COILED TUBING SERVICES MANUAL

Rev A - 98

COILED TUBING SERVICES MANUAL

The lists of equipment, techniques and applications associated with modern coiled tubing operations continue to grow at
a remarkable rate. To prepare a document which details all aspects of the technology to an appropriate “operations support”
level would be a difficult and possibly never ending task. This manual has been prepared to meet the following objectives
and qualifiers.

This manual is intended to:

• Present readers with a sound but basic understanding of the equipment, techniques and common applications
associated with modern coiled tubing operations.

• Identify the key areas in which an advanced understanding is necessary before undertaking the design, supervision
or execution of coiled tubing operations.

• Provide guidance on further reading or reference sources.

This manual does not:

• Provide sufficient detail to enable inexperienced or untrained personnel to undertake any aspect of CT operations.

• Make recommendations for the rig up, testing or operation of equipment or techniques which should be configured
and operated under the conditions and requirements of a specific operation, application or location.

This manual has been designed and published to fulfil the needs of the user. We would appreciate your assistance in
identifying ways in which the manual structure or content could be adapted or improved to increase its value to you.

Page i
 COILED TUBING SERVICES MANUAL
Rev A - 98 TABLE OF CONTENTS

Section Title & Content Page Count

Introduction to Coiled Tubing............................................................................................. 15

100 Coiled Tubing String

110 Coiled Tubing Manufacture ............................................................................................... 14

Material Specifications
String Configuration

120 Managing Coiled Tubing Life............................................................................................. 15

Tubing Fatigue
Tubing Corrosion
Tracking Tubing Life
Protective Coatings
CT String Records

130 CT String Maintenance...................................................................................................... 8

CT String Inspection
Damage and Defect Classification
CT String Repair
Welding Procedures
Alternative Repair Methods
Repair Inspection
CT String Handling and Storage

200 Coiled Tubing Equipment

210 Coiled Tubing Unit ............................................................................................................. 33

Injector Head
Tubing Reel
Power Pack
Control Cabin

220 Pressure Control Equipment ............................................................................................ 33

Stripper Systems
Conventional Stripper
Side-Door Stripper
Radial Stripper
Blowout Preventers
Quad and Combi BOPs
Shear/Seal BOPs
Annular Preventers
Wellhead Connections and Crossovers
Lubricators and Risers

225 Live-well Deployment Systems.......................................................................................... 18

Lubricator Deployment
Tool Deployment System
SAFE Deployment System
Oiled Tubing Conveyed TCPS

230 Auxiliary Surface Equipment ............................................................................................ 11

Coiled Tubing Lifting Frames
Coiled Tubing Jacking Frames
Cranes

Page ii
 COILED TUBING SERVICES MANUAL
TABLE OF CONTENTS Rev A - 98

Section Title & Content Page Count

240 Downhole Tools................................................................................................................ 9

Threads and Materials
Coiled Tubing Connectors
Hydraulic Release Connectors
Accelerators
Jars
Overshots
Spears
Depth Control

245 High Pressure Jetting System ........................................................................................... 6

Jet Blaster
Bead Blaster
Bridge Blaster

247 Multi – Lateral Well Access ............................................................................................... 4

Discovery-MLT

300 Coiled Tubing Applications

310 Design Methodology ......................................................................................................... 7

Job Design Data
Computer Aided Design
Tubing Forces
Fatigue Tracking
Operating Limits
Wellbore Simulator
Friction Pressure
Foam Cleanout
Operating Procedures

320 Wellbore Maintenance....................................................................................................... 33

Fluid Circulation and Well Kill
Wellbore Fill Removal
Scale and Asphalt Removal
Well Kickoff

330 Matrix Treatment ............................................................................................................... 12

Matrix Stimulation

340 Zonal Isolation ................................................................................................................... 17

Squeeze Cementing

350 Stiffline ............................................................................................................................ 27

Downhole Flow Control
Fishing With Coiled Tubing

360 Coiled Tubing Logging .......................................................................................................... 15

370 Coiled Tubing Completions .................................................................................................... 14

380 Coiled Tubing Drilling ............................................................................................................ 50

390 Hydraulic Fracturing .............................................................................................................. 6

Page iii
 COILED TUBING SERVICES MANUAL
Rev A - 98 TABLE OF CONTENTS

Section
Section Title
Title &
& Content
Content Page Count
Page Count

400
400 Safety & Contingency
Safety and Contingency
410 Safety Considerations ....................................................................................................... 9
H2S
Breathing Apparatus
Monitoring Equipment
Fall Protection Devices

420 Contingency Planning ....................................................................................................... 10

Emergency Response
Contingency Plans

Page iv
 COILED TUBING SERVICES MANUAL

INTRODUCTION

Coiled tubing (CT) has become a widely accepted and routinely prescribed tool for well service and work-over operations
in many areas of the world. What was originally developed in the early 1960’s as a means of entering live wells for the purpose
of removing sand bridges has evolved into a multi-faceted technology. The traditional CT well intervention, or workover
applications, still account for over three-quarters of CT work, however, the use of CT technology for completion and drilling
applications is rapidly becoming technically feasible and economically viable.

This extension of CT technology from well-intervention to drilling and completion applications has been achieved within a
relatively short time, largely due to the close cooperation of oil companies, CT service companies, and equipment
manufacturers in developing innovative tools and techniques, and in improving the performance and reliability of the CT
equipment.

The intent of this manual is to provide the reader with an overview of CT services development and a basic understanding
of a technology that is continuing to expand and evolve into a critical part of the oilfield. Within this introduction section
reference has been made to key elements, companies, and circumstances that have played a key role in the development
of CT equipment and services. In this, every effort has been made to provide information that is current and accurate.

Rev A - 98 Page 1 of 15
 COILED TUBING SERVICES MANUAL
INTRODUCTION

Basics of Coiled Tubing contra-rotating chains, a design that is still used by the
majority of CT units today. The stripper was a simple,
Perhaps the major driving force behind the origination of CT annular-type sealing device that could be hydraulically
as a basic concept was an understandable desire to activated to seal around the tubing at relatively low well-
perform remedial work on a live well. In order to do this, head pressures.
three key elements would have been required:
The tubing string used for this early model was fabricated
• A continuous conduit which can be inserted into the by butt-welding 50 ft sections of 1-3/8-in. OD pipe into a
wellbore (CT string). 15,000 ft string and spooling onto a reel with a 9 ft diameter
core.
• A means of running and retrieving the string into the
wellbore under pressure (injector head). Although this was the first operational CT unit, it was based
on concepts and ideas that had been previously developed
• A device capable of providing a dynamic seal around the for other purposes as early as 1944.
tubing string (stripper).
Prior to the Allied invasion of Europe in 1944, engineers
Coiled tubing technology is based on the use of a continu- developed and produced very long, continuous pipelines for
ous, flexible steel tube (the CT string) which is coiled on a transporting fuel from England to the European Continent to
reel for transport and storage. The surface end of the CT supply the Allied armies.
string is connected to a high-pressure swivel joint on the
reel hub to enable fluids to be pumped through the string - PLUTO was an acronym for “Pipe Lines Under The Ocean”,
continuously if so desired. and the effort involved the fabrication and laying of several
pipelines across the English Channel. A total of 23 lines
The CT string is run into and retrieved from the wellbore by were laid; 17 were made from lead pipe and 6 from steel
the injector head which combines several hydraulically pipe. The steel lines were fabricated by butt-welding 20 ft
operated functions to enable the coiled tubing unit (CTU) joints of 3-in. ID pipe into 4,000 ft. sections. These
operator a high degree of control over the position and intermediate lengths were then welded and spooling onto
movement of the CT string. floating drums that were 70 ft. wide and 40 ft. in diameter.

A stripper assembly mounted below the injector head The pipelines, approximately 70 miles in total length, were
provides a dynamic seal around the tubing string enabling laid by towing the drums across the channel while the
the tubing to be run and retrieved on live wells. Secondary pipeline unspooled.
and contingency pressure control functions are provided by
a blowout preventer (BOP) assembly mounted between the The successful fabrication and spooling of continuous
stripper and the wellhead. flexible pipeline, laid the foundation for further develop-
ments that eventually lead to downhole tubing strings used
The CTU is operated from the control cabin which is in modern CT.
designed as a single point control and monitoring station for
the primary functions of the CTU and associated equipment Steps leading to the 1962 Bowen unit included:
spread.
• In the late 1940’s, several concepts relating to the
Origin of Coiled Tubing injection of continuous tubing or cable into a live wellbore
were patented.
It is generally agreed that the first practical, fully functioning
CT unit was developed by the California Oil Company and • In the early 1950’s, several concepts relating to drilling
Bowen Tools in 1962 for the purpose of washing out sand with continuous, flexible strings were patented.
bridges in wells along the U.S. Gulf Coast.
• In the early 1960’s, a device was developed by Bowen
The injector head operated on the principle of two vertical, Tools for use in antenna-deployment aboard submerged

Page 2 of 15 Rev A - 98
 COILED TUBING SERVICES MANUAL
INTRODUCTION

Prefabricated tubing lengths Commencing spooling

Spooling the pipeline Laying the pipeline

Figure 1. Operation PLUTO - "the birth of coiled tubing ?"

submarines. The antenna, a 5/8-in. brass tube, was Following the success of the Bowen Tool, California Oil
spooled onto a reel for storage and was capable of Company efforts, in 1964, Brown Oil Tools and Esso
reaching the surface from a submerged depth of 600 ft. collaborated to develop a system that utilized a slightly
This system used the same principle of the contra- different principle for the injector design. Instead of a set of
rotating chain drive that would be later adopted for CT contra-rotating chains to grip and drive the tubing, the
injectors. tubing was squeezed between a single chain and a grooved
drive wheel. The entire unit was mounted in a portable,
• In 1962, Bowen adapted the injector design used on the hydraulic mast that suspended the CT unit above the
antenna deployment for the prototype that was developed wellhead.
with the California Oil Company.

Rev A - 98 Page 3 of 15
 COILED TUBING SERVICES MANUAL
INTRODUCTION

Figure 2. Brown injector head circa 1964.

A variation of this design exists today as alternative to the accommodate tubing up to 1-in CT. By the mid-1970’s, over
widely-used contra-chain systems. The Brown Oil Tool unit 200 of the original-design CT units were in service.
was designed for 3/4-in tubing and was successfully used
for wellbore cleanouts, on onshore and offshore wells. In the late 1970’s, the evolution of injector design was
influenced by several new equipment manufacturing com-
In both the Bowen and Brown Oil Tools developments, the panies (Uni-Flex Inc., Otis Engineering, and Hydra Rig
CT units were developed for specific clients and were one- Inc.). In general, these companies based their units on the
of-a-kind prototypes. However, the success of these proto- original Bowen Tools contra-chain design, however Uni-
types soon generated a commercial interest in CT as a Flex Inc., improved the design significantly. Although Uni-
service to be provided on a call-out basis for oil companies. Flex stopped production of its units around 1978, many of
its design concepts have been incorporated into the equip-
In 1967, NOWSCO first provided CT services to several ment of modern manufacturers.
clients who did not want to develop or purchase their own
units. Nowsco began by leasing a modified version of the At about the same time Uni-Flex ceased manufacturing CT
original Bowen Tools design (for 1/2-in. tubing) for nitrogen equipment, Brown Oil Tools also ceased manufacturing the
injection services. As a result of increased demand for CT drive-wheel model. However, a variation of this design was
services, NOWSCO ordered 12 similar units from Bowen re-introduced in 1985. This unit retains the drive-wheel
Tools. This marked the beginning of the CT service concept, but used rollers, instead of chain, to force the
industry. tubing against the drive wheel (providing traction).

Improvement and Evolution of Coiled Tubing Evolution Of The Continuous String Tubing

Throughout the remainder of the 1960’s and into the 1970’s, Throughout the period when injector heads were being
both Bowen Tools and Brown Oil Tools continued to improved, the tubing string was also undergoing some
improve, modify, and enhance their respective designs to significant development.

