Petroleum Development Oman L.L.C.
Well Engineering
Coiled Tubing Operations Procedure
Document ID
PR-1036
Document Type
Procedure
Security
Restricted (Information Security Classification Definitions)
Discipline
Well Engineering
Owner
Issue Date
Version
Link
Wells Corporate Functional Discipline Head
June 2016
Version No.3.0
http://sww3.pdo.shell.om/Getdoc?Dataid=94949 (Intranet)
Keywords: Coiled Tubing, Nitrogen Lifting, Cement Plug Back
This document is the property of Petroleum Development Oman, LLC. Neither the whole nor
any part of this document may be disclosed to others or reproduced, stored in a retrieval
system, or transmitted in any form by any means (electronic, mechanical, reprographic
recording or otherwise) without prior written consent of the owner.
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i
Petroleum Development Oman LLC
Document Authorisation
Authorised for Issue: June 2016
Document Authorisation
Document Authority
Document Custodian
Document Controller
Tariq Al-Riyami (UWH)
Mohammed Al-Jabri (UWI/7)
Christian Koepchen (UWH/2)
Date:
Date:
Date:
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ii Revision History
The following is a brief summary of the 4 most recent revisions to this document. Details of all
revisions prior to these are held on file by the issuing department.
Note that changes made as part of Document Maintenance (correction of broken hyperlinks) will
not be recorded in this Revision Table.
Note that with the publication of Rev. 2.0 of this document PR-1456, (HP-CT-001), Coiled
Tubing Rig-Up and Operations Procedure is withdrawn.
Revision No.
3.0
2.0
Date
June 2016
June 2007
Author/ Editor
Ahmed Benchekor,
UWI/4
Mohamed Jabri,
UWI/7
Kusela Ardia,
UWI/46
Jamil Alawi, UWI1F
Ahmed Benchekor,
UWXZ/31,
Christian Koepchen,
UWH/2
Changes/ Remarks
 Updated Chapter ‎2 “Procedure”,
adding Chapter ‎2.2.2 “Coiled
Tubing Unit description” and
Chapter ‎2.2.9 “Pressure and
Function Testing”

Updated Coiled Tubing
Emergency Procedure
Guidelines

Updated Coiled Tubing Pressure
Control Equipment

In Chapter ‎4, “Appendices”,
removed “Coiled Tubing Rig-Up”
as it will be included in SP-1213,
Well Control.

Integrated content of PR-1456
(HP-CT-001), Coiled Tubing RigUp and operations Procedure
with the content of PR-1036

Updated references and applied
Standard Format

1.0
01/01/2002
Added stuck pipe procedures,
Parted pipe, collapse pipe and
uncontrolled descent/ascent of
coil.
Initial Issue, post merger of Well
Services & Well Engineering.1
TWM/92
UOW 1
0
14/10/1998
TM
Services
OTW/1
–
Initial Issue
PR-1456 (HP-CT-001), Coiled Tubing Rig Up & Operations (withdrawn as, with the
publication of Rev. 2.0 of this document, PR-1456 content is combined with PR-1036,
Coiled Tubing Operations Procedure
1
16/08/2004
0
18/02/2000
Updated by : I.K.
Naamani,
TWX/91
OTW/1 - TWX/4
Checked
TWX6
by:
Suhail
Al-Riyami,
Initial Issue
iii Related Business Processes
Code
EP.63
Page 4
Business Process (EPBM V.4.0)
Design, Drill, Modify, Service and Abandon Well
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iv Related Corporate Management Frame Work (CMF)
Documents
The related CMF Documents can be retrieved from the Wells Standards Portal or through the
CMF Business Control Portal. Other, non-CMF documents and links to information relevant to
Well Engineering can be found on the Wells Standards Portal or on the Well Engineering
Documentation Page.
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TABLE OF CONTENTS
i
Document Authorisation ......................................................................................................... 3
ii
Revision History ..................................................................................................................... 4
iii
Related Business Processes ................................................................................................. 4
iv
Related Corporate Management Frame Work (CMF) Documents ........................................ 5
1
Introduction ............................................................................................................................ 8
2
1.1
Background ...................................................................................................................... 8
1.2
Purpose ............................................................................................................................ 8
1.3
Distribution/Target Audience ............................................................................................ 8
1.4
Review and Improvement ................................................................................................ 8
1.5
Step-out and Approval ..................................................................................................... 8
Procedure............................................................................................................................... 9
2.1
Scope ............................................................................................................................... 9
2.2
Procedure Description ...................................................................................................... 9
2.2.1
General ........................................................................................................... 9
2.2.2
Coiled Tubing Unit description ....................................................................... 9
2.2.3
Coiled Tubing Pressure Control Equipment ................................................. 10
2.2.4
Coiled Tubing Quality Control ...................................................................... 12
2.2.5
Physical Testing of Coiled Tubing Quality .................................................... 13
2.2.6
Pressure Testing of Coiled Tubing Pipe before starting the job ................... 14
2.2.7
Tubing Retirement ........................................................................................ 14
2.2.8
Rigging Up .................................................................................................... 14
2.2.9
Pressure and Function Testing .................................................................... 15
2.2.10
Safety Requirements .................................................................................... 16
2.2.11
Coiled Tubing Operating Guidelines ............................................................ 16
2.2.12
ESD System ................................................................................................. 17
2.2.13
Coiled Tubing Emergency Procedure .......................................................... 19
2.2.14
Acidizing with Coiled Tubing ........................................................................ 31
2.2.15
Nitrogen Lifting with Coiled Tubing ............................................................... 36
2.2.16
Cement Plug Back ........................................................................................ 38
2.2.17
Coiled Tubing Stress Analysis ...................................................................... 41
2.2.18
Contingency Plan ......................................................................................... 41
2.2.19
Policies and Procedures ............................................................................... 41
2.2.20
HSE .............................................................................................................. 41
2.2.21
Job Preparation ............................................................................................ 42
2.2.22
Job Execution ............................................................................................... 42
2.2.23
Pre-Job Meeting ........................................................................................... 42
2.2.24
Procedures ................................................................................................... 42
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2.2.25
Well and Plug Data ....................................................................................... 42
2.2.26
Equipment check up, rig up and pressure test ............................................. 43
2.2.27
Prior to running in check list ......................................................................... 43
2.2.28
Job Outline ................................................................................................... 43
3
Roles and Responsibilities as referred to in this document ................................................. 46
4
Appendices .......................................................................................................................... 48
4.1
Appendix 1, Forms and Reports .................................................................................... 48
4.2
Appendix 2, Glossary of Terms, Abbreviations and Definitions ..................................... 48
4.3
Appendix 3, Related Business Control Documents and References ............................. 50
4.4
Appendix 4, Cement Plug-Back Process ....................................................................... 51
4.5
Appendix 5, Cement Plug Back – Job Programme Template ....................................... 52
4.6
Appendix 6; Wellbore cleanout calculation process for loose solid ............................... 54
4.6.1
Deviation is 30 deg or less ........................................................................... 54
4.6.2
Deviated Wells.............................................................................................. 58
TABLE OF FIGURES
Figure ‎5-1, Particle Settling Velocities ........................................................................................ 55
LIST OF TABLES
Table ‎2-1, Example of different safety factors specified by different vendor .............................. 14
3
Table ‎2-1, Amount of the respective chemicals required to neutralize 1m of acid originally
pumped ....................................................................................................................................... 35
Table ‎2-2, Recommended circulation rates, run-in speeds and lifting depths based on
experience using a 1½-inch high-pressure CTU reel .................................................................. 36
Table ‎4-1, Roles and Responsibilities ......................................................................................... 46
Table ‎5-1, Glossary of Terms, Abbreviations and Definitions ..................................................... 48
Table ‎5-2, Related Business Control Documents and References ............................................ 50
LIST OF EQUATIONS
Equation ‎4-1, Annular Velocity .................................................................................................... 55
Equation ‎4-1, Net Rise ................................................................................................................ 56
Equation ‎4-1, Max. POOH Speed ............................................................................................... 58
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1 Introduction
1.1
Background
Coiled tubing (CT) is a method of introducing into a well an uninterrupted length of tubing that is
generally employed to execute tasks necessitating the circulation of fluids within the well conduit
and the spotting of fluids/cement.
It is also used to access highly deviated/horizontal well sections that cannot be easily achieved
by wireline methods or as cost effectively by snubbing or the use of a workover hoist.
Coiled tubing was originally used to pump chemical treatment downhole or clean-up/initiate
production from low-pressure wells or following completion operations. However, advances in
coiled tubing manufacturing techniques, fatigue prediction methods and the availability of larger
diameter tubing have triggered an increase in coiled tubing applications/utilisation and a
correspondingly reduced risk of coiled tubing failure.
Coiled Tubing operations are generally performed on live wells and are potentially hazardous
activities due to:

the handling of dangerous chemicals and/or cryogenic gases;

high wellhead and injection pressures;

the complexity of operations requiring co-ordination between various PDO departments and
contractors.
1.2
Purpose
This Procedure sets out the standards by which Coiled Tubing operations are to be conducted
on PDO operated wells.
It forms the framework from which detailed work practice procedures can be developed and
maintained by contractor companies who perform Coiled Tubing operations on behalf of PDO.
It shall also be used as a reference document when preparing programmes for specific Coiled
Tubing operations.
1.3
Distribution/Target Audience
This Well Services Procedure document will be distributed to all PDO Section Heads who have
interfaces with Well Services Operations, all Well Services Supervisors and Contractor
Supervisors.
1.4
Review and Improvement
Any user of this document who wishes to provide constructive feedback, or who encounters a
mistake or confusing entry is requested to immediately notify the Document Custodian.
This document shall be reviewed as necessary by the Document Custodian, but no less
frequently than every four years. Triggers for full or partial review of this Specification are listed
in PR-1444, Well Engineering Management Framework in Chapter 5.2.4, Document Review.
1.5
Step-out and Approval
Step-Outs shall be managed as described in PR-1444, Well Engineering Management
Framework in Chapter 5.2.1, Variance from a Standard (Step-Out)
The Step-Out Request Form can be downloaded from here.
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2 Procedure
2.1
Scope
This Procedure is applies to all Coiled Tubing operations conducted within all type of PDO wells
and jobs.
2.2
Procedure Description
2.2.1
General
Coiled Tubing operations are normally conducted in PDO for the following purposes:

Post frac sand cleanout;

Reverse circulation;

Milling;

Fluid circulation and spotting stimulation fluids across completion intervals;

Nitrogen lifting;

Tubing or well bore clean out, including chemical and/or physical remove of scale and
circulating out sand fill;

Formation stimulation;

Fishing;

Barrier insertion i.e. bridge plugs, straddles;

Reaming or plug back operations using special equipment/tools;

Logging and perforating;

Well vacuuming;

Abrasive jet perforating;

SSD manipulation;

Water shut off;

Foam cleanout

Running velocity string
2.2.2
Coiled Tubing Unit description
Coiled Tubing (CT) has been defined as any continuously-milled tubular product manufactured
in lengths that require spooling onto a take-up reel, during the primary milling or manufacturing
process. The tube is nominally straightened prior to being inserted into the wellbore and is
recoiled for spooling back onto the reel. Tubing diameter normally ranges from 0.75 in. to 4 in.,
and single reel tubing lengths in excess of 30,000 ft. have been commercially manufactured.
Common coiled tubing steels have yield strengths ranging from 55,000 PSI to 120,000 PSI.
2.2.2.1
Key Elements of a CT Unit
The coiled tubing unit is comprised of the complete set of equipment necessary to perform
standard continuous-length tubing operations in the field. For onshore operations there are
options of truck mounted unit with track stack and mast unit. The unit consists of five basic
elements:

Reel - for storage and transport of the coiled tubing

Injector Head - to provide the surface drive force to run and retrieve the coiled tubing

Control Cabin - from which the equipment operator monitors and controls the coiled tubing
completed with data acquisition system
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
Power Pack - to generate hydraulic and pneumatic power required to operate the coiled
tubing unit

Pressure Control Equipment-as first line of defense to contain the pressure during operation
Coiled tubing operations are covered in detail in EP 95-1814 Coiled Tubing Operations (Vol.
4.1).
2.2.3
Coiled Tubing Pressure Control Equipment
2.2.3.1 General
Well control equipment is the main barrier for any Coiled Tubing Operations. Normally it is
consisting of two elements
Stripper, as primary barrier for Coiled Tubing operation
BOP, as secondary and tertiary barrier for Coiled Tubing operation
2.2.3.2 Stripper
A stripper packer is a pressure-containing device designed to contain well bore pressure during
coiled tubing operations. It is the upper tool in the pressure control stack. It is always mounted
above the blowout preventer, and as close to the injector chains as possible. Its purpose is to
seal around the coiled tubing in dynamic applications as the coiled tubing is run in and out of the
well.
A stripper packer has a hydraulic piston that squeezes the packer element around the coiled
tubing. Hydraulic pressure is required to operate stripper packers. There is no manual backup
or locking device to use if hydraulic pressure is lost. These tools must be operated with a 4-way
control valve. Packoff and retract functions are required to operate safely.
Stripper Packer Elements

Polyurethane packers are the standard. These have excellent chemical and wear
characteristics with a temperature range of -50°F to 200°F.

