note: Keep observing rock catcher filters, if both of the filters is plugged, then CT should be POOH to
surface while continuing to circulate out to flowline. Do not stop pumping as there is risk of getting
stuck.
40. Continue to mill this time covering 2500 ft. further. Pump 5 bbl gel pill and perform a wiper trip to
10,500 ft.
41. Perform 2 x bottoms up and proceed to penetrate next 2500 ft.
42. Repeat above steps until the milling operation clears the well to ensure that the well is accessible
to TD.
RIH Slack Weight Contingency:
i.
Observe the weight trend to recognize if the slack weight is due to hard obstruction or friction
lock and report to town.
ii.
Mix around 150 bbls of 2% EasyReach Solutions.
iii.
Pick up CT to 18000 ft and pump 73 bbls Easyreach lubricant to displace the CT volume. Pump
only via CT at 1 bpm and continue to RIH at 40-45 ft/min provided we have milled majority of
the section. Ensure returns are obtained.
43. With CT at TD and accessibility confirmed, drop a ball to activate circulation ports to allow high
pump rates. Consult WFD Engineer.
44. Perform a wiper trip while pumping Water /N2 at 1.5bpm and 500 scfm at max allowable CT
pressures. Follow wiper trip speed chart for recommended POOH speeds.
45. POOH CT to surface following standard POOH procedures while not exceeding speed mentioned in
the recommended Wiper Trip plot and slowing down at restrictions.
46. Continue to pump until surface so that the solids do not fall down back into the well.
47. Flow back the well and clean the well until BS&W drops to 5%.
48. Follow ADNOC Offshore program.
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Baker Hughes and ADNOC Offshore, Confidential
SR-45 CT Cleanout Proposal
Rev-0
5.2.3
Pull Out of Hole (POOH) Procedures:
Note: Below are standard POOH procedures. For cleanout procedure, follow wiper trip
recommendations mentioned in the program above.
1. Specific procedures are discussed in the “Pulling Out of Hole Procedure Standard” Section 2.5.2.8
2. POOH Practices
a) The maximum speed of the coiled tubing while pulling out of the hole shall not exceed 80 feet per
minute under any circumstances.
3. Reduce speed when:
a) Through restrictions, nipples, any ID changes.
b) At depths of 250 to 100 feet from the surface, reduce the speed to a maximum of 50 feet per
minute.
c) Within 100 feet from the surface and while pulling through the wellhead assembly, reduce the
speed to 10 feet per minute.
4. Tag the stuffing box assembly with a No-Go or alternative depth correlation method to determine the
BHA is between the stuffing box and master valve.
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SR-45 CT Cleanout Proposal
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6. Recipes & Mixing Procedures
Table-C (i) Easyreach Lubricant 2%-100 bbl:
Total Volume
4200
Gals
ITEM
CODE
DESCRIPTION
Concentration
UNIT
1
Fresh Water
Easyreach ™
Lubricant
Base fluid
Metal friction
reducer
980
gal/1000
Total
Volume
4116
20
gal/1000
84
2
bbl
100
UNIT
BBLS
GAL
98
GAL
2
Table-C (ii) Friction Reduced Water 100 bbl:
Friction Reduced Water
Additives
100.00
Chemical Code
Friction reducer
Fresh Water
FRW-14
Water
Conc.
bbl
Qty (gal)
1.00
Gal
Gal
4
4,196
999.00
Table-C (iii) 7.5% HCL Acid Recipe:
7.5% HCl Acid
Additives
Raw Hydrochloric Acid
Corrosion Inhibitor
Non-Emulsifier
Anti Sludge
Iron Control
Hydrogen Sulfide Inhibitor
Complex Nano Surfactant
Friction reducer
Fresh Water
12 HR
Baker Hughes Code
32% HCL
CI-42
NE-118
AS - 6
Ferrotrol - 800 L
HS-2
CNF
FRW-14
Water
Gal
Gal
Gal
Gal
Gal
Gal
Gal
Gal
Gal
1,050.00 gal
25.00 bbl
Conc.