Page 4 of 15 Rev A - 98
 COILED TUBING SERVICES MANUAL
INTRODUCTION

The Bowen Tools prototype of 1962 used 1-3/8-in. tubing, Early tubing manufacture used techniques developed dur-
however, the models produced commercially for NOWSCO ing the PLUTO project and involved butt-welding 50 ft.
used 1/2-in. tubing. By the early 1970’s, the tubing size was sections of milled tubing into a continuous length for
increased to accommodate 1-in. tubing. spooling onto a reel. This meant that there was a butt weld
every 50 ft throughout the tubing string.
The Brown Oil Tools prototype of 1964 used 3/4-in. tubing,
but was modified by 1967 to handle 1-in. tubing. By the late 1960’s, techniques had been developed to allow
tubing strings to be milled in much longer lengths. This
In summary, the early commercial period of CT services, decrease in the number of welds throughout the string was
during the late 1960’s and early 1970’s, was dominated by accompanied by an improvement of the steel properties.
tubing sizes up to 1-in. and relatively short string lengths. The resulting improvement in string reliability significantly
The tubing diameter and length was limited by the mechani- benefited CT services (Figure 3).
cal properties of the tubing material and the manufacturing
techniques of that era. In 1969, the quality of the tubing was further improved when
Southwestern Pipe Inc. began manufacturing CT using
Early CT operations were plagued by string failures due to improved material and techniques. Another company,
the inconsistent quality of the tubing strings. A major part Quality Tubing Inc., started manufacturing tubing in 1976
of the problem related to the many butt-welds in the tubing using a process similar to Southwestern Pipe. At that time
string, necessitated by manufacturing limitations. Quality manufactured exclusively for a single CT service
company. However, by 1982, Quality Tubing provided CT

1941 Operation PLUTO - 30 ft lengths

1965 250 ft strip lengths (Republic Tubing, USA)

1983 1000 ft strip lengths

1985 1700 ft strip lengths

1986 3500 ft strip lengths (Japanese Suppliers)

1987 Tubing milled continuously

Figure 3. CT string construction.

Rev A - 98 Page 5 of 15
 COILED TUBING SERVICES MANUAL
INTRODUCTION

CT string and Control cabin

reel and power pack

Injector head
Layer1 HighExhaus t LowOi l Lo
ssof
H igh
Tem per
Ca
ool
tu
rate
n Temperatur e Pressure Coo
l an
t

Pr O
i ur
le
Cper
Tm
e oola
attnure es
s

Eng
i ne
Tcho
a me t er
Per mistrsive
sta

St rat
Engi
Kilne Em Ki
relge
lncy Ai
Pr s
r e
esur

Strippper

Quad BOP

Fluid handling
and pumping
equipment

Nitrogen handling
and pumping
equipment

Electric power to
the toolstring

Electronic data
Tool string
from the
toolstring

Figure 4. CT operations - principal equipment components.

Page 6 of 15 Rev A - 98
 COILED TUBING SERVICES MANUAL
INTRODUCTION

strings to the general CT industry, and with Southwestern Coiled Tubing Today
Pipe, dominated this market. The techniques used, at that
time, allowed for the manufacture of 1-1/4-in. CT in continu- As the complexity of CT equipment and services has
ously milled lengths of 1,500 ft. increased it has become more difficult to briefly summa-
rize the advantages of applying CT technology. Speed and
During the 1980’s, CT materials and strings improved economy were early drivers or incentives for the use of CT
significantly and still remain a key feature. The relatively small unit size
and short rig-up times compare favorably with those of
• 1980 - Introduction by Southwestern Pipe of 70 ksi yield conventional workover units . However, many other techni-
steel for milling tubing cal advantages can now be applied, depending on the
specific wellbore, reservoir and location conditions.
• 1983 - Introduction by Quality Tubing of continuously-
milled tubing lengths of 3,000 ft. Commonly cited advantages over conventional workover
methods, e.g., a workover rig, include:
• 1987 - Development by Quality Tubing of “bias-welding”
the sheets of steel prior to milling to provide a stronger, • Safe and efficient live well intervention
milled tubing.
• Capability for rapid mobilization, rig-up and well site
Over this period of development, the maximum practical preparation
CT size was increased, first to 1-1/2-in. and subsequently
to 1-3/4-in. By 1990, the first 2-in. tubing was being • Ability to circulate while RIH/POH
produced, followed shortly by 2-3/8-in., 2-7/8-in., and 3-1/
2-in. • Reduced trip time (RIH, POOH) and production downtime

Today, 2-3/8-in. tubing is generally considered the largest • Lower environmental impact and risk
practical size CT well service work. The larger sizes are
more commonly used in CT completion applications, • Reduced crew/personnel requirements
where cycling, and the resulting fatigue is not a major issue.
• Lower cost with greater flexibility
CT Drilling
Similarly, it is becoming more difficult to summarize the
Although a more detailed history of coiled tubing drilling is growing list of applications for which CT can be considered.
given in the Coiled Tubing Drilling Manual, reference should Early applications were designed around the fluid circulat-
be made to influence given to the general evolution and ing/placement capabilities of the CT string, while more
development of CT technology. recent applications can rely on several unique features of
the CT string and associated equipment.
The initial concept of using a continuous drill string dates
from the late 1940’s. However, it was not until 1964 that the The majority of current CT applications are enabled by one
concepts were actually employed. In similar, but indepen- or more of the following unique features.
dent efforts, the French Petroleum Institute and the Cullen
Research Institute developed working prototypes of con- • Live well operations - CT pressure control equipment
tinuous drilling systems. In 1976, the Canadian company enables the functions listed below to be safely applied
FlexTube Services Ltd., developed and commercial oper- under live well conditions.
ated a continuous drilling system for several years.
• High pressure conduit - CT string provides a high pressure
The modern CT drilling era began in 1991 and has rapidly conduit for fluid circulation into, or out of the wellbore. In
progressed providing the major driving force behind the addition, hydraulically operated tools may be operated or
development of the 2-in. and 2 3/8-in. CT sizes. powered by fluid pumped through the string.

Rev A - 98 Page 7 of 15
 COILED TUBING SERVICES MANUAL
INTRODUCTION

Determine
treatment Acquire job design data
objectives (i) Reservoir
(ii) Wellbore
(iii) Wellsite/location

Select treatment Select equipment

(i) Fluids (i) CT equipment
(ii) Tools (ii) Pressure control equipment
(iii) Special equipment

Prepare plans and procedures Perform treatment

(i) Normal operating procedures
(ii) Emergency responses
(iii)Contingency plans Evaluate treatment

Figure 5. CT operations - principal job designand execution elements.

• Continuous circulation - fluids may be pumped continu- widely varying conditions, using a range equipment of
ously while the CT string is run and retrieved. differing capacity and capability. As a result, there is no
standard equipment configuration which is applicable to all
• Rigidity and strength - the rigidity and strength of the CT conditions. However, there are principal equipment compo-
string enables tools and devices (and the string itself) to nents used on each operation that are generally considered
be pushed and pulled through highly deviated and hori- to be common to all applications. The illustration in Figure
zontal wellbore sections. x identifies the principal equipment components typically
required to complete safe and efficient CT operations.
• Installed conductors and conduits - electrical conductors
or hydraulic conduits may be installed in the CT string, The variety of applications, equipment configurations and
and terminated at the CT reel. This enables additional operating conditions means there is no standard job plan-
control and power functions to be established between ning and design process. However, there are job design and
the BHA and surface facilities. planning elements which should be applied to each opera-
tion. The illustration in Figure 5 identifies the principal job
The ability to easily adapt equipment, tools and techniques design and execution elements that should typically be
for specific purposes is a significant advantage of CT considered for all CT operations.
technology. This flexibility combined with specific location
or local requirements, has resulted in regional "hot spots" The components and elements identified above provide the
of activity and development. In such areas, CT technology basis for the content and structure of this manual which is
is not only accepted but is supported by often pioneering compiled in four distinct sections and supported by supple-
work in equipment or technique development, e.g., zonal mentary information in appendices.
isolation and coiled tubing drilling (CTD) in Alaska.
• CT String
Modern coiled tubing equipment is now commonly used to
perform a variety of applications on wellsites or locations of • CT Equipment

Page 8 of 15 Rev A - 98
 COILED TUBING SERVICES MANUAL
INTRODUCTION

Operation PLUTO
1943 3.35 in. x 20 ft butt
welded into 4000 ft lengths
First downhole CT
1.315 in. x 50 ft butt 1962
-welded to length
First continuous
1964 CT (1/2 in. & 3/4 in.
x 2000 ft lengths)

1 in. CT 1970
Canadian string
1976 using 2.3/8 in.
X-42 pipe
Canadian string
using 2-3/8 in. 1977
aluminium tubing

1978 1-1/4 in. CT

70 ksi yield
material 1980
CT string
1983 manufactured
in 3000 ft lengths

1-1/2 in. CT 1986

1988 1-3/4 in. CT

Continuous string
using bias weld 1989

1990 2 in. CT

2-3/8 in.
& 2-7/8 in. CT
1990
3-1/2 in. CT
1992 pre-installed
gas lift strings
Hydraulic conduit
installed 1993
(control string)
CT sizes
1995 manufactured
in 80 ksi yield

4-1/2 in. (flowline) 1995

Figure 6. CT string material and product developemnt.

Rev A - 98 Page 9 of 15
 COILED TUBING SERVICES MANUAL
INTRODUCTION

• CT Applications Despite the considerable technical advances in modern CT

string chemistry and design, a CT string should still be
• Safety and Contingency Planning regarded as a consumable product, which has a limited
safe working life. Many demands are made upon CT strings
• Appendices so reliability and predictable performance are critical quali-
ties if operations are to be completed confidently within the
Many technical papers, magazine articles and similar safe operating envelope of the string. Since many desired
reference sources have been used in the preparation of this string properties are contradictory in effect, the require-
manual. The publication of case histories and actual ments of a CT string are typically determined as a compro-
experiences are acknowledged as providing valuable con- mise of specifications relating to material chemistry (met-
tribution to the general furtherance and acceptance of CT allurgy) and the material physical properties. For example,
technology. a material having high corrosion resistance may have low
fatigue resistance.
1 CT STRING
The reliability of modern CT services is assured through
Most coiled tubing strings are constructed from high- application of a comprehensive string management sys-
strength low alloy steels which are formed into high speci- tem throughout the life of the string. This is based on a
fication tubing with the desired chemical, physical and thorough understanding of the parameters influencing string
geometrical properties. Under development are compos- performance, and the implementation of procedures de-
ite-material, special alloy, and fiberglass tubing. Improving signed to control or monitor resulting effects. For example,
the reliability of CT strings was generally regarded as the fatigue and corrosion can significantly reduce the safe
prerequisite necessary for the acceptance of CT services working life and reliability (predictability) of a CT string. By
as a viable well servicing option. Manufacturing processes tracking the parameters influencing these mechanisms an
and quality control/assurance systems can now deliver a efficient string management system does not necessarily
consistent product with a predicable performance and the prevent fatigue or corrosion, but provides a reliable means
manufacturing process is adaptable to the extent that CT of accounting for the effects, thereby ensuring continued
work strings are commonly designed to the individual reliability of string and service.
requirements of the customer (typically the CT service
vendor). Further explanation of this development process and fac-
tors effecting the design and operation of modern CT
Coiled tubing, or pipeline was first developed during World strings are contained in Section 100 of this manual.
War II as a means of supplying fuel to the invasion forces
following the Normandy landings. The PLUTO (Pipe Line 2 CT EQUIPMENT
Under The Ocean) project investigated the feasibility of
coiling 3-in. pipeline onto to massive floating spools were At first glance, much of today’s CT equipment bears great
designed to lay the pipeline as they were towed across the similarity to the early equipment designs of the 1960s.
English Channel. In excess of 20 pipelines were subse- However, over this period the "weak areas" have been
quently laid providing the allied forces with fuel to sustain improved and as factors or parameters influencing service
the liberation of occupied Europe (Figure 3). quality became known or better understood, equipment
modifications and reworked designs were implemented. As
While the chemistry, physical properties and construction with most well servicing industries, there has been a
of modern coiled tubing is significantly different form that preference for generic or "standard" coiled tubing unit (CTU)
fabricated for the PLUTO project, many of the issues and designs which enable a higher degree of flexibility in
concerns identified then are equally valid now. For example application and wellsite conditions. With the increased
the inherent weakness associated with butt welding tubes global CT market and the wider acceptance of specialized
and the resulting influence on fatigue were identified during services such as coiled tubing drilling, the use of custom
this early work. designed equipment is becoming more common.

Page 10 of 15 Rev A - 98
 COILED TUBING SERVICES MANUAL
INTRODUCTION

Operation
1944 PLUTO

Early live
cable injection 1948-51
Bowen system
1961 used on
submarine
Contra rotating
chain drive system
1962
Brown & Esso
1964 use 3/4 in. wheel
injector
Bowen 5M
& 8M CTU
1967-78
Hydra-Rig,
1975-76 Otis & Uniflex
CTU Introduced
Brown & Uniflex
cease to 1978
manufacture
Development
1985 of wheel
injector head
Combi BOP
Introduced 1988
Side door
1990 stripper
introduced
5000 &
10000 psi Quad 1991
BOPs
40,60 & 80K
1990-93 injector heads
introduced
Live well
deployment 1993
systems
Automatic stab
1994 BHA deployment

Figure 7. CT equipment development.