Viton and Nitrile Rubber. Compounds are used primarily if the surface well temperature
exceeds 180°F. Temperature range is 0°F to 400°F. These packers do not have the same
wear characteristics as polyurethane.

Steam service packers are available for 500°F steam service or geothermal applications.

As a backup device, hand operated pump have to be installed inside CT Control Cabin.
2.2.3.3 BOP
The function of the CT BOP is to provide a means of holding the CT and isolating the wellbore
pressure during emergency, unusual and normal operating situations. The configuration of the
BOP rams and side-port facility allows well control operations to be conducted under a variety of
conditions.
Minimum bore diameter of the BOP shall be large enough to freely pass all components of each
BHA will be run, both before and after the planned operation.
BOP should be capable of closing each ram preventer within 30 seconds at atmospheric
condition.
Function test of BOP rams shall be done after every rig up. Pressure test of BOP body and BOP
rams shall be done as per SP-1213.
For continuous operation BOP connection shall be pressure tested after 21 days interval.
All well control equipment shall be subject to a COS on an annual basis with an auditable trail
and verified by the Wells Supervisor (WE & CWI).
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2.2.3.3.1 BOP Rams
Typically, BOP rams are equipped with four sets of rams, hence the designation quad BOP.
Different configuration of BOP is also available which are Combi BOP and Triple BOP. Rams
shall be completed with:



Ram position, to provide a visual means to determine the ram position for each ram
component (as open or closed)
Kill line inlet, shall be a flanged connection sized for at least a 2-in. nominal flange and
a rated working pressure at least equivalent to the well control ram body. The location
of the kill line inlet is normally between the shear ram and slip ram in the standard well
control stack configuration. The kill line inlet should be used only as a flow path to pump
fluids during well intervention services, pressure testing of the well control stack, and/or
to equalize pressure across sealing rams.
Ram Locking System, All well control stack ram-type components shall have a system
for locking the rams in the closed position. The ram locking system shall be capable of
holding the rams in the closed position in the absence of closing pressure.
Basic function of BOP rams will be explained below.
2.2.3.3.1.1 Blind rams
Blind rams are designed to seal the wellbore isolate pressure when the bore of the ram is
unobstructed. By design it is not able to hold pressure from above.
2.2.3.3.1.2 Shear rams
The shear rams shall be capable of shearing the CT body (and any spoolable components
inside the tubing) at MASP of the well without tensile loads applied to the tubing. The shear
rams are normally located immediately below the blind rams in the standard well control stack
configuration. The shear rams shall be sized for the CT being used.
To ensure the shear rams is able to cut the desired CT size, calculation of minimum operating
pressure of BOP shall be made (as per appendix A in API RP 16ST), then during function test
of BOP rams then the actual pressure shall be above this minimum operating pressure. Doing
actual shear test is not advisable as if we damaged the shear rams then we may not able to
shear during the emergency condition. Certificate for shear rams BOP from manufacturer shall
be available with the units or in the base.
2.2.3.3.1.3 Slip rams
The slip rams shall be sized for the CT being used and should have CT guides to center the
tubing in the well control stack bore. The slip rams are normally located immediately above the
pipe rams in the standard well control stack configuration. The slip rams shall be capable of
holding the maximum anticipated hanging weight of the CT in the pipe heavy condition without
tubing movement within the slips. In addition, the slip rams shall be capable of holding the CT in
the pipe light condition to the force equal to the MASP multiplied by the cross-sectional area of
the tube body without tubing movement within the slips.
2.2.3.3.1.4 Pipe rams
Pipe rams are designed to isolate annulus pressure between the CT outside diameter and the
inside diameter of the well control stack bore. The pipe rams shall be sized for the CT in use
and should be configured with CT guides to center the tubing in the well control stack bore. Pipe
rams are normally the bottom ram well control component in the standard well control stack
configuration.
2.2.3.3.1.5 Shear-blind Combination Rams
Shear-blind combination rams incorporate two ram functions into a single well control ram
component. Shearing and sealing shall be achieved in a single operation. The shear-blind rams
shall be capable of shearing the CT body (and any spoolable components inside the tubing) at
the MASP of the well without tensile loads applied to the tubing and isolating the wellbore
without requiring movement of the CT. The shear-blind rams shall be sized for the CT being
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used. The closing pressure required to shear the CT and seal the wellbore at the MASP of the
well shall be less than the stabilized operating pressure of the well control accumulator system
and not exceed the manufacturer’s rated working pressure for the ram operating system.
2.2.3.3.1.6 Pipe-slip Combination Rams
Pipe-slip combination rams incorporate two ram functions into a single well control ram
component, holding the CT and isolating annulus pressure between the CT outside diameter
and the inside diameter of the well control stack bore in a single ram operation. The pipe-slip
rams shall be sized for the CT in use and should be configured with CT guides to center the
tubing in the well control stack bore. The pipe-slip rams shall be capable of sealing the annulus
while holding the maximum anticipated hanging weight of the CT without movement of the
tubing within the slips. In addition, the pipe slip rams shall be capable of sealing the annulus
while holding the CT in the pipe light condition to the force equal to the MASP multiplied by tube
cross-sectional area without movement of the tubing within the slips. Pipe-slip rams should hold
at least the kill pressure margin differential pressure from above the ram.
Operation of the BOP is hydraulically achieved, although rams may be actuated and locked
manually under certain conditions. All rams functions require that the tubing must be stationary
before it is activated. Severe damage to the BOP and CT may result if this requirement is not
observed.
2.2.3.3.2 BOP Accumulator
Accumulator volume shall be capable to complete 3 cycles (close-open-close) for each BOP
rams
BOP accumulator shall be able to maintain BOP pressure between 2,700 psi to 3,000 psi to
ensure the shear rams able to cut CT pipe at MASP. BOP accumulator pre-charge pressure is
1,400 psi and volume is 30 gal.
2.2.4
2.2.4.1
Coiled Tubing Quality Control
General
It is essential that the condition of coiled tubing is regularly monitored and that both its condition
and actual utilisation is carefully recorded, to minimise the possibility of failure during
operations.
Failure of the tubing will be either due to the development of pinholes caused by corrosion,
cracking or total rupture of the tubing due to fatigue or excessive stress.
Either of the above failures may lead to the uncontrolled release of pressurised, often corrosive,
fluids or high-pressure nitrogen. Such failures may lead to:

Personnel injury;

Aborted jobs and possible formation damage;

Loss of well control;

Fishing jobs for parted tubing.
In order to minimise the possibility of tubing failure the following practices are to be employed:

Real time force calculation of the stress and pressure subjected to Coiled Tubing

Real time working limit of Coiled Tubing Operating Limit

Tracking of utilisation of Coiled Tubing pipe by logging their operations, retirement of the
Coiled tubing pipe shall be based on its operating history and Coiled Tubing pipe condition.

Physical inspection of tubing at regular intervals, and removal of doubtful or over-stressed
section.

Working in accordance with safe operating limitations.
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
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Proper pipe management
2.2.4.2
Manufacturer’s Information
Each individual coil of tubing supplied shall be accompanied by a manufacturer's information file
containing the following information:

Traceability and quality certificates of the tubing material. Where applicable, this shall be
for each individual section of coil;

Position of each bias weld location report and butt weld in the coiled tubing;

Certificates of Gamma ray or X-ray examinations of each butt weld in the coil.
This information shall be maintained in the coil's individual record file, available for inspection at
the Contractor's CTU operations base.
2.2.4.3
Utilisation record
The CTU Contractor shall maintain full records of all coiled tubing operations. For each
operation, the following information shall be recorded:

Job type; type and volume of fluid pumped; maximum pump pressure;

Well contents and presence or absence of H2S and CO2;

Footage run in hole, and cumulative total footage run in hole;

Number of load cycles, i.e. trips in and out of the well, and depth interval of cycles if pipe
has been cycled over a limited depth interval below the surface;

Maximum pull on the tubing during the operation.

Number of Acid jobs or any high corrosion fluid.
This information is essential to evaluate the tubing condition.
The tubing is stressed every time passes through the gooseneck. It has been shown that the
number of load cycles a section of tubing has been subjected to is a more direct indicator of its
wear than actual footage runs in hole.
The tubing utilisation record shall be available at all times with the CTU.
2.2.5
Physical Testing of Coiled Tubing Quality
In special circumstances where a particular portion of the tubing has been severely stressed by,
for example multiple cycles through the injector under tension or in the job where the coiled
tubing pipe failed (crack, collapsed,...), it would be prudent to cut out the section for testing.
The test piece shall be forwarded to a qualified, independent metallurgical laboratory, where the
following physical parameters shall be measured:

Yield strength;

Tensile strength;

Percentage elongation;

Rockwell hardness;

External diameter (minimum and maximum);

Wall thickness.
The test results (failure analysis) shall be compared with the tubing's manufacturing
specifications and previous routine tests to identify unacceptable deterioration in the tubing
characteristics.
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2.2.6
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Pressure Testing of Coiled Tubing Pipe before starting the job
Before starting CTU operation, the Coiled Tubing Pipe shall be pressure tested.
This pressure test shall be performed with fresh water to a pressure similar to 10% more than
pumping pressure designed for the job, which shall be held for 10 minutes.
At the same time, the tubing shall be drifted by pumping the biggest steel ball. And for some
specific jobs, the coiled tubing pipe must be pickled by acid if required and requested by PDO.
Other pressure control equipment shall be tested as per SP-1213 requirement.
2.2.7
Tubing Retirement
It is not possible to formulate a rigid rule on the useful life of a coil of tubing as this is influenced
by many interacting factors, including:

number of runs in the hole;

number of times the tubing has been passed through the injector head/gooseneck;