Qty
210.00
20.00
3.00
3.00
5.00
3.00
0.00
1.50
754.50
SR-45
Gel Pills
Additives
220.5
21.0
3.2
3.2
5.3
3.2
1.6
792.2
2100 gal
50
bbl
Baker Hughes Code
Conc.
Qty
Gelling Agent (CMHPG)
GW-38
lbs
50
105
Water
Water
Gal
1000
2100
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SR-45 CT Cleanout Proposal
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7. Total Chemical Requirement
Accessibility and/or Milling Run
S.No Item
Raw HCL
1
CI-42
2
NE-118
3
AS-6
4
FE-800L
5
HS-2
6
Water (including for contingencies)
7
FRW-14 (for milling friction reduced water8
if required)
EasyReach Lubricant (for contingency)
9
HS-22 (for CT Coating against H2S)
10
Nitrogen
11
GW-38
12
Quantity
221
21
4
4
6
4
500
55
UOM
Gals
gal
Gal
Gal
Gal
Gal
bbl
gal
90
440-550
10000
110
gal
gal
gal
lbs
Note:
 Ensure additional quantities of water are accessible during the job.
20
SR-45 CT Cleanout Proposal
Rev-0
8. Lessons Learnt (Starting with most recent)
SR-62
During a memory TGT logging job, CT was being POOH after repeated cycles of short passes that required CT to be
stationay for few minutes and move up small intervals periodically. During POOH, there was drop of hydraulic
pressure supply to the injector motor. Upon trouble shooting, a leak was found in the directional valve of the
powerpack. O-rings were replaced and backup spares were also ordered from town. Following this, a mechanic visited
the site and checked all equipment hydraulics. Ensure backup spares are available for all such contingencies.
SR-53
CT was RIH and could not pass SSV depth. It was found that the SSV is not tubing retrievable but wireline retrievable.
Slickline was brought to retrieve it.
SR-45
Found ball valve corroded on one of the vertical tank that is storing the chemical. Immediately plug-off the ball valve
to stop the leak on the drain line of the tank.
To perform a regular HSE walkabout to check the condition of the ball valve to avoid similar situation from happening.
Also, chemical will only be stored in the vertical tank prior to job start. This is to avoid prolong exposure of chemical
in the tank; it is as part of prevention or avoidance from the occurrence of similar situation.
SR-46
There was a leak from a seal on the pump during the job and it was isolated and contained. The pump operator was
able to swap pumps and maintain rate and pressure as per company man instruction. The seal was replaced. To
remedy this, all low quality seals will be replaced with high quality seals.
SR-43
During acid pumping, observed leaking in the centrifugal pump manifold. The leakage was contained in the drip tray
and neutralized with soda ash. Action item for BAKER HUGHES is to send new Centrifugal-pump and spare parts so
this incident is avoided.
SR-20
On the afternoon of 5th August, upon completing transferring the last batch of acid from Pacific-68 vessel, a pinhole
leak was observed on the discharge line at the elbow just below the belly line. The drip tray was in place under the
manifold and prevented any acid from coming into contact with the ground. The DSL and BAKER HUGHES Supervisor
were immediately notified and the leak was contained utilizing a rubber patch. After confirming that the line was
secured, the transporter moved to location where it was decanted into the Frac Tank. The transporter has since been
removed from service until the entire suction manifold can be replaced.
BAKER HUGHES’s plan to address the issues with the leaking tankers is to source another supplier or supply BAKER
HUGHES owned transports, both options are being investigated. Tried changing acid coating, vendors and even
switched to Teflon lines hoses but not with much success. Plan is to increase inventory on island to address this
issue.
SR-23
Before acid mixing BAKER HUGHES Supervisor communicated with ADNOC official about the fresh water requirement
and started mixing acid. After mixing 900 bbl of acid, there was no water left due to Rig taking the water. After waiting
on few hours fresh water was taken from the supply boat.