Rev A - 98 Page 11 of 15
 COILED TUBING SERVICES MANUAL
INTRODUCTION

Operation
1944 PLUTO
Wellbore fill
removal and fishing 1962
inside tubing
Test drilling
1964 with CT

Acidizing 1968
First commercial
1976 CT drilling
1500 ft gas wells

CT logging 1985

CT completion
1988 velocity string
Real-time
bottomhole 1990
monitoring
Resumption of
1991 commercial
CTD
CT completion
gas lift string 1992

Figure 8. CT application evolution.

Page 12 of 15 Rev A - 98
 COILED TUBING SERVICES MANUAL
INTRODUCTION

The basic functions required of CT equipment largely One of the most visible developments influencing the
remain as they did in the early days of CT services, e.g., design and operation of CT equipment is the introduction of
run-in, pull-out, maintain well security. However, the condi- software modeling, monitoring and recording equipment.
tions under which these are now to be achieved can be Sophisticated computer models can accurately predict the
considerably different. Modern CT strings are typically, forces exerted on the CT string for any given wellbore and
larger (OD), heavier and longer. They are run and retrieved treatment conditions. In addition, the behavior of treatment
from wells which are deeper, hotter and have higher and wellbore fluids can be modeled. This combined with the
wellhead pressure. In addition, the wellbore can be devi- ability to use powerful wellsite computers to monitor oper-
ated, horizontal or, in some cases, fearsome combinations ating parameters assists CTU operators to complete the
of both. operation while fully understanding the implications of their
actions.
Many modern applications have very close depth toler-
ances and can require the application of highly controlled Significant developments in the evolution of modern CT
force downhole. Also, tools and downhole equipment pro- equipment are shown in Figure 7. Further explanation of this
viding data for real-time analysis are now routinely used. development process and factors effecting the selection
and operation of CT equipment are contained in Section 200
Each of the factors above have been addressed by equip- of this manual.
ment designers and manufacturers. The result is efficient
but complex CT equipment spreads which require operator
skill and competency far beyond that which has historically
been considered adequate for safe CTU operation.

Equipment

Personnel

Environment

Well Security

Figure 9. CT operation safety and contingency planning factors.

Rev A - 98 Page 13 of 15
 COILED TUBING SERVICES MANUAL
INTRODUCTION

3 CT APPLICATIONS The value of adequate and accurate job design data has
been realized, as have the benefits of comprehensive and
An important aspect of CT operations that is often over- documented operating procedures which typically also
looked is that CT simply provides a means of conveyance include a means of verifying that equipment and personnel
for fluids, tools or equipment required to complete the are prepared and capable of completing the operation as
desired treatment. Only by successfully combining such intended. With the increased demands being made of CTU
fluids and tools with well executed CT services can CT operators it is becoming increasingly important that person-
applications be successfully completed. Consequently, nel are fully trained, and verified as competent, for the tasks
most CT applications are undertaken through the collabo- to be undertaken. While this rationale has its roots in safety
rative effort of two or more service company "disciplines", and pressure control issues, the complexity of modern CT
departments or organizations. In such circumstances, operations and the implications of wellsite incidents often
good communication skills and team working are prerequi- demands that on-the-job-training is no longer a feasible
sites for a successful job. One obvious, but often over- option.
looked means of encouraging better team working is to
ensure the goals, i.e., the operation objectives, have been Significant developments in the evolution of modern CT
clearly defined. This enables personnel and organizations applications are shown in Figure 6. Further explanation of
to focus on a common objective rather than their individual this development process and factors effecting the design
contribution. and execution of modern CT applications are contained in
Section 300 of this manual.
The unique features offered by CT conveyance, e.g., safe
live well operations, continuous circulation and electrical 4 SAFETY AND CONTINGENCY
connection with the BHA, provide benefits that cannot be
achieved by any other well intervention method (e.g., work The equipment and techniques employed on almost all CT
over rig, snubbing, wireline). In the development of CT operations today have evolved from a process within which
applications, these features have been applied in two main safety is a major concern. In this context safety issues are
ways. Earlier efforts focused on adapting existing technol- generally categories in one of four areas:
ogy to use with CT, e.g., using CT to push logging tools
through deviated wellbores. However, more recent tech- • Well security/pressure control
nique developments combine two or more CT features and
incorporated them into application systems specifically • Personnel
designed for CT conveyance, e.g., underbalanced drilling
with wireline telemetry and control system or stimulation • Equipment
treatments performed with a real-time bottom hole pressure
and temperature sensor system. • Environment

The profile and configuration of oil and gas wellbores have No attempt is made at prioritizing the importance of these
changed significantly over the relatively short history of CT areas, rather that safety issues in each of these areas be
services. For example, highly deviated and horizontal adequately addressed during the planning and execution
wellbores are now common, completions are now specially phase of every operation.
configured with the intention of using CT for subsequent
intervention and many completion or intervention activities A vital part of any job planning process relates to contin-
require highly accurate depth correlation. Therefore, it is gency planning which is intended to minimize response
understandable that routine CT applications have changed time or operation downtime. Contingency plans provide a
accordingly. Such changes are evident not only in the reference source in the event reasonably foreseeable, but
equipment, tools and hardware but significant develop- unplanned conditions are encountered during an operation.
ments are also noticeable in the design methodology
applied in the preparation and execution of modern CT Note: Contingency plans should not be confused with
operations. emergency responses which are rapid and instinctive

Page 14 of 15 Rev A - 98
 COILED TUBING SERVICES MANUAL
INTRODUCTION

actions performed by the CTU operator to prevent, contain

or resolve an emergency condition.

The safety and contingency planning recommendations

made in Section 400 of this manual are provided as
guidelines for the preparation of detailed plans or proce-
dures. Such documents should be prepared for every CT
operation and take account of the specific treatment
requirements and wellsite conditions.

Rev A - 98 Page 15 of 15
This page left blank
 Section 110
COILED TUBING SERVICES MANUAL
Rev A - 98

CT STRING MANUFACTURE

Contents Page
Introduction .................................................................................................... 2
1 CT STRING DESIGN ..................................................................................... 2
2 CT STRING MANUFACTURE ......................................................................... 4
2.1 Strip Production Process ...................................................................... 4
2.2 Skelp Production Process ..................................................................... 6
2.3 Tubing Production Process .................................................................... 6
2.3.1 Strip Preparation ................................................................................... 6
2.3.2 Forming the tube ................................................................................... 8
2.4 Laboratory Testing ............................................................................... 12
2.5 Documentation Package ..................................................................... 13
2.6 Delivery and Spooling ......................................................................... 13
2.6.1 Spooling .............................................................................................. 13

Page 1 of 14
 Section 110
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MANUFACTURE

Introduction 1 CT STRING DESIGN

Coiled tubing (CT) is manufactured from low-alloy carbon There are many design criteria, or specifications, applied to
steel. To enable delivery of a reliable product with predict- CT string manufacture, many of which relate to the specific
able performance, stringent quality control and assurance conditions (operational) for which the string is being manu-
systems are applied throughout the manufacturing process factured. However, the following general requirements
- beginning as the steel alloy is produced continuing through typically apply to most CT strings:
until the delivery of the completed string and documenta-
tion package. • Meet oil and gas industry specifications for oilfield
tubulars (e.g. NACE MR-01-75 for use in H2S environ-
Limitations in the steel strip manufacturing processes ments).
meant that early CT strings were fabricated from several
short tube lengths butt-welded together to form the required • Be strong enough to withstand reasonable burst and
string length. The resulting tube to tube welds were points collapse pressures.
of potential failure due to fatigue induced in the unavoidable
heat effected zone (HAZ) located at either side of the weld. • Have a reasonable resistance to corrosion and erosion.

Improved steel manufacturing and rolling processes com- • Be sufficiently ductile to be stored on a reel and passed
bined with new tube manufacturing techniques enable over the injector head gooseneck without deforming.
modern CT strings to be manufactured without butt welds.
This has contributed greatly to the general reliability and • Have a good resistance to fatigue caused by cycling the
greater acceptance of CT services. tubing and the corresponding plastic deformation.

There are many steps in the manufacturing process, • Possess good welding characteristics, not only in the
however there are three distinct phases relating to the manufacturing process but also in the less controlled
location of the manufacturing facilities. conditions during field welding of the CT string.

Steel mill - master coils of the required material specifica- • Have a minimum number of butt welds (girth welds) which
tion are cast and rolled. are potential weak spots in the string.

Slit mill - the master coil is slit accurately into the strips • Be economically acceptable, since the tubing string will
(skelps) of the required width for the size (OD) of tubing to have a finite life and is therefor regarded as a consumable
be formed. product.

Tubing mill - In a two-stage process, skelps are assembled The principal limitation imposed on safe running depth for
to the desired string length and then passed through the a CT string comes from the hanging weight of the tubing
tubing mill to form the completed CT string. itself. Simply increasing the wall thickness throughout the
string provides no benefit since the increased string weight
counteracts the increase in load capacity. However, a
compromise is made by designing a tapered CT string,
making it possible to run long lengths of tubing while
maintaining the overall load on the tubing within a desired
safety factor of 80% of the tubing yield strength.

Tapered strings are commonly used in deep well applica-

tions, where heavy walled tubing is required at the surface
to support the load while thinner walled tubing is used
toward the downhole end to reduce the load.

Page 2 of 14
 COILED TUBING SERVICES MANUAL Section 110
CT STRING MANUFACTURE Rev A - 98

Figure 1. CT string design - tapered string configurations.

Tapered strings are manufactured by welding two or more The production lengths of tubing will be approximately
segments of different gauge (wall thickness) strip. If the 3,500 feet. If possible the string should be made from
increment between the thick and thinner walled sections is elements of this length, (with the exception of the interme-
too large, it may not be possible to obtain a reliable joining diate wall sections).
weld. In such cases, short strips of intermediate wall
thickness are used to form a more gradual taper in the The intermediate sections should be at least 1,000 feet in
string. length, to enable damaged sections to be removed without
the risk of removing the intermediate section.
A further development in tapered string design uses strip
segments which are manufactured with a wall thickness During operations no part of the string should exceed 80%
reduction over the length of the strip (Figure 1). This of the published yield. For the purpose of designing the
eliminates the requirement for multiple tapered strips and tapered section, no part of the string should exceed 60% of
associated bias welds, In addition, the stress concentra- the published yield.
tions due to non-uniform load transfer caused by joining
differing gauge materials is also reduced. The taper design should allow for the maximum amount of
tension in each element based on the capacity of the
The exact design of a tapered string depends on the section at the injector head and the rating of the injector
application for which it is intended. However there are head, whichever is lower.
several criteria that should be considered when a tapered
string is designed.

Page 3 of 14
 Section 110
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MANUFACTURE

2 CT STRING MANUFACTURE sulfur. In the steel making process most of the carbon is
oxidized along with virtually all the silicon and much of the
The following CT string manufacturing sequence details the manganese. Phosphorus and sulfur, which can be detri-
process, and associated checks or tests, performed in a mental to steel quality, are also reduced. Manganese
series of manufacturing steps conducted in several loca- however, is later reintroduced in measured amounts to
tions and manufacturing facilities, including: increase the alloy strength and ductility.

Strip production - steel mill The alloy produced is relatively pure iron containing less
Skelp production - slit mill than 1.7% carbon.
Tube production - tubing mill
Arc Furnace
2.1 Strip Production Process
Iron and steel scrap are fed into the furnace through the
The majority of steel produced for CT string manufacture open roof. The roof is swung into place and carbon
originates in Japan (CT manufacturing plants in U.S.A.) or electrodes are lowered until they are in near contact with the
France (CT manufacturing plants in UK). The following furnace charge. The power is applied and an arc tempera-
production stages are common to most steel strip provid- ture of approximately 6,000 F melts the alloy materials.
ers. When the specified steel requirements are met, the furnace
is tapped and the steel run off into the casting ladle.
Blast Furnace
Casting Ladle
The blast furnace is charged with iron ore, sinter, coke and
limestone, as they descend they are met by a rising volume Immediately after the furnace is tapped, the ladle of liquid
of hot gas formed by combustion of the coke in a forced air steel, at a temperature of approximately 2,950 F, is moved
stream (preheated to 1,800 F). Carbon monoxide produced to the refining station. Here the steel is agitated with an inert
from the burning coke reduces the iron oxide to iron, while gas to provide a uniform temperature and composition.
the limestone removes impurities from the ore. The molten
iron (at 2,700 F) is tapped at the base of the furnace into At the casting ladle, the alloy is tested to ensure that its
ladles. chemical composition meets predefined criteria. The table
in Figure 2 shows a typical specifications for CT string
Iron from the blast furnace contains approximately 5% material. On conclusion of successful testing, the steel
carbon, up to 1% of both manganese and silicon, and much then passes to the continuous caster.
smaller but still significant amounts of phosphorus and

TYPICAL CT MATERIAL CHEMISTRY/COMPOSITION

Chemical composition - %: Carbon: 0.10 to 0.15 range

Manganese 0.60 to 0.90 range
Phosphorus 0.03 maximum
Sulfur 0.005 maximum
Silicon 0.30 to 0.50 range
Chromium 0.45 to 0.70 range
Copper 0.40 maximum
Nickel 0.25 maximum

Figure 2. Typical CT material chemistry/composition.