Internal pressure while passing through the injector head;

tension, compression and torque stresses;

frequent failures as pinhole, cracks;

type and volume of fluids pumped through the tubing;

well fluids in which tubing was run;
However, the risk of tubing failing during operation may be minimised by carefully control of the
tubing utilisation record and strict tubing quality inspections. Therefore for Coiled Tubing fatigue
tracking it will rely to the pipe fatigue record. Coiled Tubing pipe will be retired when it reached
100 % life if safety factor minimum 20 %. This safety factor is different for each servicing
company and will depend on the type of the jobs.
Table ‎2-1, Example of different safety factors specified by different vendor
Max fatigue life allowed (included 20 % safety factor in their fatigue model)
Vendor A
100%
Vendor B
100%
Vendor C
90%
Cutting out those sections that have been repeatedly cycled over the gooseneck will increase
available tubing life.
Failure of the tubing will often be preceded by the development of pinhole leaks, and the
occurrence of these should be taken as a clear indication of potential problems.
Maximum stress on the tubing occurs as it is successively straightened and bent coming off the
reel and passing through the gooseneck and injector head. The number of load cycles to which
the tubing has been subjected shall be considered as the primary factor in assessing tubing
wear rather than the actual footage run in hole.
Elevated pumping pressures exerted whilst moving the coil through the injector head will greatly
increase the stress and resultant permanent strain.
2.2.8
Rigging Up
The following is a general guide to the rig-up procedure, for Low, Medium and High-risk wells.
Uncovered well cellars shall be covered with lightweight portable grating and scaffolding, carried
by the coiled tubing unit, prior to any work being undertaken on the wellhead.
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Prior to rig up of the coiled tubing unit (CTU), the coiled tubing pipe length and fatigue life shall
be inspected to ensure remaining fatigue life is sufficient for the job; minimum length is 100 m
more than the well depth
In the event that the CTU operation is “stand alone”, sufficient lighting must be available on site
in case the operation runs into the hours of darkness
Prior to Well Intervention all trees should be body tested by inflow testing, and all valves
function tested and inflow tested, unless the tree falls inside “Planned Preventive Maintenance”
schedule.
Only flanged connection below BOP is acceptable for CTU operation for high risk oil wells and
gas wells with CITHP above 20,700 Kpa.
There are three type of rig up allowed in PDO:
Track Stack
Big foot or/and hydraulic track stacks will be rigged up as the support of CT Injector Head.
Mast
Dedicated hydraulic mast with the unit as the support of CT Injector Head
Job without track stack (hang injector and the stack with the crane)
Job can be done without track stack when on low/medium risk wells and the tool string
considerably short. Senior Well Engineer approval is required.
The CTU shall be rigged up according to the Contractor’s rig up procedures, but great care shall
be exercised as this normally involves the lifting of heavy equipment over pressurised
wellheads. Lifting plan should be available and mitigation in place. Big foot/Track stacks shall
only be slide toward tree and not lifted. Refer to the following for safe lifting operations:
 PR-1042, General Operational Safety
 PR-1708, Lifting and Hoisting Procedure Part 1 Framework, Part 2 Inspection, Testing and
Certification
 SP-1213, Well Control
All CTU tool strings shall include dual flapper check valve assembly except for Concentric
Coiled Tubing operation or reverse circulation operation where reverse circulation tools is
required.
Disconnecting mechanism shall also be run to release the coil in case of stuck, whenever
appropriate.
Surface filter shall be installed for all of operation except for cement/sand plug jobs.
For operation with small area jetting nozzles down hole filter maybe required.
BOP can be used as lubricator to accommodate the BHA to allow shorter stack up.
Safety pin for track stacks must be installed prior operations and fall arrestor shall be used.
2.2.9
Pressure and Function Testing
Low Pressure Test (LPT) 300 psi for 5 minutes; verify equipment assembly.
Pressure Test Blind Rams and BOP Body:
With BOPs installed on wellhead, upper blind rams closed, coiled tubing not inserted in BOP
stack, the ram shall be tested as per SP-1213 requirement.
Pressure Test Pipe Rams, Double Flapper Check Valve and Stripper:
Prior to opening the well, with all equipment rigged up and downhole check valves installed,
with the coiled tubing inserted in the BOP stack, stripper and pipe rams closed, pressure test as
per SP-1213 requirement.
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All BOP’s rams shall be function tested prior running in the hole, making sure the correct
hydraulic hoses connected to correspondence BOP rams. Open/Close indicators and manual
locking handles are checked prior operations.
During the pressure test, all lines and connections shall be visually inspected for signs of
leakage. Any weeping joints, even though they may pass the pressure test, shall be repaired or
replaced as these may fail whilst pumping acid into the well.
All pressure testing is to be done with water or brine. Pressure testing with N2 may only be
done in specific extraordinary circumstances and with the prior agreement of the PDO
supervisor.
2.2.10 Safety Requirements
2.2.10.1 General
Coiled Tubing operations are particularly hazardous due to the high pressures involved and the
hazardous nature of the fluids handled.
Safety requirements for the wellsite, equipment and personnel protection are covered in:
 PR-1042, General Operational Safety
 PR-1045, Hazardous Substances
 SP-1219, Well Engineering H2S Specification
See also the following with regard safety considerations during concurrent operations:
 SP-1220, Concurrent Operations Specification
2.2.10.2 Special Considerations for Coiled Tubing Operations
The following basic guidelines must be adhered to for safe operations:
i. For high risk wells and level 3 H2S, the injector head assembly shall be fixed directly over
the wellhead on a support frame. This can be achieved by means of four adjustable
stabilising legs, which support the corners of the injector head, placed on solid ground (not
directly upon the well cellar grating), with load plates if required, or preferably with a boxsection support frame. For low/medium risk wells it will be suspended from a hoist or crane
using certified lifting gear with approval from CWI Team Leader.
ii. Additionally, chains shall be attached and secured with chain tensioner between the four
corners of the injector head to the concrete blocks.
iii. When connecting the hydraulic hoses to the injector head, the hydraulic power pack motor
shall be shut down to prevent accidental energising of any of the hydraulic functions of the
injector head.
iv. All persons climbing to reach the injector head shall use proper platform and safety harness;
or self control cherry picker. Climbing on the wellhead, which may be slippery with oil, is
forbidden.
2.2.11 Coiled Tubing Operating Guidelines
2.2.11.1 General
Potentially most coiled tubing operational failures occur when running into the hole. The most
common problem is buckling when the tubing hits some object or catches on a change of
borehole diameter.
The potential for buckling is a function of the coiled tubing wall thickness, diameter and the size
of the tubing or casing that the CT is being run into.
Prior to running in the hole, the following information shall be available on site:

wellbore profile or completion diagram and well history;
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
deviation profile of well bore;

computer simulation operating limit predictions, or maximum pressure rating and pull
strength of the CT;

diagram of bottom hole assembly including tool dimensions;

length of CT pipe

volume of fluid available on location

H2S and CO2 concentration

details of any previous wireline drift run.
2.2.12 ESD System
The control of remotely actuated Xmas tree valves and SCSSSV’s must be isolated from the
ESD system while coiled tubing is being run in a well.
Hydraulic wellhead valves/SCSSSV may be either locked mechanically open or hydraulically by
maintaining required control line pressure locked in place by needle valve. This required to
regularly monitoring locked pressure thru acquisition system. The manipulating locked pressure
is strictly prohibited while coil in motion and coil has to completing stopped to adjust the
pressure. The PDO and Contractor lead supervisors need to witness this operation.
2.2.12.1 Maximum Running Speed
The following practices are recommended: A maximum running speed in hole for normal
operation of typically 50 feet per minute (15 m/minute). This may be increased, for operations
such as PLTs, or if the hole section has been previously traversed to ensure that no restrictions
are evident.
A maximum running speed of 10 feet per minute (3 m/minute), when running through
restrictions such as SCSSSV, sliding side doors, nipples and gas lift mandrels. This reduced
running speed should be applied for 50 feet (15 m) before and 50 feet (15 m) after the position
of the downhole obstruction to allow for any discrepancies in the depth readings.
Pulling out of the hole (inside tubular) the speed is not as critical, but should be limited to a
maximum of 100 feet per minute (30 m/minute). The same speed reductions as above should
be applied when pulling through well conduit restrictions or in open hole. In addition, on pulling
out of the hole the speed should be reduced to 10 feet per minute (3 m/minute), when within
100 feet (30 m) of the wellhead or BOP.
For slim BHA, extra careful when CT pipe reaching around 30 m from surface, no body allowed
to put hands on injector chain to check arrival of slim BHA on surface.
2.2.12.2 Maximum Pumping Rate
Maximum allowable pumping rate will depend on the characteristics of the fluid being pumped
(especially viscosity) and the total tubing length. The burst pressure of the coiled tubing will
provide the ultimate limit. For reverse circulation the collapse pressure of the coiled tubing will
provide the ultimate limit.
To achieve more pumping rate friction reducer can be added to the system
However, the reaction of the friction reducer on the formation being treated must be taken into
consideration as this may impair permeability thereby decreasing the permissible pumping rate.
All friction reducing agents must be approved by Production Chemistry prior to their use in a
particular operation.
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2.2.12.3 Running Guidelines
A double flapper check valve shall be run on all CTU jobs except for cementing , wellvac and
reverse circulation operations.
The tubing shall never be run empty, to prevent collapse and slow circulation through the tubing
is advisable throughout the running operation.
It is recommended to circulate through the CT whilst running in hole. If buckling does occur
whilst running in, the pipe will kink and a rapid increase in circulating pressure will be noticed.
Pull test shall be done every 500 m interval and may be done frequently depend on the type of
operation.
Minimum clearance between CT BHA and completion shall be discussed and agreed with PDO
Well Engineer during job designing phase.
Prior running in hole any thru tubing tools picture, OD and ID shall be recorded
During the job CT operator shall ensure that CT was run within its operating limit
2.2.12.4 Pumping and Flowing Through Coiled Tubing
There is no definite way of predicting the development of a surface leak with coiled tubing.
For this reason, the following restrictions shall apply to the pumping of fluids:

Hydrocarbon gases shall not be pumped through coiled tubing, in few cases Sayyala crude
can be pumped to the well.

Fluids classified as "High Risk" flammables may be pumped through coiled tubing, provided
that adequate fire fighting equipment and trained fire fighters are on site.
 PR-1045, Hazardous Substances
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2.2.13 Coiled Tubing Emergency Procedure
2.2.13.1 General
The primary objective in dealing with a Coiled Tubing (CT) emergency situation is in all
cases to minimise risk to people, asset and environment.
This section defines guideline standard contingency procedures for emergencies that may arise
during coiled tubing (CT) operations dealing with most common type of emergencies. It should
be recognised, however, that emergency situations are never fully alike and that the guidelines
given shall never be a substitute for sound judgement and a common sense approach to any
emergency situation.
2.2.13.2 Power Unit Failure
2.2.13.3 Stuffing Box Leak
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2.2.13.4 Collapsed Coiled Tubing shallow in well
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2.2.13.5 Collapse with Coiled Tubing deep in well
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2.2.13.6 Tubing Parted between the Reel and injector
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2.2.13.7 Tubing parted downhole
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2.2.13.8 Tubing parted between Injector and Stripper Assembly
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2.2.13.9 A Hole in the Coiled Tubing Above the Stripper (RIH)
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2.2.13.10 Coiled Tubing Buckled Between the Stripper and Injector
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2.2.13.11 Uncontrolled Descent of Coiled Tubing into the Well
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2.2.13.12 Uncontrolled Ascent Out of the Well
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2.2.13.13 Emergency BOP Operation
2.2.13.14 Stuck Coiled Tubing
CT may be considered stuck when an overpull of 20% above normal pick up weight or pull up to
80 % of yield fails to free it.
Sticking may be due to any of the following reasons:

pump failure during sand clean-out or descaling operations;

unexpected increase in drag (typically in high deviation wells);

Obstruction or debris in well (e.g. packer elements, lost circulation material, perforating
debris, etc.);

Differential sticking.
The following approach should be considered in the event pipe is stuck:
a. Be aware that moving the coiled tubing up and down over the tubing guide arch rapidly
weakens the coiled tubing. High pumping pressure while working the pipe should be
avoided if at all possible as this greatly accelerates the fatigue problem. Minimize unnecessary attempts of cycling the CT pipe.
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b. Check for fluid return and attempt to maintain circulation if it’s possible.
c.
Compare current tubing weight with previous pick-up weight.
d. Apply a tensile load to the coil of up to 80% of pipe tensile yield rating and hold. Monitor
weight indicator for changes in weight.
2.2.13.15 Friction stuck with circulation:
If the weight indicator reading decreases after applying the 80% pipe tensile yield load, it is
likely that the pipe friction stuck. The following options may exist:
a. Increase pipe buoyancy by circulating heavier fluid into the wellbore; be aware of the
risk of collapse.
b. Pump friction reducing fluids or additives.
c.
Displace the coiled tubing with lighter fluids such as nitrogen or diesel to further
increase the buoyancy.
d. Increase circulation rate to lift debris.
e. Work tubing free of stuck.
2.2.13.16 Mechanically stuck with circulation:
If the weight indicator load does not decrease after applying a tensile load of up to 80% of pipe
tensile yield rating, it’s likely that the coiled tubing stuck mechanically. Attempt to lower the Coil
into the well to determine if it is actually stuck at that point or if it is unable to pass through a
restriction or upset in the completion pipe.
If coiled tubing can be moved downward, then determine the following:
a. If the pipe or tools could have been bent or buckled by setting down excessive weight or
running into an obstruction.
b. The type of connection used to connect the tool string.
c.
If any restriction or obstruction can be identified by reviewing the pipe and BHA position
in well compared to the well sketch.
The following options may exist:
a. Ensure that the injector pulling limit is set at 80% of coiled tubing tensile yield rating.
Lower the coiled tubing 10 to 15 feet and attempt to pull the pipe past the previous
stuck point again.
b. Pump a ball to release the hydraulic disconnect if it is determined that the BHA is
getting hang up.
c.
Kill the well and cut the coiled tubing at surface than follow normal fishing procedures.
2.2.13.17 Mechanically stuck and cannot circulate:
If the pipe is stuck and cannot circulate, the following steps should be taken:
a. Pump the kill fluid down the coiled tubing. if it is not possible to pump down the coil,
attempt to pump down the annulus.
b. Try to release the BHA and pull, if no, cut the coiled tubing at surface than follow the
fishing procedures.
2.2.13.18 Stuck due to fill or known debris.
If sticking due to debris or fill is suspected, pull to the permitted maximum as a first attempt,
then attempt to work the tubing whilst circulating, noting the following:
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
Constant load cycling at the same depth rapidly weakens the pipe.