This miscommunication should be avoided in future jobs as it will delay the job. Recommend to have two 500 bbl
water tank for storing fresh water in the job site.
SR-25
21
SR-45 CT Cleanout Proposal
Rev-0
During acid pumping, observed leaking in Centrifugal pump manifold. The leakage was contained in the trip tray and
neutralized with Soda Ash. Action item for BAKER HUGHES is to send new Centrifugal-pump and spare parts so this
incident is avoided.
SR-44, while pumping acid observed leak in third party well testing Gauge connection close to well head. Baker and
SLB should coordinate and make sure the connections are standard connection. Announcement should be made
before pumping and neutralizer should be available in the well head area.
While transferring Acid from Vessel to Acid Hauler, the transfer time is long. Baker Hughes to send 3” centrifugal
pump to North Island for acid transferring which will reduce transfer time.
SR-44
Inadequate barricading while mixing SR-44 acid job. In Tool Box talk, all the safety procedure must be discussed and
announcement should be made for every job operation.
SR-41
During SR-41job, there was not enough fresh water to mix the Acid. Baker crew and ADNOC Supervisor must check
that there is enough water at site as per program before mixing acid.
Lowlights: Not enough water to make enough 15% HCl acid as per original job design. Adjusted by mixing 28% HCl to
fulfil remaining requirement.
All parties involved must confirm enough water and diesel are on location prior to starting the job.
BAKER HUGHES is working with supplier to send chemicals in toe tanks not in drums on pallets.
N2 and Stimulation must work together and assist if competent personnel available. All parties must work together
and maintain constant communication to prevent issues in the future.
Post job feedback shared with N2 team to address customer feedback issues.
Disposal tanks must be placed next to the pumping unit to circulate and flush all system to neutralize the fluid.
Disposal tanks should be emptied prior to every job. Soda ash mixture should be prepared prior to pumping in case
leaks or other need during job.
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SR-45 CT Cleanout Proposal
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9. Equipment List
Dimensions (MTR)
Item
Quantity
No.
Equipment / Product Description
Length - L
Width W
Height - H
m
m
m
1
1
Safety Shower (Portable)
2.44
1.22
2.75
2
1
Acid C-Pump
2.55
1.47
1.80
3
1
Acid Drip Tray
14.20
52.00
0.78
4
1
Acid Drip Tray
14.20
52.00
0.78
5
1
Acid Frac Tank, 500 bbls
10.33
3.95
3.90
6
1
Acid Frac Tank, 500 bbls
10.33
3.95
3.90
7
1
Air compressor
2.65
1.75
1.99
8
1
Diesel Power Generator
2.00
1.10
1.90
15
1
Safety Caravan (Workspace Module)
4.88
2.44
2.90
16
1
Pacemaker Twin Pump
6.50
2.50
0.32
17
1
Diesel Tank (Pacemaker Pump Unit)
2.48
1.05
1.36
18
1
Single Skid Pump Unit (Pyroban) - Engine Skid
2.45
2.19
3.02
19
1
Single Skid Pump Unit (Pyroban) - Transmission Skid
2.45
2.19
3.02
20
1
Single Skid Pump Unit (Pyroban) - Pump Skid
2.45
2.19
3.02
21
1
Acid Centrifugal Pump Skid
2.95
1.52
1.92
22
1
20 ft Open Top Container
6.06
2.44
2.78
23
1
20ft Half High Container
6.06
2.44
1.39
24
1
20ft Open Top Container
6.06
2.44
2.78
25
1
20ft Open Top Container
6.06
2.44
2.78
26
1
20ft Half High Container
6.06
2.44
1.39
27
1
N2 Unit Pump
3.96
2.43
2.75
28
3
Nitrogen Tanks
3.65
2.45
2.60
34
1
Batch Mixer
10.25
2.68
4.27
35
1
Basket with Geomembrane Roll
7.01
2.44
1.46
36
1
Water Frac Tank, 500 bbls
12.00
3.10
3.40
37
1
Diesel Frac Tank, 500 bbls
12.00
3.10
3.40
23
SR-45 CT Cleanout Proposal
Rev-0
38
1
Acid Tanker, 5000 gal w/ Prime Mover and Driver
16.65
3.12
3.50
39
1
Prime Mover with Driver
6.00
2.80
4.00
40
1
20 ft Half Height offshore container
6.06
2.44
1.58
Item
No.