Page 4 of 14
 COILED TUBING SERVICES MANUAL Section 110
CT STRING MANUFACTURE Rev A - 98

Blast furnace
ARC furnace Casting ladle

Continuous
caster

Slab reheat

Rolling mill

Pickling
Oiling Master coil

Figure 3. CT manufacturing process - master coil.

Continuous Caster Rolling Mill

The continuous caster produces steel strip in a semi- Heated, semi-finished steel slabs are passed through the
finished form. The ladle of liquid steel is tipped into an hot-strip rolling lines comprising sets of rollers that progres-
intermediate, smaller ladle that feeds a water-cooled cop- sively squeeze the slab reducing it to the required thick-
per mould. The partially solidified steel is slowly drawn into ness. This reduction in thickness is achieved with a
a series of rollers that transfers the cast material from a corresponding increase in length and, to a lesser degree
vertical to a horizontal orientation. A travelling torch cuts width.
the ingot or slab into manageable lengths.
The rolling process must be carefully monitored to ensure
Slab Reheat the finished strip is within the strict CT wall thickness
tolerances.
Since the steel slabs are produced in a continuous process,
some of the slabs may have to wait before entering the Pickling Line
rolling mill. To maintain the correct temperature the material
is held in a slab reheat facility. If, during the rolling process The rolled strip is passed through an acid spray and bath to
the slab temperature drops too much, it may also be remove surface scale and oxides which may have been
returned to the reheat facility for reconditioning prior to picked up during the rolling process. The final pickling
finishing. process includes a treatment to ensure residual chemicals
are neutralized.

Page 5 of 14
 Section 110
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MANUFACTURE

Oiling closed tube are welded using a high frequency induction

welding system.
Immediately following pickling, the strip is sprayed (coated)
with a viscous oil preparation which prevents atmospheric Each skelp received from the slit mill is dimensionally
corrosion or contamination while in storage or during checked for width and gauge and the strip edges visually
transportation to the tube manufacturing facility. inspected for any slitting process defects. A unique iden-
tification number, referencing the master coil identification,
Master Coil is assigned to each strip to ensure traceability throughout
the tube forming process.
Following pickling and oiling, the strip is wound into a spool
known as the “master coil” and prepared for shipment to the 2.3.1 Strip Preparation
slitting mill. Representative strip material from each mill
heat is submitted for chemical composition analysis to Individual skelps are spooled down and spliced to form a
ensure that the steel meets the required specification. continuous strip the length of which is determined by the
length of the CT string required (i.e., CT string length + pre
Each master coil is uniquely identified and supported with and post-mill manufacturing excess).
a documentation package which includes details of the
steel specification, manufacturing process, overall length Bias Welding
and thickness.
To ensure the weld joining each strip forms an integral part
2.2 Skelp Production Process of the assembled strip, the end of the strip is cut at a “bias“
angle which precisely matches the cut in the tail of the
Skelp production is a relatively simple process conducted preceding strip. The strips are then welded together using
at special slit mill facilities located in the U.S.A. or UK. a plasma arc welder with an inert gas shield to form one
continuous strip.
The master coil is spooled down and cut into strips (slit) by
means of rotating blades, the width of the strip being When the tube is formed, this bias weld takes on a helical
determined by the required OD of the finished tubing. The profile making the tube less prone to failure than a tube-to-
resulting strip, or skelp, is then individually prepared and tube (butt) weld.
uniquely identified before shipping to the tubing mill.
Radiographic Inspection
2.3 Tubing Production Process
The weld is visually examined then passed through a
The tubing production process is typically completed in two radiographic inspection station where it is examined for the
distinct phases. following faults:

• Stage 1 - The relatively short lengths (approximately 3500 • Gas porosity

ft) of flat steel strip, of the required properties and
dimensions, are bias welded to form the complete length • Concavity of the bead
of the CT string. Each weld is heat treated in a closely
controlled process to remove any HAZ from the strip • Uneven surface of the bead
material. The assembled strip is wound onto a accumu-
lator reel for transport to the next stage of the manufac- • Surface misalignment
turing process.
• Undercut parent material
• Stage 2 - The flat strip from the accumulator reel is passed
through the forming mill where several sets of rollers bend Any defective weld is cut out and a new joint prepared.
the strip to gradually form the tubular profile. Prior to
passing through the final roller set, the edges of the

Page 6 of 14
 COILED TUBING SERVICES MANUAL Section 110
Schlum berger
CT STRING MANUFACTURE Rev A - 98

Slitting
Bias welding

Radiography

Planishing

Machining

Heat treatment 1
2
3
4
5
Lay er 1
LAS E R

MPI inspection
Width inspection Length check Strip spool

Figure 4. CT manufacturing process - strip preparation.

Longitudinal weld

Bias weld

Figure 5. CT biased and longitudinal welds.

Page 7 of 14
 Section 110
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MANUFACTURE

Heat Treatment for the tubing mill.

Accepted welds are induction heated to raise the tempera- Due to the exacting welding processes and subsequent
ture of the weld area, thereby eliminating the hardness and extensive inspection procedures, strip assembly typically
embrittlement which occurs during any welding process (in requires more time to complete than the tube milling
the heat affected zone). process. Consequently, there are typically several accu-
mulator reels prepared to enable the tube mill to be operated
Planishing efficiently.

This optional process minimizes the amount of material 2.3.2 Forming the tube
removed in the next step by passing the weld area between
high-pressure rollers to smooth and prepare the weld area. The second stage of tube manufacture involves several
continuous phases which form the flat steel strips into
Machining tubing of the desired physical properties. The process must
be highly controlled and uninterrupted if a high-quality,
In order to achieve a smooth transition between strips, and consistent product is to be produced.
over the weld itself, excess material remaining after weld-
ing and planishing is removed by a precision grinding Due to the nature of the product, destructive testing of
process. material samples can only be conducted at the beginning
or end of the mill run. Also, physical tests cannot be
Magnetic Particle Inspection conducted on the material during manufacture. To ensure
the correct heat treatments are applied, an initial sample is
The surface of the strip is sprayed with a magnetic particle milled at the beginning of each string. The mill is stopped
solution and placed in a magnetic field. With the field active, and the sample tested for the following properties and
indications of imperfections will become apparent when the characteristics before the milling process is restarted.
site is viewed in ultraviolet light.
Once started, the milling process cannot be interrupted
Dimensional Inspection without jeopardizing the properties or integrity of the tubing
string. To confirm that the desired properties have been
The strip at the weld site is checked for thickness, width, maintained throughout the mill run, a test sample is
hardness and alignment, each measurement must fall retrieved from the tail end of the milled string. The tests and
within the original strip tolerances before the weld is checks listed below are performed, with a tubing sample
ultimately accepted. identified and stored for quality assurance purposes.

When the weld has passed inspection, a unique number • Dimensional checks
identifying the weld is assigned and marked on the strip at
both sides of the weld. Documentation relating to the weld • Ovality
is retained for inclusion in the CT string manufacturing
record. • Wall thickness

Length Counter • Seam-weld mismatch

The strip length is measured as it leaves the assembly area • Crush test
prior to being wound onto the strip accumulator reel.
• Flare test
Accumulator Reel
• Tensile test
The assembled strip is spooled up on an accumulator reel
which is used to store and transport the strip in preparation

Page 8 of 14
 COILED TUBING SERVICES MANUAL Section 110
CT STRING MANUFACTURE Rev A - 98

The following steps or phases are included in the tube Two basic techniques are used for flash removal:
milling process.
• Flash material cut and removed at the tubing mill
Forming Stands
• Flash material cut at the tubing mill and then removed
The forming stands comprise a series of rollers that during the string flushing process following manufacture
gradually form the tube from the flat skelp. This manipula-
tion is designed to evenly “work” the material and avoid Seam Annealer
areas of high stress. The tube forming process also
incorporates the longitudinal welding process which occurs The formed tube passes to the seam annealer which heat
immediately the two skelp edges are closed. treats the weld area (approximately 1650 °F) to recrystal-
lize the material in the heat affected zone. This process
Longitudinal Welding relieves the stresses resulting from the welding process.

The longitudinal weld is made using a high frequency Cooling Station

electrical induction weld system. Heat for the weld is
generated by electrical resistance induced by a coil which The tube is slightly cooled before progressing to the next
encircles the tubing. The heat produced (approximately stage of the manufacturing process.
2500 °F) is confined to a narrow area along the edges of the
closing tube. The final set of forming rollers force the edges Weld Inspection
together at fusion temperature to produce the weld. Since
no filler material is added during the welding process, the Electronic inspection of the seam weld is carried out using
composition of the weld is the same as the body of the tube. an electromagnetic (eddy current) testing system. The
testing station continually records the inspection data and
The tubing is welded slightly oversize with the emphasis on automatically identifies and precisely marks any area that
the weld quality rather than on the final dimension. may require further inspection by magnetic particle testing
and radiography.
Flash Removal
Sizing Stand
A small quantity of weld flash material is extruded on the
inner and outer surfaces of the tube. This is removed from After inspection the tubing is drawn through the sizing mill
the outer surface by a contoured cutting tool located where precisely set rollers form the final string OD.
directly after the welding station. On larger CT sizes (>1-3/
4-in.) the internal weld flash can also be removed if desired.

PHYSICAL PROPERTIES OF 70,000 YIELD STRENGTH MATERIAL

Physical properties: Minimum yield strength: 70,000 psi

Minimum tensile strength: 80,000 psi
Minimum elongation: 30%
Minimum hardness: 22C Rockwell

Figure 6. Physical properties of 70,000 yield strength material

Page 9 of 14
 Section 110
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MANUFACTURE

Forming stand Longditudinal Flash removal Seam anealling

Strip spool
weld

Water cooling Weld inspection Final sizing Length check

Diameter check Stress relief Air cooling End fitment Weld inspection
welding

Hydro-testing Drift and purge Spooling

Figure 7. CT manufacture - tube forming process.

Length Check Dual Axis Laser

The formed tubing is accurately measured to confirm that A dual axis laser continuously scans the outer surface of
the overall length is that of the required CT string. The the tube to ensure the diameter of the tube is within the
length recorded at this station is considered “string length selected specifications.
as manufactured”.

Page 10 of 14
 COILED TUBING SERVICES MANUAL Section 110
Schlum berger
CT STRING MANUFACTURE Rev A - 98

Full Body Stress Relief Spooling

The tubing passes through a reheat station where the entire When the CT string is spooled onto a shipping drum the
tube body is heated to between 900 and 1400 °F. The exact string is spooled back to front, i.e., the downhole end of the
heat treatment specifications are carefully controlled to CT string is at the spool core. This ensures the string will
achieve the desired physical characteristics from the be correctly oriented when it is eventually spooled onto the
material being milled. The heat treatment ensures a consis- CT work reel. While this may not be so important for parallel
tent material grain structure throughout the body of the tube strings, it is obviously essential that tapered strings are
and relieves any residual stress induced during manufac- correctly handled and spooled.
ture. The characteristics of the tubing material combined
with the heat treatment at this stage determine the ultimate End Fitment Welding
physical characteristics of the completed CT string (Figure
6). The end fitting, typically a WECO 1502 “wing-half” , is
welded to the string to simplify the spooling (to work reel)
Air Cooling operation. This connection makes up to the corresponding
connection on the reel axle.
In preparation for spooling, the tubing is air cooled over an
interval between the tubing mill and spooling stand.

Nom. Wall Coiled Tubing OD (in.)

Thickness (in.) 1-1/4 1-1/2 1-3/4 2-3/8 2-3/8 3-1/2

0.075 1.000 - - - - -
0.080 1.000 1.1875 - - - -
0.087 0.875 1.1875 - - - -
0.095 0.875 1.1875 1.375 - - -
0.102 0.875 1.1875 1.375 - - -
0.109 0.875 1.1875 1.375 - - -
0.116 0.875 1.1875 1.375 - - -
0.125 0.875 1.125 1.375 2.000 - -
0.134 0.875 1.125 1.375 2.000 - -
0.145 0.875 1.125 1.375 1.875 2.500 -
0.156 0.750 1.0625 1.250 1.875 2.375 -
0.175 0.750 1.0625 1.250 1.875 2.375 3.000
0.190 - 1.000 1.250 1.875 2.375 3.000
0.204 - 1.000 1.250 1.875 2.375 3.000
0.224 - - 1.1875 1.750 2.250 2.875
0.250 - - 1.125 1.750 2.250 2.875
0.280 - - - 1.625 2.188 2.750
0.300 - - - 1.625 2.125 2.750

Figure 8. Recommended CT gauge-ball sizes.