Pumping at pressures over 14,000 kPa while cycling the tubing will accelerate tubing
fatigue.
If sticking due to drag is suspected, a number of techniques may be used:

Circulate a pill of slick fluid (well friction) or solvent (paraffin, bitumen).

Rapidly bleed off annulus pressure (if possible) whilst pulling on the tubing.

Attempt to increase the buoyancy by displacing the CT with nitrogen taking care not to
create sufficient excessive external pressure differential that could cause collapse.
If the above techniques fail, the following action shall be taken:
1) Close the pipe rams and slips.
2) Slack off string weight to ensure slips are holding
3) Kill the well by pumping through the kill wing valve with kill fluid, after first circulating out the
coil with the same fluid in order to avoid collapse of the tubing, and prevent blow-out of the
CT when it is cut.
4) Remove all skate tension, break the connection above the BOP and raise the injector.
Clamp the CT and cut it above the clamp leaving as much tubing "stick-out" as practically
possible.
5) Rig down the injector head and rig up electric line.
6) RIH flash cutter (normally ¾-inch OD) and cut the tubing at the deepest point possible,
taking into consideration the mode of sticking.
7) Rig down the flash cutter and make an initial test to the maximum permissible tension with a
crane that is capable of safely pulling the required tension, if available, or with the travelling
block, if a rig is on site. If free, fish tubing as per Section 2.2.8.6 items 9 to 13.
If the CT remains stuck, consider the following options:

Flash cut at shallower depth.

Hydraulic snubbing unit;
Once upper section of coil has been removed, fishing lower (stuck) section may be
accomplished by using:

Heavyweight CTU; or

Hydraulic snubbing unit; or

Workover rig.
2.2.14 Acidizing with Coiled Tubing
2.2.14.1 General
Acid can be spotted in a well with CT to clean the perforations or stimulate the flow across the
perforations by remove filter cake. As well it could be used to remove scales (Carbonate based
scale which is soluble in acid).
1) Prior to being acid is used the reel should be pickled using 5% solution, then pigged. The
connector should be attached to the end of the coil and the reel pressure tested.
2) The toolstring is made up and the coil is then stabbed and run in the hole. Depending on the
risk of the well Low, Medium or High the reel should be full of the correct weight brine fluid
to equalise the well pressure while running in hole
3) Acid should be pumped when the coil tubing nozzle reaches the desired depth. The
pumping of acid should be referred to the contractors Operations Manual.
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4) After the acid has been washed across the zone it will be circulated out and disposed of as
per HSE guidelines.
5) There might be at least 1.5 hole volume of correct weight brine on location during the
operation depending on well condition.
6) All returns should be via a choke manifold taking returns through the kill line side of the tree.
Then to the flare pit or return tank.
7) If the well having high H2S then return must be routed to flow back loop and a means of
fluid separation to keep igniting produced H2S.
2.2.14.2 HSE Aspects of Acid Washing
2.2.14.2.1 Safety Meeting
Prior to operations involving the use of acid, a safety meeting shall be held, attended by the
following personnel:

PDO Supervisors;

CT Contractor Man-in-Charge and any crew involved in the operation;

Pumping Contractor personnel.
Note: Non-essential crew shall be instructed to keep well clear during pumping operations.
The following subjects shall be discussed:

Correct PPE;

First Aid equipment and procedures;

MSDS sheet available.

Permit to Work requirements;

Operation plan;






Objective of treatment;
Assignment of duties;
Sequence of events;
Maximum pressures and pumping rates;
Placement of equipment
Handling of returned (spent or partially spent) fluids.
Note:
ALL acids returned from the well should be considered as live acid, NOT
spent acid.
2.2.14.2.2 PPE
Minimum PPE requirements for all personnel working in the vicinity of the pumping operation
shall be:




Hard Hat;
Chemical Safety Goggles or Face Shield;
Safety Boots;
Gloves - rubber gloves for handling acids, work gloves for rigging up/down equipment.
Personnel involved in the handling of acid shall be equipped with full protective clothing. This
shall consist of:





Respirator;
Mask;
Full length rubber gloves (no pin holes);
Rubber apron;
Rubber safety boots.
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2.2.14.2.3 Job Planning
Acid handling and other operations shall be controlled as required by Chapter 15.9 of PR 1172
"Permit to Work System Manual".
Acid wash operations should not proceed in the dark unless there is adequate lighting available.
The acids used, hydrochloric acid (HCl) and hydrofluoric acid (HF), are toxic and dangerous
chemicals. Refer to the relevant SHOC card/MSDS for details of handling, storage and disposal
precautions.
Only essential personnel shall be allowed in the vicinity of the acid handling equipment. Every
effort shall be made, particularly through thorough pre-job planning, to ensure that minimum
intervention by personnel is required during the acidisation.
Safety barriers shall be used as appropriate to isolate the areas of potential hazard,
Programme should be discussed, roles and responsibilities are clearly assigned.
2.2.14.3 First Aid Procedures
2.2.14.3.1 Hydrochloric Acid (HCl)
i.
Fresh water and bottled neutraliser shall be available at the worksite.
ii.
Emergency shower shall be available and working on location
iii.
In the event of acid contact with the eyes, immediately flush eyes gently with clean
water and consult a doctor as soon as practicable
iv.
If acid contacts the skin, wash the area thoroughly with fresh water. Remove
clothing contaminated with acid or acid additives. This clothing should not be reworn until thoroughly washed.
2.2.14.3.2 Hydrofluoric Acid (HF)
Concentrations as low as 2% may cause symptoms if in contact with skin for long enough.
Dilute solutions of HF penetrate deeply before dissociation. Surface involvement is minimal and
may even be absent.
In the event of contact with HF acid, a speedy response is critical. All potentially exposed
personnel shall be trained in its handling and first-aid actions shall be planned before beginning
work with HF.
Rescuers shall take precautions against inhalation and contact with HF acid during the rescue
operation.
A suitable first aid kit shall be located in or near work places where HF acid is been used or
transported.

12 tubes x 25g Calcium Gluconate Gel (2.5% concentration);

12 sealed packs of sterile medicated swabs;

Two pairs of gloves for rescuers (pin-hole free) - Nitrile or Neoprene (PVC clothing should
not be used)

Scissors (one large, one small) - for cutting clothes;

Drinking water (2 litres) and drinking cup;

Eye Irrigation bottle with sterile isotonic saline solution.
In the event of contact with HF acid, the following treatment should be immediately applied:
i.
Remove contaminated clothing and shoes.
ii.
If breathing or heart has stopped, resuscitate victim by artificial respiration and/or
cardiac massage. Use oxygen if breathing is laboured.
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iii.
Flush the contaminated skin with copious quantities of water for at least five
minutes.
iv.
Apply Calcium Gluconate Gel and massage it into the burnt area. Continue to
massage while repeatedly applying gel until 15 minutes after pain in the burnt area
is relieved. If Calcium Gluconate Gel is not readily available, continue to flush with
water until it is available. It is advisable for the applier to wear surgical gloves. After
treatment of burned areas has begun, the victim should be examined to ensure
there are no other burn sites which have been overlooked.
v.
Flush the eyes with eye wash solution (sterile isotonic saline solution)
vi.
Give up to 2 litres of water to drink to dilute. Never give anything by mouth to an
unconscious victim.
2.2.14.3.3 Rigging-Up
Rigging-up activities shall comply with the following:
i.
Use sufficient swivel joints to give flexibility to the treating line, in case of change
elevation use 3-way chiksan and when change direction use 2-way chiksan. To
have wing facing well.
ii.
Line should be chained or clamped to the wellhead.
iii.
Install check valve on ground as close to wellhead as practical.
iv.
Pressure test all lines with water as per SP1213 requirement to predetermined
pressure. Do not strike or tighten line while under pressure.
v.
Fill both displacement tanks with water prior to pumping acid.
vi.
Equipment should be bonded and grounded.
vii.
Proper rigging should allow for water to be flushed back through suction line after
acid has been pumped.
viii.
Spotting of tankers should allow for a minimum of suction hose to be used.
ix.
Hatches on tankers should be opened with caution prior to job.
x.
Pumping string shall not be rotated using a chicksan as swivel. If rotation is
required a rotating head needs to be rigged up.
xi.
CT must be cut after each operation to spread the fatigue life within the length of
Coiled Tubing pipe.
2.2.14.3.4 Requirements for Safe Operation
Acid washing operations shall comply with the following:
i.
A dedicated line shall be used from the pumping unit to the well. The transfer and
pumping lines shall be properly secured with snubbing lines.
ii.
Under no circumstances hammer on leaking connections whilst pumping acid. The
lines shall be pressure tested prior to starting the acid job.
iii.
A pressure relief valve shall be installed on the pumping unit with the vent directed
away from all personnel. The vent area should be flagged off. A non-return valve
shall be placed in the pumping line as close as possible to the well.
iv.
Returns from the well shall be taken via the flow SWV.
v.
Be aware of the risk of reaction gases evolved during the wash (primarily CO2)
unloading the well as they near surface. This can be particularly severe in shallow
wells.
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vi.
Due to the risk of contamination and splashing personnel, live acid shall not be
returned into open top drilling fluid tanks. All acid returned from the well shall be
regarded as live acid.
vii.
Should there be a delay in the requirement for HF acid, and the chemical has
already been delivered to the well site, storage of HF acid should preferably be in
the open air in a separate chemical storage area with restricted access and away
from occupied buildings.
viii.
Extreme care must be taken during high pressure pumping while conducing acid
stimulation treatments as unexpected leaks on surface lines can develop which
could release the HF acid as a fine spray. HF acid can vaporise in air to form a
noticeable cloud if released to the atmosphere. If the vapour cloud is concentrated
enough it can be toxic until sufficiently dispersed.
2.2.14.3.5 Acid Formulation
The acid formulation shall be specified in the Program. All acid recipes and volumes will be
confirmed by UIK prior to call off. Acid solutions shall be ordered pre-mixed and ready to pump.
HF acid shall not be ordered unless it is absolutely known that it shall be pumped downhole.
Transport of the premixed acid shall be in a dedicated tanker.
The onsite dilution and mixing of concentrated acid shall not permitted.
2.2.14.3.6 Sampling
Sampling of the acid shall not be conducted unless specifically requested by the Program. In
these cases, the requirement shall be explicitly confirmed with the relevant Senior Well
Engineer. Contractor personnel are fully geared to safely handle any phase of acid operations,
including sampling for neutral pH after disposal.
2.2.14.3.7 HCl Acid Neutralization and Disposal
Spent acid may be disposed of by discharge direct to the waste pit. The acid shall be
neutralised whilst flowing through the cuttings slot by the addition of either Soda Ash or Calcium
Carbonate LCM. Alternately, pre-mixing soda ash in a tank of water and discharging both the
live acid line and the neutralizing water line into the pit has proved to be a safe, effective
neutralizing procedure.
The following table identifies the amount of the respective chemicals required to neutralize 1m
of acid originally pumped:
3
3
Table ‎2-2, Amount of the respective chemicals required to neutralize 1m of acid
originally pumped
Hydrochloric Acid
Concentration
3
kg of Soda Ash per m of acid
pumped
kg of Calcium Carbonate
3
LCM per m of acid
pumped
120 kg
225 kg
15%
235 kg
28%
470 kg
HCl/HF Acid Concentration
12%/3%
235 kg
225 kg
The end products of the neutralization process for HCl acid are NaCl (with Soda Ash) or CaCl2
(with Calcium Carbonate), water and CO2. The main by-product while neutralizing HF acid will
be sodium fluoride (not harmful). These disposal methods are considered acceptable and
represent a significantly reduced safety hazard to personnel rather than neutralization in the
active tank system prior to dumping.
Checks shall be made on the pH of the waste pit after dumping the acid to ensure that it has
been neutralized effectively.
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2.2.15 Nitrogen Lifting with Coiled Tubing
2.2.15.1 General
Nitrogen (N2) is injected into a well via coiled tubing to lift the tubing contents for the following
purpose:

to create a drawdown prior to perforating;

to create a drawdown in order to kick-off a well;

to create a drawdown for reverse pressure testing of the tubing or its components;

to evacuate the tubing and pressurise with N2 for a gas integrity test;

to evacuate the tubing and pressurise with N2 prior to a Stimulation job with a N2 cushion;

to clean out debris from well with nitrified gel.
2.2.15.2 Continuous Nitrogen Lifting
The parameters governing the continuous lifting of liquid from tubing with N 2 are:

liquid density and viscosity;

annular area between coiled tubing and tubing;