Equipment / Product Description
Dimensions ( LxWxH ) Mts
Actual
Weight
1
Coil Cabin
5.0 x 2.5 x 2.5
7.50
2
Power Pack
2.8 x 2.5 x 2.4
4.50
3
4.0 x 2.5 x 4.3
13.50
4
Injector Basket Containing the below:
Injector"
Quad BOP “+”shear seal BOP"
power hoses
Stuffing box
CT Reel
5.4 x 3.9 x 4.6
60.00
5
Lowbed+Prime Mover
22.5 x 3.65 x 6.2
35.38
6
Tool Container
3.1 x 2.5 x 2.8
6.00
7
Generator Skid
3.0 x 2.0 x 2.5
1.10
8
Generator Skid
9
Jacking Frame
6.10 x 2.41 x 3.67
3.00
10
Bleed off tank
1.8 x 1.65 x 1.3
1.00
11
Diesel Tank
2.7 x 1.2 x 1
0.50
12
Half Height Basket (Contains HS-22 drums &
accessories)
Open top container (Contains gooseneck, securing
blocks)
Open Top Half Height Basket
4.5 x 2.4 x 1.4
10.00
3.9 x 1.6 x 1.7
14.50
3.9 x 1.6 x 1.7
9.5
13
14
24
SR-45 CT Cleanout Proposal
Rev-0
10. Equipment Layout Schematic
25
SR-45 CT Cleanout Proposal
Rev-0
11. CT BHA and PCE Stack up
Run#1: CT Milling BHA with WFD MacDrill Motor
26
SR-45 CT Cleanout Proposal
Rev-0
Well Stack Schematic
Single Oil Producer
Item
Client:
Field:
Well Name & Number:
Min. Restriction:
KOP:
Category:
ADNOC Offshore
Bu-Sikeen
SR-45
N/A
N/A
2
BHP:
BHST:
S/O:
Supplier:
Date Drawn:
Drawn By:
~5100 psi
265°F
N/A
BHGE
N/A
Baker Hughes
Height Pressure
(ft)
(psi)
Item
Description
1
HR680 Injector+Gooseneck
17.08
-
2
4-1/16" 15K Over/Under Stripper
or Stufing Box with 4-1/16" 15k
Flange Bottom
4.41
15000
3
Riser 4-1/16" 15k (if required)
10.00
15000
4
X-over: Spool Adaptor 4-1/16" 15k
Flange to 5-1/8" 15k Flange
1.50
15000
2
5
5-1/8" 15k Quad BOP: 5-1/8" 15k
Flange Top & 5-1/8'' 15k- Bx 169
Flange Bottom
3.85
15000
3
10.00
6
5-1/8" 15 K Dual Combi-BOP
3.80
15000
4
1.50
7
X-over: Spool Adaptor 5-1/8" 15k
Flange to 4-1/16" 5k Flange
1.50
10000
8
X-mas tree
(Top connection 4-1/16" 5k
Flange)
17.08
1
5
4.41
Kill line
3.85
6
3.80
7
1.50
8
To Well Test
Total Height:
22-Jun-22
42.14
Max PSI:
Production
line
10000
27
SR-45 CT Cleanout Proposal
Rev-0
12. Coiled Tubing String Details
28
SR-45 CT Cleanout Proposal
Rev-0
13. Coiled Tubing Engineering Analysis Simulations:
Refer to attachment “SR-45 CT TFA and Flow Simulation Report (2022) Rev.0”
29
SR-45 CT Cleanout Proposal
Rev-0
14. Coiled Tubing Emergency Procedures:
Refer to Attachment CT Emergency Procedures (OPS-GLB-En-101479 Rev:M)
30