Page 11 of 14
 Section 110
COILED TUBING SERVICES MANUAL Schlum berger
Rev A - 98 CT STRING MANUFACTURE

Weld Inspection On completion of the pressure testing procedure, the test

fluid is purged from the string using air or nitrogen and an
The end fitting weld undergoes radiographic inspection. internal corrosion inhibitor applied to protect the tubing
Typically, three shots are taken at 120° intervals around during transportation and storage. If the string is to be
the circumference of the weld, offset from the weld centre. delivered or stored in a cold climate, freeze protection may
also be applied to prevent damage from freezing of any
The resulting film is inspected for the following flaws and, residual water/moisture.
on successful conclusion of the checks, placed in the
string file:
2.4 Laboratory Testing
• Gas porosity
Tubing samples taken from the beginning and end of each
• Concavity of the bead mill run are subjected to the following tests or checks.

• Uneven surface of the bead Dimensional Checks

• Surface misalignment Samples are dimensionally checked for:

• Undercut parent material • Ovality

Hydro Testing • Wall thickness

The completed CT string is hydro tested to 90% of the string • Seam-weld mismatch
yield pressure for a minimum of thirty minutes. The test
pressure and duration are recorded on a chart and become Crush Test
part of the permanent string record.
Completely flattens a test section of tubing with the seam
Drifting And Purging weld orientated at the apex of the fold. No open defects are
permitted in the weld.
While the string is being filled with water, a steel gauge ball
of a specified diameter is run through the tubing to ensure
there are no obstructions. Recommended gauge ball sizes
are shown in Figure 8.

Crush Flare Ovality Seam weld Tensile Wall thickness

mismatch

Figure 9. CT string manufacture - laboratory testing.

Page 12 of 14
 COILED TUBING SERVICES MANUAL Section 110
CT STRING MANUFACTURE Rev A - 98

Flare Test • Weld log including bias weld and butt weld positions

Stretches the open end of the tubing over a mandrel with a • Hydrostatic test pressure including:
60° taper, the tubing must expand 21% above the initial Test duration
diameter before failure (splitting). Failure should not occur Maximum pressure
at the seam weld. Crush and flare tests are carried out in Minimum pressure
accordance with ASTM A450. Temperature
Test fluid
Tensile Test
• Details of purging/drying or freeze protection procedures
Full section test samples are marked to enable % elonga-
tion to be determined, placed in a tensile test facility. A • Details of drift ball pumping program
tensile load is gradually applied until the sample is tested
to destruction. The resulting data is used to determine: • Record of spooling during the manufacturing and testing
program.
• Yield strength
2.6 Delivery and Spooling
• Ultimate yield strength
On receipt of a new CT string there are several inspection
• Elongation and check procedures necessary before the string is
spooled to the work reel.
2.5 Documentation Package
• Visual inspection of shipping spool and string including:
The documentation package prepared for each tubing Protective crating
string comprises data relating to the string material, manu- Spool hub and handling/mounting points
facturing processes and test or inspection procedures. Not String union/connection for reel core (WECO)
all information contained in the package will be provided General condition of visible wraps
with the string on delivery. However, a complete package
is archived at the tubing mill in the event of subsequent • Review of documentation package/string record, includ-
enquiry. ing:
Confirmation of material order and delivery note
The documentation package should contain the following Confirm the required certification package is complete
information or data.
Prior to spooling, all protective crating and banding is
• Unique string identification number removed from the shipping spool. In addition, any nitrogen
pressure contained within the string for shipping should be
• Tube grade and serial numbers carefully released.

• Chemical composition 2.6.1 Spooling

• Heat number(s) The shipping spool is mounted on a stand which enables

rotation, under a controllable back tension, while the string
• Mechanical properties: is spooled to the work reel. Accurate spooling is essential,
Hardness especially on the reel bed wraps, to ensure no damage is
Tensile strength(s) caused to the string.
Yield strength(s)

• Identification and position of tapered string segments

Page 13 of 14
 Section 110
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MANUFACTURE

Several checks or inspections should be made at time of

spooling, including:

• Confirm length - at least two independent measuring

devices should be used to confirm the string length.

• OD monitoring - the string should be run through a UTIM

(Universal Tubing Integrity Monitor) to enable a base
record of diameter/ovality to be established.

• Surface protection - application of an external surface

corrosion inhibitor (or similar) should be considered.

• Pressure test - Once the CT string is fully spooled onto the

CT reel, the complete assembly is pressure tested to the
working pressure of the CT string (nominally 5,000 psi)
using water as the testing medium. On completion of the
test the water is completely purged from the string with air
or nitrogen. If the string is to be stored before use, an
internal corrosion inhibitor may be applied.

• String File Record - The documentation package provided

with the string should be used to start the string file or
record. If an electronic string monitoring and recording
system is used, the string details should be entered.

Page 14 of 14
 Section 120
COILED TUBING SERVICES MANUAL
Rev A - 98

CT STRING LIMITS

Contents Page
Introduction .................................................................................................... 2
1 CT OPERATING LIMITS ................................................................................ 2
1.1 Pressure and Tension ............................................................................ 2
1.2 Internal Burst Pressure ......................................................................... 2
1.3 External Collapse Pressure ................................................................... 3
1.4 Wellhead Pressure ................................................................................ 3
1.5 Tension ................................................................................................. 3
1.6 Diameter and Ovality ............................................................................ 5
1.7 Fatigue and Corrosion ........................................................................... 5
1.8 Pumping and Flowing Fluids ................................................................. 5
1.9 Flowing Through CT .............................................................................. 6
1.10 Hydrogen Sulfide ................................................................................... 6
2 CT STRING FATIGUE .................................................................................... 7
2.1 CT String Stress and Strain .................................................................. 7
2.1.1 Stress Applied in the Well ................................................................... 10
2.1.2 Stress Applied at the Surface ............................................................. 10
2.2 CT String Fatigue Testing .................................................................... 11
3 CT STRING FORCES .................................................................................. 13

Page 1 of 15
 Section 120
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING LIMITS

Introduction In the majority of cases the pressure and tension limits that
apply to a CT work string in given wellbore conditions will
The experience associated with leading research and be determined by a computer model. The model output
development efforts has helped create well-defined, rec- typically includes a plot describing the pressure and ten-
ommended operating limits and procedures for coiled sion limits which will apply in the wellbore conditions which
tubing (CT) operations. were input and for treatment conditions during the intended
operation (Figure 1). In addition, maximum allowable pres-
This manual section will help identify factors contributing to sure and tension values are sometimes given. These
generally accepted (current) operating limits. Most of these values can used to define the test pressure and tension
factors are dependent both on the physical/metallurgical applied to the CT while function testing the injector head
characteristics of the CT string, and on the history of events and pressure control equipment.
to which the CT string has been subjected. However, in
some cases, the operating limits relate to operating tech- The principal curve shown is the working limit curve. This
niques and conditions. curve and the Pmax and Tmax lines define the pressure and
tension operating limits for a specific CT string under the
1 CT OPERATING LIMITS stated conditions.

Current operating limits are increasingly defined by com- In the event that computer model output data are not
puter models and specially prepared software. available, the following long-standing recommended limits
will apply.
The limits discussed in this section apply to the following
aspects of the CT string and CT operations. 1.2 Internal Burst Pressure

• Pressure and tension Internal burst pressure is the pressure required to stress the
OD of the nominal wall thickness tubing to the minimum
• Diameter and ovality material yield. This value varies greatly with the tensile load
applied to the tubing string. An extract of tubing data
• Fatigue and corrosion supplied by a tubing manufacturer details specifications
and capacities of CT manufactured from 70,000 psi grade
• Pumped or produced fluids material (Figure 2) . It should be noted that the effect of axial
tension on pressure rating has not been applied and the
• H2S considerations data are for new tubing at minimum strength.

Tubing fatigue and reel history data are factors which may Due to the relatively high friction pressures encountered
influence the limitations and applications of particular when pumping through CT, the highest internal pressure will
tubing strings. These effects are cumulative and require a generally be found at the reel core. However, the effects of
recording system to accurately monitor the progress of the hydrostatic pressure should not be ignored.
tubing life.
The internal pressure limitations typically recommended
1.1 Pressure and Tension where no model output data are available are as follows.

The factors which affect the operational limits of a CT string • Maximum pump pressure while running tubing
in any application are often interactive, e.g., the pressure 4000 psi
capacity of a CT string can be greatly affected by the
tension to which it is subjected. Therefore, it is essential • Maximum pump pressure with tubing stationary
that all relevant factors are taken into account when 5000 psi.
determining any operational limits.

Page 2 of 15
 COILED TUBING SERVICES MANUAL Section 120
Schlum berger
CT STRING LIMITS Rev A - 98

Figure 1. CT string pressure and tension model output plot.

1.3 External Collapse Pressure

overcome the forces created by stripper friction and well-
This is the external pressure required to stress the tubing head pressure while injecting CT into the wellbore.
to its minimum yield strength. Again, this varies greatly
depending on the tensile load applied to the tubing string. • Maximum recommended wellhead pressure 3500 psi.
Ovality and irregularities in the tubing surface profile can
lower the tubing resistance to collapse to significantly low Operations at higher pressures are commonly undertaken,
levels. however, special consideration is given to the equipment
and techniques necessary to achieve safe operations. The
The maximum outside to inside pressure differential cur- recommendation shown above relates to "standard" CT
rently recommended where no computer simulation output equipment and techniques.
data are available is as follows.
1.5 Tension
• Maximum Collapse Differential 1,500 psi.
The tubing tensile operating limit is dependent on the
1.4 Wellhead Pressure specification of the tubing material, the OD of the tubing and
wall thickness. The manufacturers data shown in Figure 2
Wellhead pressure acts on the CT by creating an upward show the minimum yield strength values for a range of
force which (if high enough) will tend to force the tubing out tubing sizes and wall thicknesses. Since the tensile limit
of the well. The maximum wellhead pressure into which CT will varies with the wall thickness of the tubing, it is
can be safely run is not a limitation of well control or safety important that the operator is aware of the weld locations
equipment. It is set by the ability of the injector head to when tapered strings are used.

Page 3 of 15
 COILED TUBING WORK STRING DATA – 70,000 PSI YIELD STRENGTH MATERIAL

Tubing Dimensions Pressure Capacity Internal

Page 4 of 15
x Sec Area Wt Load Capacity External Rev A - 98
(in.) (psi) Capacity
Section 120

(in2) (lb/ft) (lb) displacement

per 1000ft per 1000ft
O.D. Wall Yield Ultimate Burst Collapse
Wall I.D. Wall Inside Tested (gal) (bbl) (gal) (bbl)
MIN NOM MIN MIN MIN MIN
NOM NOM NOM NOM NOM

0.75 0.067 0.063 0.616 0.143 0.298 0.489 10,031 10,748 9,400 12,600 10,722 5.48 0.369 22.95 0.547

1.00 0.067 0.063 0.866 0.196 0.598 0.668 13,720 15,040 6,980 11,440 8,260 30.60 0.729 40.78 0.971
1.00 0.075 0.071 0.850 0.218 0.568 0.741 15,260 17,440 7,860 12,900 9,970 29.51 0.703 40.78 0.971
1.00 0.087 0.083 0.826 0.250 0.536 0.848 17,500 20,000 9,200 15,100 11,120 27.84 0.663 40.78 0.971
1.00 0.095 0.091 0.810 0.270 0.515 0.918 18,900 21,600 10,080 16,500 12,030 26.54 0.637 40.78 0.971
1.00 0.109 0.104 0.782 0.305 0.480 1.037 21,350 24,400 11,530 19,210 13,600 24.94 0.594 40.78 0.971

1.25 0.067 0.063 1.116 0.247 0.980 0.840 17,290 19,760 5,580 9,020 5,410 50.21 1.212 63.75 1.518
1.25 0.075 0.071 1.100 0.277 0.950 0.941 19,390 22,160 6,290 10,130 6,770 49.35 1.175 63.75 1.518
1.25 0.087 0.083 1.076 0.318 0.909 1.081 22,260 25,440 7,360 11,900 8,810 47.22 1.124 63.75 1.518
1.25 0.095 0.091 1.060 0.345 0.882 1.172 24,150 27,600 8,070 13,050 9,830 45.82 1.094 63.75 1.518