N2 circulation rate;

CTU running/pulling speed; and

Back pressure.
The most efficient method of lifting is to commence circulation of N 2 as close to the surface of
the liquid as possible, which exhibits minimum or near to zero backpressure.
After lifting has commenced the coiled tubing is run in hole to lower the injection point to
establish continuous lifting with minimum circulation pressure throughout. The run-in speed and
circulation rate are important in order to achieve efficient continuous lifting.
The run-in speed during lifting shall not be too fast (maximum 15m/min) otherwise the risk of
running ahead of the lift and having to pull back to re-establish lift is encountered.
The table below gives an indication of recommended circulation rates, run-in speeds and lifting
depths achieved, based on experience using a 1½-inch high-pressure CTU reel.
Table ‎2-3, Recommended circulation rates, run-in speeds and lifting depths based on
experience using a 1½-inch high-pressure CTU reel
Tubing size
N2 rate
Run-in speed
inch
Gals/min
m/min
3½
4
15
4½
6
12
5½
9
8
The preferable choke size at return line is ½” choke.
Depth lifted
m
4500
4500
3000
This can be used as an aid in deciding programme parameters and estimation of fluid level
depths after a Nitrogen lift.
Pulling out speeds shall be restricted to a maximum of 30 m/min, depending on the trajectory of
the well and any restrictions or diameter changes in the tubing string.
When passing downhole restrictions (i.e. SCSSSV's, mandrels, wireline nipples, tail pipes etc.)
maximum run in/pull out speed shall be reduced to 3m/minute.
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2.2.15.3 Nitrogen Sweep Lifting
On shallow wells a less common, but faster way of lifting liquid from the tubing using less
Nitrogen, called sweep lifting can be employed.
This involves running the coiled tubing in hole at a maximum speed of 30 m/min whilst
continuously pressurising the tubing to avoid tubing collapse and then only starting to displace
whilst on bottom.
The expanding N2 bubble will, in small annular spaces, displace most of the liquid up the tubing
in one sweep.
The maximum lifting depth in such cases is dependent upon the maximum allowable pump/reel
pressure.
Note that this method involves much higher N2 pump pressures that creates a greater safety
hazard and also reduces the coiled tubing life.
A Nitrogen Displacement Graph (which may be built into a computerised data acquisition and
recording system) can be used to determine the maximum depth limitations with regard to the
maximum allowable CTU pumping pressure.
Using the calculated Bottom Hole Pressure, based upon the well fluid contents, at the targeted
depth, the expected WHP can be determined.
For safety add about 10% to this figure to compensate for friction losses whilst pumping.
If this pressure is then below the maximum allowable CTU pumping pressure, it can be safely
assumed that the depth can be reached in one sweep.
Because of the risk of bringing hydrocarbons to surface up the CT /production tubing annulus,
all returns should be via a choke manifold taking returns through the kill line side of the tree.
The returns will be disposed of in accordance with current HSE procedures.
2.2.15.4 Determining Fluid Level After Lifting
If it is required to establish the fluid level after N2 lifting, this can be achieved by any of the
following means in order of accuracy (starting with the least accurate):
1. By estimating the volumes of fluid returned from observing pit flows.
It is almost impossible to accurately estimate flows and this method is therefor only to be
used as an indication of lifting performance and nature of returns.
2. From an estimation of lifting depth by use of the table in Section 2.2.12.2
This should be 95% accurate provided proper follow through of the lift on depth is applied.
3. By measuring volumes of fluid displaced through the PD meter of a separator.
Note:
the backpressure applied by the separator will reduce the lifting depth
achievable.
The accuracy depends on the flow meter but should, in general, be greater than
95%.
4. By carrying out a wireline fluid depth tagging run.
This is fairly exact, but because of the time and risk involved this operation shall not be
carried out unless absolutely necessary. It shall preferably be combined with a HUD run if
required.
2.2.15.5 Programme Guidelines
Prior to any Nitrogen lifting operation, the operator shall be provided with a copy of the well
diagram and a written programme containing the following data:

Pressure test data;
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
Rig up configuration;

Run in speed;

N2 circulation rate;

Maximum run in depth;

Time on bottom;

Pull out speed;

Running speed passing downhole equipment.
Revision: 3.0
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A sample programme would contain the following steps:
1) Rig up BOP, and function test all BOP rams.
2) Note: BOP configuration in this part shall be specified. High-pressure jobs need a special
consideration.
3) Test all surface equipment as per Sp-1213 requirments.
4) Pressure test BOP body and Blind Rams to the same pressure.
5) Rig up CTU, stab tubing and connect double flapper and rounded bullnose.
6) Rig up injector and zero the weight indicator and depth counters.
7) Close the pipe rams on the tubing and test the pipe rams and coil to the same pressure as
in or the maximum allowable working pressure of the coiled tubing as defined by Coil LIMIT,
whichever is less.
8) Test the lower and upper stripper (if in use) to the same pressure.
9) Test the double flapper valves to 10,000 kPa. (For a detailed step by step test programme
refer to the operators manual)
Note:
All tests to be done with water or any other solids free liquid, but not acid.
Pressure testing with N2 may only be done in specific extraordinary
circumstances and with prior agreement of the PDO supervisor.
10) Completely displace CTU reel to N2 prior to running in hole.
11) Note : The wellhead pressure, if any, shall be bled off as much as possible prior to running
the tubing in hole. The tubing shall never be run empty, to prevent collapse.
12) Run in coiled tubing to 4500 metres bdf continuously displacing tubing to N2 by pumping 5
gallons/min with a run in speed of 15m/min.
13) Stay on bottom for 10 minutes, then POH at 30 m/min while continuing pumping N2 at 5
gallons/min.
Note:
When passing downhole restrictions (i.e. SCSSSV's, mandrels, wireline
nipples, tail pipes etc.) maximum run in/pull out speed shall be reduced to 3
meters/minute. Set down weight shall at all times be kept to the minimum.
2.2.16 Cement Plug Back
2.2.16.1 General
The use of CT to cement plug back reservoir zones in deep and high-pressure wells shall not be
considered as a standard operation for the following reasons:

the depths and high reservoir pressures involved and the fact that, in most wells, the
cement plug has to be set while the well is still live;

in under-balance mode, the cement plug is kept in place by applying surface back pressure,
this, however, results in high pumping pressures and low pumping rates thereby increasing
the chance of failure;
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
the presence of gas and saline fluids in wells make the job even more difficult and every
effort must be taken to avoid slurry contamination;

Heavy wall CT is used to plug back deep/HP wells.
The overall experience of CT plug back in deep/HP wells has been good, however, failures
have occurred in the most recent jobs which has highlighted both procedural and operational
issues which need to be addressed and incorporated in the process, as listed below:
2.2.16.2 Job design considerations

In some wells it may be necessary to bleed off any present gas prior to
bullheading/circulating well with brine. This is to reduce wellhead pressure, minimise
possible cement slurry contamination and assist in RIH of CT.

Well shall be dead or dynamically stable before commencing pumping cement i.e. job
shall not go ahead until well is confirmed to be dead and/or stable.

Sufficient backpressure is to be maintained during the entire job to ensure proper plug
placement.

Use special designed spacers (weighted/viscosified) for wells that require high back
pressure to be maintained.

Same brine is to be pumped to bullhead/circulate the well and for displacing cement, to
avoid possible well influx.

Avoid pumping excess cement unless it is really necessary.

Adequate CT equipment inspection to be carried out onsite prior to the job. A standard
checklist is to be made available and used by the contractor.

Contractor to ensure CTU personnel comply with procedures at all times.

Contingency plan shall be drawn as part of job preparation.

Contractor to ensure that all future job reports are clear and reliable.

Prepare standard 'Flow chart' for CT plug back process from start to finish, complete
with action parties and deliverables.
2.2.16.3 Placement
Proper plug placement is critical for the success of the job and the following issues shall be
taken into consideration.
2.2.16.3.1 Volume Measurement
The volumes of fluids (slurry and spacers) during CT plug back jobs are generally very small (<
3
5m ) and the plug set depths are normally very deep (> 3,000m), thus requiring that the volume
measurement, and hence placement of fluids, needs to be very accurate.
The measurement system presently in place is considered sub-optimum and therefore needs to
be improved. Currently large mixers are used to mix slurries and flow meters are used to
measure pumped volumes, dedicated small mixers and calibrated displacement tanks are a
better option to ensure reliable fluid measurements. If large mixers are to be used, then
calibrated meters shall be used to ensure accurate volume measurements.
The use of a cement wiper plug pumped behind the cement slurry, to give accurate
displacement and minimise contamination inside the CT, is not recommended due to failures
and risk associated with it.
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2.2.16.3.2 Surface Backpressure
It is recommended to maintain sufficient backpressure at surface throughout the job to ensure
that the cement plug is kept at the desired depth.
This backpressure shall be maintained during WOC period until the inflow/pressure test on the
plug is to be done. The pressure shall be bled off slowly in stages to avoid induced plug failure.
The application of high backpressure may result in some cement slurry being lost into the
perforations, however, this is not considered a problem as long as the desired pressure isolation
is achieved.
For dead wells:

A 5,000 kPa back pressure is considered sufficient depend on tubing size and losses..
For live wells:

It is important that the well is dynamically stable after being displaced to heavy brine.
Displacing the well to fresh water reduces contamination risk but is not recommended as it
reduces the pressure head resulting in high well pressure.

Once the well is stable, sufficient backpressure shall be maintained over the entire job to
ensure proper placement. An estimate of the backpressure required can be obtained from
shut-in THP after displacing hole to heavy brine.

When high back pressure is applied, precise manipulation of the surface choke is critical to
ensure that correct pressure is maintained and pumped volume is equal to volume returned.

In cases where the well is not stable even after circulating/bullheading brine, then killing the
well with heavy mud/brine may be the only option before commencing plug back.
2.2.16.3.3 Excess Cement
The necessity for pumping excess cement must be decided based on the objective and
parameters of individual jobs. Pumping, then circulating out excess cement shall be avoided
whenever possible.
Normally, when the plug is long and set inside the casing or liner, it is not required to pump
excess cement. However, a small amount of excess cement is normally unavoidable, due to a
cement sheath left on the surface of the coiled tubing, and can be circulated out.
Because of measurement inaccuracies, it should always be assumed that excess cement has
been pumped and the well circulated accordingly.
During recent jobs, excess cement was circulated out under high back pressure that resulted in
erosion and blockage, due to low flow rate downstream of the choke, in surface equipment. It is
therefore recommended to design jobs so that all pumped cement is left in hole.
In wells where the plug is small (in volume) and the planned TOC is close to next set of
perforations above, it may be necessary to pump some excess cement. This is also required to
ensure that sufficient uncontaminated cement is placed. A separate return line with a choke
shall be installed to cater for the cement returns.
Recent experience with proppant circulation has shown that adjustable chokes suffer erosion
from abrasive fluid mixtures, so it is recommended to used a fixed choke and adjust the desired
back pressure by controlling the pumping rate.
2.2.16.4 Contamination
2.2.16.4.1 Surface Contamination
Precautions are to be exercised to avoid cement contamination at surface. Surface rig up shall
be kept simple and all brine tanks shall be completely isolated. All surface lines are to be
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flushed with proper retarded mix water prior to pumping cement. The slurry dump valve used to
zero counters is also useful for getting rid of any contaminated slurry.
2.2.16.4.2 Subsurface Contamination
Normally, all wells are circulated to heavy brine (13.5 kPa CaCl2) prior to setting a cement plug,
as this is necessary to reduce well pressure and to suppress reservoir fluids to avoid
contamination.
For live wells, both mix water and spacer shall be pumped ahead of cement slurry as an extra
precaution to avoid contamination. The mix water may contain fresh water and retardant only
(other additives are not required). Adequate spacers, in terms of both recipe and volumes, are
to be pumped ahead and behind the cement.
In cases where high surface back pressure (> 10,000 kPa) is to be applied during the job then a
suitably weighted/viscosified spacer is to be pumped.
Because of the high pumping pressure and low pumping rate, there is a risk that a lighter
spacer may channel through the heavy brine, rather than displacing it, which may result in slurry
coming into contact with the brine and possibly flash setting.
Specially designed spacers shall be used, therefore, based upon hole content and well
parameters (the Company chemist in conjunction with the contractor are responsible for
designing and testing of spacers).
2.2.17 Coiled Tubing Stress Analysis
Job simulation, based on expected well, reservoir and coil parameters, shall be carried out and
analysed prior to each actual job.
The simulation shall be repeated onsite to ensure that the latest well parameters are used.
Particular attention shall be given to the expected pumping pressures and depths involved.
The contractor is expected to highlight any key issues or concerns involved with the job in hand.
2.2.18 Contingency Plan
A contingency plan shall be drawn as part of the job execution programme. Key issues of
concern shall be highlighted and 'what if' scenarios discussed.
If the CT should get stuck for whatever reason, overpull above the limit is strictly against policy
and shall not be attempted without management approval.
The contractor is required to have basic tools (e.g. CT cutter) for intervention on site, in case
they are required.
2.2.19 Policies and Procedures
All personnel involved in the job shall be aware of and fully comply with:

the appropriate operational procedures;

all relevant policies in place;

the decision making route specifically during emergency.
2.2.20 HSE
It is Company policy that a cascade system shall be hooked up during all CT operations in H 2S
wells.
The system provides a continuous air supply at various points on location for well intervention.
A multi-point H2S detection system shall also be installed.
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2.2.21 Job Preparation
Listed below are the key steps to be followed sequentially during the preparation for the job.
The job preparation process is also presented in a process diagram, see Appendix C
i.
Copy of well test programme to be copied to the Production Chemist and the
Cementing & Stimulating Contractor. A lab report for spacer and cement recipe is
to be prepared well in advance. As standard procedure, a second test is to be
carried out few days prior to the job. The Production Chemist shall approve the lab
analysis reports.
ii.
A meeting shall be called few days prior to the job to discuss the job programme.
Any specific issues that require special attention are to be highlighted during the
meeting. Minimum attendees: CWI Engineer, Asset Team Production Technologist,
Production Chemist and Contractor rep.
iii.
The contractor shall prepare a Coil Analysis (CoilCADE or CERBERUS or similar)
run onsite to simulate the job prior to the actual job. The coil simulation is to be
reviewed by Drilling Engineer and Production Technologist.
Any concerns
regarding the job shall be highlighted. The contractor supervisor should be aware
of the 'Procedures and Limits' for the job.
iv.
A specific job programme shall be prepared jointly by CWI Engineer and Asset
Team Production Technologist as per the guidelines in these procedures.
v.
PDO Site Supervisor to prepare a programme for job execution. A standard format
shall be used (see template in Appendix D ). Copy of this programme might be
sent to CWI Engineer prior to commencement of the job.
2.2.22 Job Execution
The job execution process is also presented in a process diagram, see Appendix C.
2.2.23 Pre-Job Meeting
As standard practice, a pre-job meeting shall be called onsite and it is mandatory that all
personnel onsite attend. PDO Site Supervisor to go through the job programme and highlight
the key issues including contingency plan in place. Roles and responsibilities shall be clearly
defined to all personnel. Relevant HSE items shall also be discussed.
2.2.24 Procedures
Both supervisors on site (PDO and contractor supervisor) shall be aware of the job operational
limits and the contingency plan. Other contractor personnel onsite shall also be aware and fully
comply with procedures and policies in place.
2.2.25 Well and Plug Data
Well status and plug data shall be included as part of the programme together with a latest well
status diagram. Minimum data required is as listed below:

Casing/Liner size
:x"

Existing perforations
: top @ xxxx and bottom @ xxxx m bdf

HUD

Planned TOC
: xxxx m bdf

Plug length/volume
: xxx m / x.x m3 (in 4.1/2" and/or 7" liner).

Bottom of next perfs.
: xxxx m bdf (xxx m above planned TOC).
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2.2.26 Equipment check up, rig up and pressure test
Upon arrival on site, all equipment shall be thoroughly checked. This is critical when equipment
has travelled long distance and/or under rough road conditions. The contractor shall have a
standard checklist for onsite equipment checks.
Once all equipment has been checked and found to be satisfactory, rigging up shall commence.
If it is planned to pump and circulate out excess cement, then a dedicated line with choke shall
be hooked up to cater for the returns.
All equipment (CT, BOP’s and surface lines) pressure tested to the required pressures as per
standard practice/programme.
The CT string shall incorporate a check valve and a nozzle. Optimum nozzle type is to be used
with large enough jets and positioned for optimum displacement.
It is also standard practice to displace/flush the CT reel so that its capacity is known. This is
critical since the CT capacity per metre is small hence even a small volume in CT reel can have
a big impact on the job.
Ball pigs shall not be used as they are prone to getting lost and can cause problems. Dye fluid
or hydraulic oil is to be used instead. Friction pressures are to be checked against theoretical to
ensure full clearance in coil.
2.2.27 Prior to running in check list
1) Check that all equipment is functioning correctly; flow meters and depth counters are
calibrated and checked for accuracy.
2) Check that proper and adequate size mixer and displacement tanks, as planned, are to be
used.
3) Check and confirm logbook inspection of CT life.
4) Ensure CT has been drifted and capacity checked.
5) Note wellhead pressures.
6) Ensure that hydraulic master valve is locked open.
7) Confirm that there is sufficient pressure on the control line to ensure that TR-SCSSSV is
maintained fully open.
8) CTU operator to have accurate well sketch for reference.
9) For sour wells, Cascade system is to be hooked up and all personnel briefed on the system.
10) Safety pin for track stacks must be installed prior operations and fall arrestor shall be used.
2.2.28 Job Outline
The job outline set out below provides guidelines and should only be used for reference.
Adjustments will have to be made for each specific job based on the job in hand and well
parameters.
1) Bleed off well pressure to minimise any gas cap in well and to allow RIH in cases where coil
is having trouble injecting into well.
Notes:
a.) Surface backpressure shall be maintained through out the job.
b.) Surface choke shall be continuously manipulated to maintain desired
backpressure (fixed choke is to be used in case excess cement is going to
be circulated out).
c.) Bullheading the well may also be an option prior to RIH CT.
2) RIH CT while circulating well to brine (at ± 0.1 m3/min).
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a.) RIH speed at 15 to 20 m/min slowing down to 5 m/min at all restrictions and
when approaching HUD.
b.) Pull tests shall be performed as per standard procedures.
c.) Minimise the time CT is kept stationary especially after cement has exited
the coil, to avoid getting stuck.
3) Tag HUD and pull 1m off bottom to ensure CT nozzle is clear.
4) Continue circulating well with brine until well is dead or dynamically stable, i.e. no large
volumes of gas observed at surface. If well is not dead, note and report THP for
backpressure calculation.
*** At this point, mix water, spacer and cement slurry should be mixed ***
i. The spacer shall be designed based on hole content and well parameters. It shall be
mixed as per the approved recipe.
ii. Cement shall also be batch mixed as per the approved lab test report. Correct mix
water to be used. Some excess cement shall be mixed above to the volume that is
required to be pumped. Confirm cement properties prior to pumping.
Notes:
a.) Cement slurry should not be mixed too early (45 min or less prior to the job).
b.) Cementer shall be given written instructions specifying cement and additives
quantities. PDO Site Supervisor to witness the cement mixing.
c) If mixed slurry is not to the desired specification it shall be discarded and
another batch mixed. Sufficient cement shall be onsite to allow for this.
d.) Samples of dry cement, mix water, spacer and cement slurry shall be
collected and retained at site.
5) Pump ± 0.5m3 of mix water ahead of spacer (at ± 0.1 m3/min).
Note:
Mix water to contain only retardant as additive.
6) Pump 1m3 of spacer ahead of cement slurry (at ± 0.1 m3/min).
Notes:
a.) Suitable designed spacer is to be pumped if well contains heavy brine and/or
high surface back pressure is going to be applied.
b.) For dead wells, mix water can be used as the spacer. In this case, total
volume of mix water (with retardant only) to be pumped ahead of slurry is 1.0
m3.
7) Open the bleed-off line at the reel and start pumping cement until good cement is observed.
Close the bleed-of line and zero counters.
Note:
Cement slurry returns shall be collected in drums to avoid location
contamination.
8) Pump the cement slurry (at ± 0.1 m3/min).
Notes:
a.) Excess cement shall be pumped only if necessary as highlighted above.
b.) Job simulation shall be run to confirm the number of stages required for the
job. For deep wells, 2.5 m3 slurry volume has been considered as the
maximum per stage.
9) Pump 1m3 of spacer behind the cement (at ± 0.1 m3/min).
10) Displace cement with brine until cement is at CT nozzle (at ± 0.1 m3/min).
Note:
a.) CT capacity should be known.
b.) Displacement fluid shall be of the same weight as the circulation fluid. This
is to avoid well influx due to reduction in head pressure, which may result in
cement contamination.
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11) Continue to pump brine until about 10m of cement has risen above the nozzle in the
CT/liner annulus.
Note:
a.) Cement above nozzle in CT/liner annulus shall not be allowed to rise more
than 10m in order to allow quick pick up in case high drag is encountered.
b.) Accurate volume measurement is necessary to facilitate estimation of top of
cement.
12) Start POH CT while continuing to displace cement with brine (at ± 0.1 m3/min).
Notes:
a.) The CT shall be POH at a speed that will ensure the nozzle is always some
10m inside the cement for efficient cement spotting to avoid contamination.
The speed shall be calculated based on the pumping rate and the liner fill up
rate.
b.) Precise co-ordination of pumping rate and CT speed is critical for efficient
cement spotting.
13) Continue to POH while pumping brine until all cement has been pumped clear of the nozzle.
Notes:
a.) Step 13 assumes that no excess cement is to be circulated out i.e. all
pumped slurry will be left in hole.
b.) If excess cement is pumped, then the circulation point shall be at planned
TOC. It should be noted that the final TOC is normally slightly deeper then
planned depth depending upon applied back pressure and reservoir
parameters.
14) Decrease pumping rate to minimum and POH CT to the circulation point.
Notes:
a.) to counter the inaccuracies involved, CT shall be POH slowly to allow
cement to equalise and settle.
b.) CT is to be POH at least 10m to ensure circulation point is above TOC to
ensure that only small amount of cement will be circulated out.
c.) Circulation point shall also be at least 10m below the bottom of the next
planned perforations to ensure clearance.
15) At circulation point, resume(increase) pumping brine to clean the well.
Notes:
a.) Pump at maximum feasible rate to ensure optimum hole clean up (± 0.2
3/
m min).
b.) Pump at least 125% of hole volume, spacer returns will indicate bottoms up.
c.) Observe and report returns regularly.
16) POH CT while continuing to pump brine at a lower rate whilst still maintaining backpressure
in the CT/tubing annulus.
17) POH CT to surface.
Note:
Extra care shall be taken when approaching the surface especially in
HP/sour wells.
18) Rig down CTU.
19) WOC for at least 24 hours while continuing to maintain and monitor backpressure.
Note:
Monitor and report status of surface samples.
20) Inflow test the plug by bleeding off surface pressure slowly in stages. Pressure the test plug
from above to the required pressure.
21) Tag TOC with wireline. - Continue as per test programme.
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3 Roles and Responsibilities as referred to in this document
Table ‎3-1, Roles and Responsibilities
Role
Responsibility
Asset Team
CWI Co-ordinator/Supervisor

The Asset Team is responsible for defining the
objectives of the operation, the design of the
programme sequence to achieve these objectives
and the formulation of the detailed programme,
including specific equipment, operations sequence,
data collecting and reporting requirements.