1.25 0.102 0.097 1.046 0.368 0.859 1.251 27,340 31,250 9,100 11,400 10,450 44.64 1.063 63.75 1.518
1.25 0.109 0.104 1.032 0.391 0.837 1.328 27,370 31,280 9,220 15,180 11,140 43.48 1.035 63.75 1.518
1.25 0.125 0.118 1.000 0.442 0.785 1.502 31,000 33,225 10,000 13,200 12,500 40.80 0.971 63.75 1.518
1.25 0.134 0.128 0.982 0.470 0.757 1.597 32,886 35,235 10,000 15,000 13,300 39.34 0.936 63.75 1.518
1.25 0.156 0.148 0.938 0.536 0.691 1.840 37,100 39,750 10,000 17,400 15,200 35.89 0.855 63.75 1.518

1.50 0.095 0.091 1.310 0.419 1.348 1.425 29,350 33,540 6,720 10,750 7,490 70.03 1.667 91.806 2.186
1.50 0.109 0.104 1.282 0.476 1.291 1.619 33,340 38,100 7,680 12,430 9,430 67.06 1.597 91.806 2.186
CT STRING LIMITS

1.50 0.125 0.119 1.250 0.540 1.227 1.836 37,800 43,200 8,790 14,390 10,690 63.74 1.518 91.806 2.186
1.50 0.134 0.128 1.232 0.575 1.192 1.955 40,250 46,000 9,460 15,500 11,390 61.92 1.474 91.806 2.186
1.50 0.156 0.148 1.188 0.658 1.108 2.239 46,106 49,410 10,000 13,800 13,000 57.58 1.370 91.806 2.186

1.75 0.109 0.104 1.532 0.5619 1.843 1.910 39,335 44,955 6,100 7,630 3,600 95.78 2.28 120.68 2.870
1.75 0.125 0.118 1.500 0.6381 1.767 2.190 44,670 51,051 7,000 8,750 4,100 91.82 2.19 120.68 2.870
COILED TUBING SERVICES MANUAL

1.75 0.134 0.128 1.482 0.6803 1.725 2.313 47,621 54,424 7,500 9,380 4,400 89.63 2.13 120.68 2.870
1.75 0.156 0.148 1.438 0.7812 1.624 2.660 54,684 62,496 8,700 10,920 5,000 84.39 2.01 120.68 2.870

2.00 0.109 0.104 1.782 0.6475 2.494 2.200 45,328 51,803 5,300 6,670 3,100 129.59 3.09 157.63 3.750
2.00 0.125 0.118 1.750 0.7363 2.405 2.670 51,540 58,905 6,100 7,650 3,400 124.98 2.98 157.63 3.750
2.00 0.134 0.128 1.732 0.7855 2.356 3.070 54,988 62,843 6,500 8,200 3,800 122.42 2.91 157.63 3.750
2.00 0.156 0.148 1.688 0.9037 2.238 4.400 63,261 72,298 7,600 9,550 4,500 116.28 2.77 157.63 3.750
Schlum berger

Figure 2. Manufacturers CT string data table - example for 70,000 psi yield strength material.
 COILED TUBING SERVICES MANUAL Section 120
CT STRING LIMITS Rev A - 98

The tensile strength of a tubing string can be reduced for string, the model can predict when the first cracks in the
several reasons, not least by the events during the history tubing will be initiated. By applying a safety factor to this
of the tubing string. A safety factor to take account of these prediction, the CT string may be withdrawn from service
events, known and unknown is included when determining before a fatigue-induced operating failure occurs.
the tensile limit of a specific string.
To provide data for the computer model to function effec-
• The recommended maximum CT tension limit is 80% of tively, the following parameters must be accurately re-
the manufacturer's published yield strength. corded during every operation.

1.6 Diameter and Ovality • Bending cycles

Typical diameter and ovality limits are based on the ability • Pressure cycles
of the pressure control equipment to operate efficiently with
oversized or distorted tubing. In addition, the reduced • Major and minor diameters
collapse resistance which is associated with oval tubing
requires that the CT string be closely monitored if predict- • Chemical environment
able performance is to be maintained.
With these parameters input to the model, a plot can be
A tubing integrity monitor, or similar device is commonly made to display the percentage tubing life against the
used to monitor tubing diameter and ovality. length of the string (Figure 3).

Alarm limits on the monitoring device should warn the Most models incorporate a means of inputting the proposed
operator if tubing diameter varies by more than plus 5% or pumping and tubing movement schedules for an intended
minus 3% of the nominal diameter. A tubing ovality warning operation. The resulting plot may then be analyzed to verify
should activate when the ovality reaches 105%. the ability of the CT string to safely complete the operation
while within the fatigue limits of the string.
NOTE: The ovality percentage value is obtained by dividing
the major axis diameter by the minor axis diameter. CT work strings containing tubing elements which have
been used in excess of 95% should typically be removed
• The recommended operating limits applied to CT diameter from service to allow the appropriate repair or replace
and ovality are as follows: action.

Maximum OD – 106% of the nominal CT diameter. 1.8 Pumping and Flowing Fluids

Minimum OD – 96% of the nominal CT diameter. Since there is no definitive method of predicting the
development of a tubing failure or pinhole, the pumping of
1.7 Fatigue and Corrosion hydrocarbon gas or condensates through a CT work string
should be prohibited.
Fatigue damage, as a result of internal pressure and
bending cycles, is the primary consideration when attempt- The pumping of flammable fluids such as crude oil through
ing to define the useful life of a CT string. However, fatigue CT is allowed providing necessary precautions have been
is an unusual parameter since it must be predicted as it taken, e.g., the oil has been degassed. Adequate fire
cannot be measured. protection precautions should be provided on location for
the duration of the operation. The pumping of “live crude”
The computer models feature complex mathematical algo- through CT is not generally permitted.
rithms which were derived from an extensive CT fatigue
testing program. This model calculates the damage that Reverse circulation through CT is permissible if the follow-
occurs to the tubing due to the sequence of pressure and ing conditions are met.
bending cycles. By analyzing the cumulative data of a CT

Page 5 of 15
 Section 120
COILED TUBING SERVICES MANUAL Schlum berger
Rev A - 98 CT STRING LIMITS

Figure 3. CT string safe working life model output plot

• CT size is 1-1/2 in. or greater ervoir fluids can be safely produced through CT comple-
tions which have been installed and secured following
• The well is dead and is full of kill-weight fluid approved procedures and using equipment designed and
approved for such application.
• After considering the anticipated combination of tensile
and differential pressure loads, the CTU operator and 1.10 Hydrogen Sulfide
engineer are aware of all operating limits.
Equipment which is designed and built for use in H2S
The tubing may be subjected to extreme loads and forces environments can safely tolerate exposure to relatively
during this type of operation, Therefore, it is important that high levels of H2S for an extended time period. However, the
the parameters on which the job was designed and ap- presence of H2S (even in minute concentrations) can be
proved are maintained as closely as practical. sufficient to initiate corrosion or cracking in equipment that
is not intended for use in such an environment. The hazards
1.9 Flowing Through CT associated with use of the incorrect equipment in an H2S
environment are severe, both in terms of personnel safety
The production of reservoir fluids through CT above the well and well control.
pressure control equipment is normally strictly prohibited.
Where a total system pressure is greater than 265 psia and
The absence of a suitable master valve and kill facility, the H2S partial pressure exceeds 0.05 psia the system is
located at or on the wellhead, can render temporary CT an considered sour. This is based on the National Association
extremely hazardous means of production. However, res- of Corrosion Engineers (NACE ) Standard MR-01-75-88

Page 6 of 15
 COILED TUBING SERVICES MANUAL Section 120
CT STRING LIMITS Rev A - 98

definition of a sour environment. Damage is caused by the repeated bending and straighten-
ing of the CT at the gooseneck and reel. The resulting
In practice CT operations will almost always be performed failure mechanism is known as low cycle fatigue. Under
in systems with a total pressure exceeding 265 psia. these conditions, damage is dramatically increased if
Therefore, the critical limit in terms of H2S corrosion in any internal pressure is applied while simultaneously bending
system will be 0.05 psia. This is applicable in single- and the CT.
multiphase fluids.
As a result of the research and development efforts,
To simplify the procedure in determining whether a well is sophisticated fatigue tracking system have been imple-
to be considered a “sour well” and initiate the corresponding mented. These systems takes account of the factors that
requirements of equipment and personnel safety, the are now known to have influence over the useful life of a CT
following recommendations are made. string.

It should be noted that these are minimum recommenda- The physical and metallurgical properties of CT materials
tions; application of more stringent limits may be justified have significantly improved in recent years. This combined
by local requirements. with better manufacturing techniques and quality control
procedures has resulted in the production of a consistent
• Any well on which an acid treatment is to be performed, product with a predictable performance.
and which has or has had any history of H2S, should be
regarded as a potential sour well. Early manufacturing processes required that the CT string
be assembled using butt welds to join several short lengths
• Any well on which the CT will be exposed to a total system of tubing. This introduced a relative weakness into the CT
pressure less than 5000 psi, and an H2S level in excess material adjacent to the weld site and failures in this type
of 10 ppm, should be regarded as a sour well. of work string were relatively common - almost always
occurring within the heat-affected zone (HAZ).
• Any well on which the CT will be exposed to a total system
pressure greater than 5000 psi containing any level of H2S Almost all CT strings are now being formed from a continu-
will be regarded as a sour well. ous length of strip material. The short lengths of flat strip
material, which are used to assemble the final string length,
• Only equipment that can be positively identified as are welded and heat treated in a closely controlled process
suitable for use in an H2S environment (as specified by which effectively removes any HAZ from the strip material.
NACE Standard MR -01-75-88 and API R49) should be
used when working on a well that is known or suspected 2.1 CT String Stress and Strain
to contain H2S.
A stress is the internal reaction of a body to an external
2 CT STRING FATIGUE force. It is generally described as the internal force acting
across a unit area in a solid material in resisting the
The working life of a piece of metal (e.g., coiled tubing) is separation, compacting or sliding that tends to be induced
governed by the loads and resulting stresses to which it is by external forces. Stress analysis is the determination of
exposed. For many years the industry standard unit of the stresses produced in a solid body when subjected to
measure for CT life was “running feet.” This unit of various external forces.
measurement is a reflection of what happens to the CT in
the wellbore and, consequently, implies that the stresses Since stress is a function of the area of an element, stress
applied to the CT in the wellbore determine its life. Exten- values are expressed in force/area (e.g., psi).
sive studies made into the behavior and fatigue of CT have
conclusively shown that the useful life of a CT work string Whenever a stress is applied to an element, the element
is almost entirely determined by fatigue imposed by tubing reacts by changing its dimensions, i.e., it is deformed.
handling methods outside the wellbore. Strain is a measure of this deformation and is defined as the
change in the dimension of the element divided by its

Page 7 of 15
 Section 120
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING LIMITS

original dimension. • Radial stress

The units of strain are consequently expressed as in./in., The radial stress and associated radial strain only be-
mm/mm, etc.... or sometimes as a percentage. Any stress come a significant factor when the wall thickness of the
applied to an element will always have an associated strain; CT is reduced as a result of the combined effects of the
a bending stress causes a bending strain. hoop strain and bending strain.

In any operation CT is exposed to several stresses, some The tension applied to the CT downhole is the result of
of which apply at specific points while others apply through- tensile stresses which terminate at the injector-head chains.
out the entire system. The primary stresses that are applied The tension to which the CT is subjected at surface is
to a CT string are shown in Figures 4 and 5. negligible under normal operating conditions.

• Hoop stress (circumferential) For most metals, there is a well-established relationship

between the stresses applied to an element and the
Internal pressure applied to a CT string produces a hoop resulting strains. This general relationship is graphically
stress which is applied to the full length of the string. shown in Figure 6.

• Bending stress The plastic and elastic regions shown in Figure 7. identify
important differences in material behavior. There are two
A bending stress is produced when the CT is being bent distinct parts to the relationship as shown by the lines OA
over the gooseneck or onto the reel. and AB. In the line OA, the strain is directly proportional to
the applied stress, i.e., if a small amount of pull is applied,
the material stretches a little. If twice as much pull is
applied, it stretches twice as much (however, the material
will always return to its original dimension). This applies up
to a limit corresponding to Point A, which is known as the
Pressure and
yield point.
Pressure and bending
tension
The stress (C) applied at Point A is known as the yield
Pressure and strength.
bending

Radial stress

Pressure and
compression

Pressure and
tension
Hoop stress

Bending
Possible stress
torque

Figure 4. CT string stress sources. Figure 5. Principal CT stresses.

Page 8 of 15
 COILED TUBING SERVICES MANUAL Section 120
CT STRING LIMITS Rev A - 98

The line XZ, which is parallel to line OA, shows how the
Ultimate Strength stress will be removed.
D B
Plastic Region Breaking
A Strength This is called plastic deformation and is the reason why the
C
Elastic Region interval AB is referred to as the plastic region. A plastic
Yield Point
deformation represents a permanent change in the atomic
structure of a material when the stress is removed.
STRESS

The new elastic limit for the material is now somewhere

Elongation
between points F and X, but its exact position depends on
the type of material and the stresses involved. The next
time a stress is applied, it will go up the line ZX and not OA.
O
STRAIN E It is important to understand that every time a material is
stressed beyond the yield point, some permanent damage
occurs. Two important points should be noted when consid-
ering stresses applied to the CT:
Figure 6. General stress/strain plot.
• The stress/strain theory applies to each of the different
Beyond Point A, the behavior of the material changes. A stresses applied to the CT, e.g., bending stress, hoop
small change in stress will result in a large strain. If it is stress, radial stress or the tensile stress acting on the CT
pulled beyond its yield point, the material stretches signifi- while in the well.
cantly until it breaks. The breaking point corresponds to
Point B. • The stresses can be simplified into two groups– those
acting on the CT when it is in the well and those acting on
The applied stress (D) at Point B is known as the ultimate the CT at the surface.
strength of the material. The strain (E) at Point B is known
as the ultimate strain.

If the applied stress is kept within the range OA, e.g., point
Y, and then released, the strain will also return to zero. The
material is said to behave elastically in this interval and is
the reason for referring to Point A as the elastic limit.
Ultimate Strength
Elastic deformation represents an actual change in the D B
X
distance between atoms of a material when a load is A
Plastic Region
applied. When the load is released, the atomic structure C
F
returns to its original position.
Y
A stress/strain plot of the release will follow the same line STRESS
OY. There is no permanent damage or deformation to the
material when the stresses are in this range.
Elastic Region

If the applied stress is in the range AB, e.g., Point X, and

is then released, a stress/strain plot of the release will not O
follow a line XO. STRAIN E

Although the stress returns to zero, a strain (Z) will remain,

i.e., there is some permanent change to the material. Figure 7. General stress/strain plot.

Page 9 of 15
 Section 120
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING LIMITS

2.1.1 Stress Applied in the Well strains a majority of the time. As a result a multiaxial
stress/strain analysis is required to determine the com-
The CT is straightened by the injector-head chains, and the bined stress to which the CT is being subjected.
string weight is then held by the chains. Below the chains
the CT is usually hanging freely in the well (except in The graph in Figure 8 depicts the combined effect of the
deviated/horizontal holes). The CT stresses are always three primary strains due to continuous reciprocation of the
within the elastic region except in very extreme cases. CT at the surface.

Although other stresses are present, the primary stress Point 0 on the graph represents the tubing after being stress
acting on the CT in the well is tension. relieved at the factory but before it has been spooled onto
a reel for the first time (it has never been bent).
Factors that can affect CT tension are buoyancy, well
geometry (frictional drag), obstructions and stuck pipe. If Tubing which has never been bent behaves elastically. As
the tubing becomes stuck in the hole and the operator CT is spooled onto a reel, the material is subjected to
continues to pull on the CT, the tension in the tubing would combined postyield strains equivalent to Point 1.
increase until the yield stress is reached and the CT would
then begin to plastically deform. Once it is spooled, it is then called CT and practically the
entire cross section is plastically deformed. This can be
Once the ultimate stress of the material is reached, a failure observed by cutting a section of tubing from the reel and
will occur. Normally, the CT would break just below the laying it on the ground. The CT is no longer straight but is
injector head if this were allowed to happen. curved due to the residual stress in the CT which is induced
by plastic deformation.
Torque can be applied to the tubing string in several ways.
The tubing will follow a helical path down the wellbore and However, tubing that has been plastically deformed will still
effectively produce a minimal torque stress value. How- behave elastically, e.g., if a 3-ft length of 1-1/4-in. CT is
ever, the most severe case of torque stress arises when bent 2 in. and the force is then removed, the CT will return
downhole motors are run. As larger and more efficient to its original shape.
motors are developed, consideration of torque is becoming
a limiting factor. Point 2 of the plot corresponds to residual strains which
remain after the tubing has been rolled off of the reel and
2.1.2 Stress Applied at the Surface straightened as it approaches the gooseneck.

A characteristic of bending strain is that the bottom portion As the tubing is again bent over the gooseneck, combined
of the tubing decreases in length, resulting in a negative strains increase to those at Point 3. Restraightening the
bending stress and strain (compression). The top portion tubing within the injector head creates a strain reversal to
increases in length, resulting in a positive bending stress Point 4. A subsurface tensile load lower than the yield point
and strain (tension). of the CT material is represented at Point 5.

The hoop strain may be simply stated as the diametral On pulling out of the hole, the pipe returns through the
growth of the CT due to high internal pressure. chains and travels over the gooseneck (point 6).

The radial strain becomes a significant factor once the wall As the cycles accumulate, the combined strain increases
thickness is reduced, because of the combination of the until the ultimate strain is exceeded and the pipe fails
hoop and bending strains. (fatigue). At the point of failure, the final stress will have
been produced, which has in turn caused the tubing to reach
One strain acting independently will cause less severe its ultimate strain.
results than a combination of strains simultaneously pro-
duced. In fact, the CT is subjected to a combination of

Page 10 of 15
 COILED TUBING SERVICES MANUAL Section 120
CT STRING LIMITS Rev A - 98

COMBINED
STRESS
3,7
1 3 6 RUPTURE

2,8 ield
Y
Stress
4,6

1,9
STRAIN

(-)

2 4

Figure 8. Stress/strain diagram for CT during spooling.

2.2 CT String Fatigue Testing

Extensive industry tests (Schlumberger Dowell 1988 - cases is severe, e.g., during one of the tests at 5000 psi
1990) revealed two physical, easily measurable phenom- with 1-1/4-in. CT, the pipe ballooned from its original 1.25
ena which can be exploited in the field to predict the effects in. out to 1.47 in.
of fatigue and so be used to apply operating limits. Field
systems were developed to track the condition of the tubing Under static conditions, the levels of pressure that are
string with respect to these phenomena and correlate them typically applied will not result in any permanent deforma-
to the fatigue life of a CT work string. tion, because the associated stresses are well within the
elastic limit. However, when the tubing is being bent
• Bending Under Pressure sufficiently to make the bending stress plastic, any other
stress that is applied at the same time will also have plastic
There is a distinct relationship between the number of trips strains associated with it. This applies even if these
to failure and the simultaneous internal pressure. The additional stresses applied individually would be elastic.
higher the internal pressure, the less the number of trips to Therefore, bending the CT with a high internal pressure, i.e.,
failure (e.g., 199 trips at 300 psi versus 41 trips at 5000 psi). greater than 3000 psi, will cause some diametric growth.
If there is a butt weld within the section, the number of trips
to failure will be dramatically reduced due to the changed If the CT is bent with no internal pressure, there will be no
metallic structure in the HAZ. significant growth in diameter.

• Diametric Growth Approximately 60% of the CT jobs performed have an

applied internal pressure greater than 3000 psi. Therefore,
The CT grows in diameter as trips are made with an internal the majority of CT workstrings will be subject to ballooning
pressure applied. This growth is significant and in some in the sections that have been cycled at a higher pressure.

Page 11 of 15
 Section 120
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING LIMITS

From the results of the fatigue testing program, the follow- • The initial cracking (which initiates failure) usually begins
ing systems were developed: on the inside surface of the tubing.

• A fatigue tracking system with on-site data acquisition for • The sequence and cumulative effect of pressure and
a reel database. A computer model can then be used to bending cycles must be considered to determine CT life.
predict the remaining life of the CT work string.
• The CT behaves elastically when subjected to an internal
• A real-time tubing inspection system which accurately pressure alone. However, when the CT is bent at the
measures the diameter of the CT to alert operating same time, the CT then behaves plastically.
personnel if the predefined dimensional limits of the CT
are exceeded • Bending strains remain essentially constant to failure at
all pressure levels; however, hoop strains increase with
Other significant findings during testing influenced how increasing internal pressure.
tracking system results are interpreted and operations are
planned: • Test measurements showed that CT will either not
lengthen or only lengthen slightly with an applied internal
• The CT fails at the maximum diameter of the ballooned pressure, and that most of the damage is caused by
portion and generally on the underside. In the vast diametric growth (ballooning).
majority of the tests, this occurred while passing over the
gooseneck coming out of the hole. • The longitudinal weld does not effect CT string longevity.

• At the beginning of the tests, the CT assumes an elliptical • Thicker walled pipe gives a longer cycle life.
shape such as that shown in Figure 9.
• The smaller the OD of the CT, the more cycles that can
• The top portion of the CT often conforms to the shape of be made before failure.
a wave just before failure as shown in Figure 10. The
wave shape is more pronounced at higher internal pres- • The less skate tension, the longer the tubing life.
sures and barely visible at lower internal pressures.

Typical new tubing Flattening with Oversize tubing just

Ideal geometry geometry repeated passes prior to failure Y

X X

Figure 9. CT string ovality changes.

Page 12 of 15
 COILED TUBING SERVICES MANUAL Section 120
Schlum berger
CT STRING LIMITS Rev A - 98

acting on the CT under given wellbore and treatment

conditions. It is thereby possible to predict the loads on the
CT string, enabling efficient job design prior to the opera-
Wave pattern on tubing tion.
surface.
Model outputs are used to assist in the design of safe and
reliable CT operations by predicting the maximum depth
which a tool string may be run in horizontal and highly
deviated wellbores. A plot of the anticipated weight indica-
tor load against the measured depth is used during the job
as a means of checking and interpreting any anomalous
Figure 10. Fatigue induced deformation.
conditions.

• The tests with the butt weld revealed the regions of Most models or calculations used to determine forces
localized plastic deformation were located approximately acting on the CT divide the well and tubing string into
0.2 in. on either side of the weld, in the HAZ. sections or elements. The resultant load is then calculated
for each component in each element. In this way it is
• Reversing the direction of curvature also reduces the life possible to examine the effects over the length of the tubing
of the CT. Reversal of the CT is commonly caused by and not only at the top or bottom of the tubing string.
positioning the levelwind too low. Theoretical predictions
suggest that as much as a 25% reduction in the life of the The forces identified below have varying effects on the CT
CT may result if a reversal is present on every trip string performance.
throughout the life of the CT.
Buoyant Weight
• Although a section of CT fails, the remainder of the string
is not affected in the same manner as the failed section This is the weight of the CT, taking into account the effect
unless subjected to exactly the same conditions. There- of internal and external fluids, their density and correspond-
fore, the entire string should be evaluated to determine ing buoyancy effect.
whether it should be repaired or discarded.
The buoyant weight of each element in the string has a
tensile effect on the other elements in the tubing string.
3 CT STRING FORCES
Well Profile
When CT is run into or pulled out of a vertical well, it is
relatively easy to predict what will be the indicated weight The profile of a well or completion can affect the load or
of the tubing string. The tubing weight per foot, or meter, is force applied to the tubing string in two ways.
known so the weight of the string will correspond to the
length hanging in the well, with some correction being made • Low Side Drag - The buoyant weight of a tubing string,
for the effects of buoyancy. Thus, the weight of the string which is lying against the low side of the well, will vary with
as shown on the weight indicator display on the surface the deviation of the well. As the deviation changes, the
gives a primary indication of the forces being applied to the amount of friction due to buoyant weight will also change.
CT downhole.
• Belt Effect - When tubing is placed in tension around a
In highly deviated wellbores, the forces required to push the curve, the tubing is forced against the inside surface of
CT along the wellbore cannot be accurately determined by the well tubular. This causes a corresponding increase in
the weight indicator display alone. A number of forces friction. The belt effect may be induced by changes in
which act on the CT must be taken into account to predict deviation and azimuth.
the loads that the tubing will be subjected to in the wellbore.
Computer programs are available which model the forces

Page 13 of 15
 Section 120
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING LIMITS

Residual Bend be reached where the tubing snaps from being sinusoidally
buckled to being helically buckled.
When the CT is injected through the stripper, the tubing will
be bent with a radius of curvature of about 24 ft. This bend As with sinusoidal buckling, the wave pattern is dependent
is referred to as the residual bend and originates from on the CT and well tubular dimensions and is within the
storing the CT in a plastically deformed state on the reel. As elastic range of the CT. The direction of the helix will change
the tension on the CT string is increased, as a result of over the length of the buckled section of tubing, thus the
string weight or applied tension, the tubing will straighten. cumulative effect of rotation and induced torque over the
When the tension is decreased, the tubing will again form total length of the buckled section is zero.
a residual bend.
When the tubing is helically buckled, the resulting helix
The principal effect of the CT residual bend occurs as applies force against the side of the well tubular. However,
compressive force is applied to the string and buckling is the tubing can still be moved further into the wellbore. The
initiated. increased friction caused by forcing the tubing further into
the wellbore causes the period of helix to shorten, which in
Buckling turn further increases the friction. At a certain point, the
friction forces become greater than the force pushing the
Compressive force exerted on the CT string during normal tubing. When this point is reached, it is impossible to push
operations in deviated wells may result in buckling of the the tubing further into the wellbore. This condition is referred
string in two distinct modes. to as helical lockup.