The Asset Team will provide on site production
technology support with responsibility for quality
control of all pre-job and on-site cementation fluid
design, testing and mixing
The PDO Well Services Co-ordinator shall monitor
the daily progress of the operation and ensure its
objectives are being met. Necessary programme
amendments shall be discussed with the Asset
Team.


PDO Site Supervisor
Page 46

All instructions to the well site will be through the
CWI Co-ordinator.
The PDO Site Supervisor has overall responsibility
for the integrity of the well. He monitors the
execution of the operation and can step into the
execution of the operation at any time in case of
deviation from the given well objectives.

He has the authority to shut down any activity if he,
or the PDO Site Production Technologist, deems the
quality of equipment or chemicals is below the
standard required for the operation.

He will co-ordinate the logistics for all services
associated with the operation. He will co-ordinate all
personnel and equipment movements for these
services and ensure that all personnel and
equipment have the necessary certification. All
service company personnel will report directly to
him.

He is responsible for ensuring that all safety critical
items of equipment are available and tested (i.e.
overpressure relief and shut down systems)
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Role
Contractor Supervisor
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Responsibility

The Contractor Supervisor is in charge of all surface
operations on site and is responsible for site access
control.

He shall ensure that all coiled tubing equipment is
rigged up, tested and operated in accordance with
current procedures and the programme.

He will liaise closely with the PDO Site Supervisor
and will jointly issue programme instructions.

He is responsible for opening and closing the well in
accordance with the programme, and will liaise
closely with PDO Site Supervisor on progress,
advising of any situations that might compromise
safety. He may delegate the responsibility for
opening and closing the well to other contractor
service supervisors.

He is responsible for the quality of measurements,
data collection and reporting, routine inspection and
maintenance of equipment, on-the-job supervision
and training of personnel, safe operating practices of
crews, toolbox meetings, etc.

He operates under the direct supervision of the PDO
Site Supervisor and shall provide him with all
necessary information for reporting purposes
including information on operations, HSE issues,
quality control, equipment status, supplies and
logistics, etc.
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4 Appendices
4.1
Appendix 1, Forms and Reports
The following forms are used in relation to this Specification:
 Step-Out Request Form
 Well Location Custodianship Transfer Form
The PDO Site Supervisor will ensure that a Pre-Stimulation Audit Checklist is completed
jointly with the Contractor Stimulation Supervisor, and any shortfalls rectified, before the
stimulation operations commence.
4.2
Appendix 2, Glossary of Terms, Abbreviations and Definitions
Table ‎4-1, Glossary of Terms, Abbreviations and Definitions
Term/Abbreviation
Definition
May
Indicates one possible course of action
Should
Indicates a preferred course of action
Shall
Indicates a mandatory course of action
bdf
Below Derrick Floor
BHA
Bottom Hole Assembly
BHP
Bottom Hole Pressure
BOP’s
Blow Out Preventers
CFDH
Corporate Functional Discipline Head
Csg
Casing
COS
Certificate of Services
CT
Coiled Tubing
CTU
Coiled Tubing Unit
CWI
Completion and Well Inetervention
EDMS
Electronic Document Management System
ESD
Emergency Shutdown System
HCl
Hydrochloric Acid
HF
Hydrofluoric Acid
HP
High-Pressure
HSE
Health, Safety and Environment
HUD
Hold Up Depth
L/min
Litres per Minute
LPT
Low Pressure Test
MASP
Maximum Anticipated Surface Pressure
MPWHP
Maximum Potential Wellhead Pressure
N2
Nitrogen
NDT
Non-Destructive testing
OD
Outside Diameter
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PD meter
Positive Displacement Meter
PLT
Production Logging Tool
POH
Pull(ing) Out of Hole
PPE
Personal Protective Equipment
PRV
Pressure Relief Valve
PT
Production Technologist
RIH
Run(ning) In Hole
SCSSSV
Surface Controlled Sub-Surface Safety Valve
SHOC
Safe Handling Of Chemicals
MSDS
Material Safety Data Sheets
SIEP
Shell International Exploration and Production BV
THP
Tubing Head Pressure
TOC
Top of Cement
TR-SCSSSV
Tubing Retrievable Surface Controlled
Safety Valve
UIK
Production Chemist
W/L
Wireline
WHP
Well Head Pressure
WOC
Waiting on Cement
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4.3
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Appendix 3, Related Business Control Documents and References
Table ‎4-2, Related Business Control Documents and References
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
Document
PL-01-17,
PDO Policies

CP-118, Well Integrity Code of Practice
CP-122, Health Safety and Environment Management System Code of
Practice
CP-123, Emergency Response Code of Practice
PR-1065, Emergency Response Documents Part II
PR-1287, Emergency Response Document Part III, Contingency Plan
Volume II, Well Engineering Operations
CP-178, Well Delivery Code of Practice
PR-1444, Well Engineering & Logistics Management Framework
Well Location Custodianship Transfer Form
SP-1213, Well Control
PR-1708, Lifting and Hoisting Procedure Part 1 Framework, Part 2
Inspection, Testing and Certification
PR-1042, General Operational Safety
PR-1045, Hazardous Substances
SP-1220, Concurrent Operations Specification
EP 95-1814 Coiled Tubing Operations (Vol. 4.1)
API RP 16ST, Coiled Tubing Well Control Equipment Systems
API RP 5C7, Recommended Practice for Coiled Tubing Operations in Oil
and Gas Well Services
WS 38.80.31.32-Gen. Revision 1.06, Pressure Control Manual For Drilling,
Completion and Well Intervention Operations
Page 50
PR-1036, Coil Tubing Operations Procedure
Co.
PDO
PDO
PDO
PDO
PDO
PDO
PDO
PDO
API
API
Shell
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Appendix 4, Cement Plug-Back Process
ID
ACTION
A.
PREPARATION
A1.
Lab analysis of cement slurry and spacer recipes
(repeated few days prior to job)
A2.
Job meeting to review:
Job requirements
Well Status (fluid & pressure)
Recipes, etc.
A3.
Prepare job programme in conjunction with the
procedures
A4.
Prepare job execution programme (copy to Senior
Well Testing/Stimulation Engineer for comment)
ACTION PARTY
DELIVERABLE
Production Chemist
Contractor
Approved lab report
Drilling Engineer
Prodn Technologist
Production Chemist
Contractor
Agreed Job Plan
Drilling Engineer
Prodn Technologist
(Production Chemist)
(Contractor)
Specific job programme
PDO Site Supervisor
(Drilling Engineer)
Site job execution
programme
PDO Site Supervisor
All personnel on site
Awareness of job plans to
all personnel involved
Contractor
PDO Site Supervisor
Completed equipment
check list, rig up and
pressure test
Contractor
PDO Site Supervisor
CT Capacity
PDO Site Supervisor
Contractor
Required cement plug
PDO Site Supervisor
Contractor
Complete job report
Drilling Engineer
Updated well diagram
Drilling Engineer
Up-to-date procedures




B.
EXECUTION
B1.
On-site pre-job meeting to discuss:
Programme
Contingency Plan
HSE, etc.
B2
Equipment check, rig up and pressure test
If excess cement required to be circulated out,
dedicated line & choke to be h/u
If high H2S, cascade system to be used
B3
CT flushing and capacity check
B4.
Job execution as per programme and procedures
C.
REPORT
C1.
Report job
C2.
Update well status
C3.
Update procedures, if required






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Appendix 5, Cement Plug Back – Job Programme Template
4.5
DEEP/HP Well Testing and Fraccing - CT Cement Plug
Pre-job checklist
1) Approved recipe for cement slurry and spacers available on site?
2) Job programme from TWG/3 received - any comments ?
3) Coil analysis run and reviewed - any concerns ?
4) Procedures and Limits of job are clear?
All equipment shall be checked onsite on arrival and recorded in standard checklist.
Thorough checks are required when equipment has travelled long distance and/or
rough road conditions.
Pre-job meeting (all personnel on site to attend)
Items to be covered in the meeting:
1) Job programme
2) Roles and responsibilities
3) Contingency plan
4) Any relevant HSE issues
Note:
Job programme to be sent to Senior Well Testing/Stimulation Engineer
prior to execution.
Well Data
Attach up-to-date well status diagram for reference
Well name
?
Down hole equipment
See well diagram
Hole volume
xx m
Fluid in hole
xx kPa/m brine
D/floor - base Xmas tree
xx m
Desired top of cement
Xxxx m bdf
Top existing perfs.
Xxxx m bdf
Bottom existing perfs.
Xxxx m bdf
Bottom of next perfs.
Xxxx m bdf
HUD
Xxxx m bdf
Height of cement column
xx m
Liner capacity
x" liner 0.0xxx m /m
Volume of cement
xx m
CT diameter
: 1.5
CT wall thickness
: 0.175 inch
CT reel length
: x m
CT capacity
: x m
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3
3
3
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Equipment Pressure Testing
1) Install the BOP stack on the Xmas tree; Function test the BOP, close the blind
rams and pressure test the BOP body, wellhead connection and blind rams from
below to their maximum working pressure.
2) Rig up the injector head on to the BOP stack; fill the CT with water and pressure
test the CT and stuffing box quick union to their maximum working pressure
against the swab valve.
3) Close the pipe rams round the CT; open the BOP side outlet and pressure test
the pipe rams from below to their maximum working pressure.
4) Bleed off the pressure in the reel to inflow test the check valve to a differential
pressure of 10,000 kPa (this is working pressure minus 10,000 kPa).
5) Install adjustable choke and bleed off line to mud pit for any cement returns.
Prior to RIH checklist
1) All equipment functioning correctly, flow meters and depth counters are
calibrated and checked for accuracy.
2) Check that proper and adequate size mixer and displacement tanks are to be
used.
3) Check and confirm logbook inspection of CT life.
4) Ensure CT has been drifted and capacity checked.
5) Note wellhead pressures.
6) Hydraulic master valve is locked open.
7) Sufficient pressure on control line to ensure TR-SCSSSV is maintained fully
open.
8) CTU operator to have up to date well sketch for reference.
9) For sour wells, Cascade system is to be hooked up and all personnel briefed on
the system.
Cement slurry and spacers (as per approved recipes)
Cement density
xx kPa/m
Slurry volume
mix batch of x m
Dry cement required
x Tones
Mix water required
xm
Mix water
Volume of water and amount of
additives required.
Spacer
Volume of water and amount of
additives required
3
3
Detail job outline as per the procedures and job programme prepared by
Drilling Engineer and PT.
Note: Report job in Daily operation report. A separate detailed report shall also be sent
covering any failures/recommendations and attaching all job print outs.
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4.6
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Appendix 6; Wellbore cleanout calculation process for loose solid
4.6.1
Deviation is 30 deg or less
This calculation method is only suitable for cleaning out wells with all sections inclined less than
30 deg from the vertical. See separate notes for cleaning wells with deviation greater than 30
deg.
Can reservoir hold a full column of fluid?
It is important that the reservoir can support a full column of fluid. The well operator should
know how much fluid the reservoir can support before the well starts to take losses. If a well
starts to take losses during a cleanout operation it can cause the particles that are meant to be
getting circulated out to fall back down the wellbore potentially sticking the coiled tubing. The
weight of the particles that are being cleaned out by the fluid need to be taken into account to
calculate the actual fluid weight during a wellbore cleanout. More details are given later.
Calculate using commingled fluid with maximum ratio of nitrogen at 30%.
Using commingled fluid can lower the hydrostatic weight of the cleaning fluid. It is often thought
that commingling the fluid with gas improves the cleaning process but this is not usually the
case. Adding gas to a liquid increases the rate at which any solids will fall through the fluid. Any
gains in annular velocity are only achieved as the gas gets closer to the surface and is
expanding. An increase in annular velocity is most often desired in the larger casing annulus but
here the gas is usually still compressed so adds little to the annular velocity. Keeping the
nitrogen ratio below 30% as it returns up the annulus to the surface equipment avoids excess
velocities and erosion. To avoid erosion, fluid velocities should be kept below 35 ft/sec (10.7
m/sec). Increasing the Nitrogen ratio also increases the chance of fluid refluxing in the annulus.
This occurs when the nitrogen rate traveling up the annulus gets so high that it forces the fluid
back down the annulus taking the solids down also.
Calculate using foam with nitrogen ratio between 60% and 95% in the wellbore.
The main advantages of foam are the better solids transport properties and low hydrostatic
pressures that can be achieved. Foams are basically commingled fluids with a higher ratio of
nitrogen. To keep them stable the addition of a foamer is required (such as a surfactant) which
is often added using a foam generator. More details about foams can be found in a separate
section.
Determine the particle settling velocity.
A variety of ways exist to calculate or estimate this but a simple way is often the use of the
following chart based on the equation from the Drilling Practices Manual. It should be noted that
this chart is set up for proppant with a particle SG of 2.65 and a fluid SG of 1. When fluid or
solids vary from this the actual calculation should be done using the equation on the chart. This
is especially true for some of the heavier types of proppant.
For non-Newtonian fluids it is necessary to use apparent viscosity estimated for the given
conditions. Due to the nature of coiled tubing operations, apparent viscosity for a fluid can
usually be based on the viscosity at a shear rate of 511sec-1 (or Fann 35 speed of 300rpm with
R1, B1, F1 setup).
When using gelled fluids be sure to find the viscosity while at the expected downhole
temperature. Elevated temperatures can have a major effect on a gelled fluids viscosity. It is
often difficult to predict the temperature a fluid will reach while getting circulated around a well
so an estimate of the worst case needs to be done. (worst case = higher temperature = lower
viscosity)
After this step the particle settling velocity (or slip velocity) should have been estimated.
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Figure ‎4-1, Particle Settling Velocities
Calculate expected pump pressures, pump rates and therefore achievable annular velocities
with chosen fluid.
For Newtonian fluids (such as water, glycerin, salt water, acids, kerosene, diesel, alcohol and
oil), the pump friction pressures for the pump rates can be calculated using simple charts in the
Coiled Tubing Handbook. For non-Newtonian fluids (such as gels and some drilling muds) and
friction reduced fluids it is more accurate to consult specific fluid data sheets or computer
software such as HalWin™ or Cerberus™. In most cases friction pressure inthe annulus for
coiled tubing operations is negligible but if the coiled tubing
OD is close to the ID of the wellbore tubulars for any significant length then the pressures can
be substantial.
Once a maximum pump rate has been estimated the annular velocity can be estimated from the
following formula.
Equation ‎4-1, Annular Velocity
where IDprod.is the ID of the production casing and ODcoil is the OD of the coil tubing, both
measured in inches.
Can annular velocities above particle settling velocities be reached?
Compare the slowest annular velocity calculated from Step 6 and compare to the fastest particle
settling velocity (slip velocity) from Step 5. If annular velocities above particle settling velocities
can be reached then it should be possible to clean out the wellbore. The time taken to clean out
the wellbore is dependant on the particles net rise up the wellbore. To determine the cleanout
time in later steps the particles net rise can be calculated as follows.
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Equation ‎4-2, Net Rise
In situations where the annular velocities are high enough to reach the speeds shown below this
will usually be sufficient to easily lift most solids up the wellbore.
Add Friction Reducer to base fluid, increase viscosity of base fluid and / or use larger coiled
tubing.
The addition of friction reducing chemicals to base fluids can significantly reduce the amount of
pump pressure required to pump the fluid and can therefore increase the annular velocities that
can be achieved. Also, by reducing the pump pressures they allow us to pump faster and
therefore decrease the time it takes to carry out the operation. Different friction reducers are
available to suit different fluids and environments.
Gelling the base fluid to increase it’s viscosity will decrease the velocity that a particle will settle
meaning that the annular velocity can be decreased while still lifting the solids up the annulus.
Special attention should be made to the well temperature as this can have a drastic effect on
gels. Gel stabilizers may need to be used.
Using larger coiled tubing allows increased pump rates and also decreases the size of the
annulus around the coiled tubing thus increasing fluid velocities.
Using larger coiled tubing may not always be possible due to various operational constraints
such as downhole restrictions or surface equipment capabilities.
Calculate or specify the maximum allowable hydrostatic loading the reservoir can hold due to
sand loading.
When using commingled fluids the calculations should be based on liquid volumes only.
The equivalent circulating density (ECD) at the reservoir will change throughout a cleanout
operation and is dependant mainly on fluid weight, friction pressure in the annulus and wellhead
pressure. It is important to keep the ECD below the level at which the reservoir starts to take
fluid losses or else the solids being cleaned out may start falling back down the wellbore and
bridge around the coiled tubing causing it to become stuck. The wellhead pressure is easily
determined and changed by looking at the gauge and adjusting a choke if necessary. The
annulus friction pressure is usually negligible for coiled tubing operations but should be
considered if the coiled tubing OD is close to the wellbore ID.
The main factor needed to calculate the ECD is the fluid weight. The fluid weight increases as it
picks up solids and begins to circulate them out so it is important to regulate the cleaning speed
to ensure the fluid weight does not become to great.
Before the operation try to determine the maximum allowable fluid weight based on the past
history of the well or similar wells to give an idea when the well will start to take losses. Allow an
additional safety factor of at least 500psi and never exceed the wells fracture gradient.
If unsure about anything with the job design try to plan for a fluid loading of 1ppg. This means
that using an 8.33ppg cleanout fluid the sand laden fluid will be 9.33ppg. If well information and
experience levels are both good the amount of sand loading can be increased accordingly to
perhaps 3ppg to speed up job times. The fluid loading can also be changed throughout the job if
necessary, for instance if a well has been fracced and the proppant has screened out (well is
full of proppant) it may be beneficial to clean the well with a fluid loading as high as 5ppg but
decrease this down to 1ppg when approaching the top of the reservoir or the bottom of the
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production tubing. This depth will change depending on the properties of the sand being
cleaned and should be evaluated in each instance.
With foams the fluid loading should be kept below 1.5ppg to avoid interfering with the foam
quality.
Calculating the fluid loading is best demonstrated with an example.
Consider 7” 24# Casing (ID=6.336”) filled with 20/40 Ottowa Proppant.
From Tables:
Casing Volume = 1.638 gal / ft
Proppant SG=2.65 and Bulk Density = 100 lb/ft3 = 13.37 ppg and 40% porosity. (These are also
good numbers to use if the actual sand or proppant data is unknown)
If porosity = 40% then 40% of volume is well fluid, lets assume freshwater.
Density of Settled Sand = 13.37 + (8.33 x 0.4) = 16.7 ppg
If we RIH into the sand @10 ft/min while pumping at 42 gpm what will the new Dirty Fluid
Weight be?
Over a one minute interval, as we RIH into the sand we are mixing 42gal clean fluid with 10ft of
casing volume (16.38 gal) of existing settled sand.
= (Clean Fluid Weight×pumprate) + (Settled Sand&Fluid Density×CasingVolume×RIHspeed) /
PumpRate + (CasingVolume×RIHspeed)
= (8.33 × 42) + (16.7x1.638×10)/42 + (1.638×10)
Where:
Fluid Weights in ppg
Pump rate in gpm
Casing Volume in gal / ft
RIH speed in ft / min
New Dirty Fluid Weight = 10.68 ppg
Therefore fluid loading is 10.68 – 8.33 = 2.35ppg
Once the new fluid weight is know it is a straightforward calculation to determine the hydrostatic
pressure at the reservoir due to this fluid weight.
Calculate the CT travel rate for a given flow rate to ensure the fluid loading is kept low enough.
When using commingled fluids or foams the calculations should be based on liquid volumes
only.
From Step 9 the desired fluid weight should now be known. From this the clean rate can now be
calculated as follows:
Clean Rate to obtain the desired fluid weight = Pump Rate ×[Clean Fluid Weight -Reqd. Fluid
Weight] / Csg Vol ×[Reqd. Fluid Wt -Dirty Fluid Weight]
Where:





Fluid Weights in ppg
Csg. Volume in gal/ft
Dirty Fluid Weight = Settled Sand and Liquid weight to be cleaned out.
Clean Fluid = Fluid being pumped through CT
Clean Rate in ft/min
Calculate the cleanout time based on clean rate, annular velocity and particle net rise velocity.
The total cleanout time is basically: Time to clean down thru required length of wellbore (Based
on clean rate) + Sand Cleanout Time
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(Based on particle net rise velocity at specific pump rate after the CT reaches TD)
When POOH while circulating, ensure CT displacement is taken into account with fluid flowrate
and annular velocity calculations.
Make sure to pull out of hole slower than the particle net rise velocity.
When calculating annular velocities while POOH remember to subtract fluid volumes required to
fill the space left from the CT. These calculations should be based on the external displacement
of the coiled tubing. (While pulling the CT out of the well we are also pulling the fluid inside the
coiled tubing out of the well and back onto the reel).
For Example:
With 2” OD CT inside 4.5” 12.6# tubing the annular volume is 476 gal/1000ft. The external
displacement of 2” CT is 0.163 gal/ft.
If we POOH at 100 ft/min what effect does this have on the annular velocity while pumping at
84gpm ?
The annular velocity while the CT is stationery is 176.5 ft/min
If we POOH at 100 ft/min it takes 100 x 0.163 = 16.3 gpm to fill the CT displacement.
Therefore, the actual fluid rate in the annulus becomes 84 – 16.3 = 67.7 gpm
This gives an annular velocity of 142.2 ft/min while the pipe is being pulled out of hole.
To calculate the maximum POOH speed to ensure the BHA is always behind the sand being
cleaned out, use the following equation:
Equation ‎4-3, Max. POOH Speed
Where:



4.6.2
Particle Net Rise Velocity in ft/min
CT External Displacement in gal/ft
Annular Capacity in gal/ft.
Deviated Wells
Solids are always being pulled downward by gravity. When a hole is deviated or horizontal, the
particulates tend to lie or wedge into the low side of the hole.
When the hole is deviated by more than 35 degrees, then the mechanism of movement upward
is changed to a rolling, sand-dunning movement. The wash fluids will tend to pass over the top
of the particulates. Water in turbulence works best in this situation but friction pressures are
often too high to allow reaching the necessary annular velocity. Foams will usually work the
best. Gel-laden fluids keep the fluid in laminar flow and do not generate enough energy to clean
the sand out of the triangulated area. Gel fluids become the least successful means in this
scenario
Centralization in the horizontal section can greatly improve cleanout efficiencies.
If cleaning the wellbore with straight fluids, aim to have an annular velocity of 10 times the
particle settling velocity.
If cleaning the wellbore using a foam, aim to have a foam quality along the complete deviated
section between 70-80%. This is when foam has the best carrying capacity.
Page 58
PR-1036, Coil Tubing Operations Procedure
Printed 13/06/16
The controlled version of this CMF Document resides online in Livelink®. Printed copies are UNCONTROLLED.
Revision: 3.0
Effective: June 2016
Petroleum Development Oman LLC
Considerations when doing cleanout jobs:
1) RIH with the coiled tubing and circulate one complete coiled tubing and annulus volume of
the cleanout fluid before reaching the expected start of cleanout depth. This ensures that
pressures have stabilized to allow better monitoring of the operation.
2) Continue down at the calculated cleanout rate. Take extreme caution when uncovering any
perforations.
3) Carefully monitor the pump and wellhead pressures to see changes due to heavier solids
laden fluids being circulated up the annulus.
4) Monitor flow returns at all times, if returns slow down or stop start to POOH immediately
while continuing to circulate.
5) When the final desired depth is reached, start POOH slowly at a rate calculated to be
slower than the upward speed of the largest expected particles. Circulating without moving
for long periods should be avoided to prevent erosion of the coiled tubing at surface and in
any downhole restrictions.
6) Pull the coiled tubing out of the hole while maintaining circulation. DO NOT shut the pumps
down for any reason, unless you are out of the hole. If at any time the flow line develops
leaks or washes out, shut in the flowline and immediately pull the coiled tubing out of the
well. After the repairs to the flowline have been made, reestablish circulation before
stopping pulling out and running back in.
Printed 13/06/2016
PR-1036, Coil Tubing Operations Procedure
Page 59
The controlled version of this CMF Document resides online in Livelink®. Printed copies are UNCONTROLLED.