• Sinusoidal buckling Following helical lockup, it will still be possible to inject

tubing into the well; however, this will only result in
• Helical buckling increasing the amount of buckled tubing in the well. The
BHA cannot be pushed further into the well following helical
The force required to push CT into a horizontal or deviated lockup. Determining the point at which lockup occurs is a
well increases as the tubing is pushed further along the major element of CT job design work in horizontal and
wellbore. When the force reaches a certain level, the CT will deviated well applications.
snap into a sinusoidal wave pattern (Figure 11). The load at
this point is referred to as the sinusoidal buckling load or Where the wellbore contains a curvature, either as a result
critical buckling load. of deviation or azimuth change, the sinusoidal and helical
buckling loads will be increased. This is due to the in-
The period and amplitude of this sinusoidal waveform is creased support the well tubulars afford to the CT. Increas-
dependent on the dimensions of the CT and well tubular in ing the compressive force tends to stabilize the CT by
which it is contained. However, since the period will be very forcing it into the trough of the curve. A larger force is
long in comparison with the amplitude, any bending of the required to move the CT out of the trough into a sine or
CT will be within the elastic range and no plastic deforma- helical waveform.
tion or damage will be caused to the tubing.
Fluid Turbulence
The orientation of each sine wave varies, giving the
appearance of helically buckled tubing. However, the When fluid is flowing at high rates through the CT or through
important difference between sinusoidal and helical buck- the surrounding annulus, the CT will tend to vibrate. This
ling is that helically buckled tubing will contact the wall of vibration will effectively decrease the friction between the
the well tubular throughout the period, whereas sinusoidally CT and the well tubular in which it is contained.
buckled tubing does not.
Stripper Friction
When downward force is applied to a sinusoidally buckled
work string, the tubing will continue to move further into the The seal provided by the stripper to secure well pressure
well. As the force required continues to increase, a point will causes a friction force to be applied to the tubing. When the

Page 14 of 15
 COILED TUBING SERVICES MANUAL Section 120
Schlum berger
CT STRING LIMITS Rev A - 98

Sinusoidal buckling Helical buckling

Figure 11. CT buckling characteristics.

stripper operating pressure or wellhead pressure is in- Tubing Reel Back Tension
creased, the friction caused by the stripper seal area will
also increase. The amount of back tension applied to the CT between the
reel and injector head will affect the value shown on the
When operating at high wellhead pressures, this friction weight indicator display. This is due to the design of the
becomes a significant factor. In extreme cases the friction injector head frame pivot and location of the weight indica-
imposed by the stripper seal area may make it difficult to tor load cell.
inject the CT through the stripper assembly.
Although the CT reel back tension does not affect the actual
Wellhead Pressure stress in the tubing below the drive chains, it must be taken
into consideration in to accurately predict the weight
Wellhead pressure acts on the CT by creating an upward indicator reading which will be displayed and recorded.
force which tends to force the tubing out of the well. The
chart in Fig. 8 shows a plot of force against wellhead
pressure for various CT sizes.

NOTE: This chart shows the calculated effect of wellhead

pressure only.

Page 15 of 15
This page left blank
 Section 130
COILED TUBING SERVICES MANUAL
Rev A - 98

CT STRING MAINTENANCE

Contents Page

Introduction .................................................................................................... 2
1 CT STRING MAINTENANCE ......................................................................... 2
2 CT STRING DAMAGE AND DEFECTS .......................................................... 3
2.1 Cracks ................................................................................................ 3
2.2 Pitting.................................................................................................. 4
2.3 Abrasion .............................................................................................. 4
2.4 Mechanical Damage ............................................................................ 5
2.5 CT String Geometry ............................................................................ 6
2.6 String Damage Assessment ................................................................ 6
3 CT STRING WELDING ................................................................................... 7
3.1 Weld Related Problems ....................................................................... 7
4 CT STRING STORAGE .................................................................................. 8

Page 1 of 8
 Section 130
COILED TUBING SERVICES MANUAL Schlum berger
Rev A - 98 CT STRING MAINTENANCE

Introduction If possible, the string should then be blown through with

nitrogen. In addition to removing potentially corrosive
There are several conditions which may effect CT string fluids, displacing the string with nitrogen substantially
reliability as a direct result of inadequate care and attention reduces the weight of the reel. This will aid in the handling
being (maintenance). In the majority of cases, the conse- of skid-mounted reels and reduce the effect of impact loads
quences are not immediate, but instead will lead to a rapid on the reel bearings and structure.
worsening of condition (e.g., accelerated fatigue) ultimately
leading to string failure significantly before predicted or The use of a foam pig is recommended to increase the
anticipated. efficiency of the nitrogen displacement. This is especially
effective where nitrogen gas bottles are used, because the
The principal objectives of pre- and post-job maintenance initial displacement rate is very low and a considerable
procedures is to: slippage of fluid will take place around the reel. Confirma-
tion must be made that the pig has passed from the tubing.
• Prevent or control internal and external surface corrosion
which may effect string performance. Cement and Particulate Materials

• Prevent restrictions to the workstring drift diameter. The removal of cement and particulate materials is impor-
tant for two principal reasons:
1 CT STRING MAINTENANCE
• To avoid a restriction on the low side of the reel, formed
The variety of applications and fluids to which a CT string by settling material.
may be exposed is considerable. To aid in determining the
action to be taken, recommendations for postjob mainte- • Solid materials which have settled can interfere with the
nance are grouped as follows: operation of downhole equipment on subsequent opera-
tions.
• Noncorrosive fluids.
Flushing the string as described above should ensure that
• Cement and particulate materials. the reel is free from internal buildup or restriction. However,
the flushing should be conducted at as high a rate as is
• Acid or corrosive fluids. practical. The water leaving the reel should be inspected to
check for continued contamination. The addition of a gelling
• Cold weather precautions. or slicking agent. As above, the minimum volume should be
1.5 times the volume of the string. Displacing the string with
• Wireline reels. nitrogen is then recommended.

Noncorrosive Fluids Acid and Corrosive Fluids

On completion of an operation, fluids that are potentially Following an operation involving acid or corrosive fluids, a
corrosive are flushed from the CT string. The flushing fluid pill of neutralizing solution should be pumped through the
should be clean, fresh water or the best available alterna- string. Typically, the pill will be a solution of soda ash or
tive. The recommended minimum volume of fluid that caustic (depending on availability) and should be at least
should be flushed through the string is 1.5 times the string one half the volume of the string. A commonly used
volume. formulation is 50 lb soda ash in 10 BBL clean water. This
should then be followed by the flushing and displacement
procedures described above.

When a neutralizing or passivating solution is flushed

through the reel, consideration must be given to the
appropriate disposal of the waste fluid.

Page 2 of 8
 COILED TUBING SERVICES MANUAL Section 130
CT STRING MAINTENANCE Rev A - 98

Cold Weather Precautions Damage to CT strings can be broadly classified as follows:

Ice plugs can easily form and cause a restriction in a CT • Cracks

string during cold weather. Considerable damage can be
caused, up to and including a rupture, if the weather • Pitting
conditions are severe.
• Abrasion
To prevent this, the flushing and purging process should be
completed to obtain as dry a string as is practical. A foam • Mechanical damage
pig displaced with nitrogen is recommended. If conditions
require, a quantity of antifreeze solution should be pumped • Geometry
behind the pig prior to nitrogen displacement. This should
ensure that any liquids left in the string as a result of 2.1 Cracks
slippage will be freeze protected.
Cracks are generally regarded as a serious form of defect
2 CT STRING DAMAGE AND DEFECTS since the stresses applied to a CT string in normal use can
only make the defect worse. Once initiated, cracks can
Damage and defects can have a significant effect on the propagate relatively quickly, jeopardizing the safety and
performance of a CT string. However, there are currently no reliability of the string. Consequently, it is common for any
“industry accepted” guidelines regarding acceptance or string section identified with cracks to be removed and
rejection criteria for CT strings with damage. Similarly, repaired.
there are no agreed de-rating factors with which a safe early
retirement of the CT string could be planned. The majority of cracks are caused by fatigue (fatigue
cracks) and are often wrongly identified as pinholes when
the crack has penetrated the wall thickness.

Transverse crack
Longitudinal crack

Angled crack

Figure 1. CT string defects - cracks.

Page 3 of 8
 Section 130
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MAINTENANCE

Three crack “modes” are recognized for detection pur- • Internal - Resulting from exposure to improperly inhibited
poses: corrosive treatment fluids, or (more commonly) failure to
adequately flush or passivate the internal surface before
• Transverse cracks - Run around the circumference of the storage.
tube. Transverse cracks can grow very quickly due to the
stress applied to the tube when bending. This form of • Weld bead - The weld bead can provide a protective site
crack is the most common defect identified in used CT for the initialization and rapid progression of localized
string. corrosion.

• Longitudinal cracks - Run along the axis of the tube. These 2.3 Abrasion
are less common but may propagate rapidly to form a split
in the tube under severe stress. Damage resulting from abrasion or round dents typically
effect string performance as a result of reduced wall
• Angled cracks - Not a common configuration but typically thickness:
associated with a bias weld.
• Round dents - Have less effect on fatigue than sharp
2.2 Pitting notches or cracks but can still significantly affect string
performance.
Pits are typically associated with localized corrosion which
can occur on the internal and external surfaces of the tube. • Abrasion - Localized wall loss can occur as a result of
A variation of internal pitting is associated with damage to abrasion with wellbore tubulars, i.e. at contact points of
the longitudinal weld bead (Figure 2): the buckled (sinusoidal) tube.

• External - Resulting from contact with corrosive treatment • Longitudinal scratches - Can result from contact with
fluid or wellbore fluids, atmospheric corrosion or a com- sharp edges in the wellbore, pressure control equipment
bination of each. or CT equipment. If undetected, the scratch may extend
for several thousand feet. Although the scratch may have
little direct effect on string performance it may indirectly
lead to accelerated localized corrosion or fatigue.

Internal pitting

Weld bead pitting

External pitting

Figure 2. CT string defects - pitting.

Page 4 of 8
 COILED TUBING SERVICES MANUAL Section 130
CT STRING MAINTENANCE Rev A - 98

Round dents

Localized
abrasion

Longitudinal sctratch

Figure 3. CT string defects - abrasion.

2.4 Mechanical Damage

Mechanical damage of CT strings was once commonplace accelerated fatigue at that point. Current slip designs
– and was indirectly responsible for many string failures. It apply a “toothed” pattern over a longer interval to reduce
is now realized that marks and indentations hitherto thought these effects.
insignificant can greatly affect the performance of a string.
• Chain marks - May result from misaligned chains,
• Slip marks - Early slip deigns were configured with slip incorrect tension or damaged chain blocks. A repeating
teeth which formed semicircular indentations or marks. pattern will probably result.
These resulted in localized stresses and significantly

Modified slip
marks

Old style slip

marks
Injector head chain
(repeating)

Injector head chain

(repeating)

Figure 4. CT string defects - mechanical damage.

Page 5 of 8
 Section 130
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MAINTENANCE

2.5 CT String Geometry • Accelerated or unpredictable fatigue:

material loss
Variations in string geometry cause problems with handling material structure
equipment (injector head chains) and pressure control stress concentration
equipment (stripper, slip rams, pipe rams, etc.). In addition,
many string performance models (fatigue, pressure and • Gross geometry changes:
tension, etc.) are based on algorithms which assume that compatibility with handling and pressure control equip-
the tube is circular and the wall thickness is constant (with ment
allowance for tapered strings). If the actual geometry of the deviation from geometry used in model predictions
tube is different, the predictions may no longer be within an
acceptable margin of error. In the worst case, a reduction in string performance will may
become apparent with an unexpected string failure. How-
• Ovality - All tubing is out of round from the first time it is ever, it is more common that the damaged area does not fail
spooled. The maximum recommended ovality limits for immediately, but will causes localized fatigue at an accel-
any CT string is typically around 6% erated rate. Ultimately a failure will occur before the
predicted useful (safe) life of the string is achieved. Only
• Necking - generally caused by over stressing a section of upon close examination will the original damage or defect
tubing be identified as a contributory cause.

• Ballooning - most frequently the result of cycling (bending) The issues associated with identifying CT string damage
under high pressure can be broadly categorized as follows:

2.6 String Damage Assessment Detection

The effect of CT string damage and defects include: CT string inspection:

• Reduction in string performance: • Hardware and software may both used to assist in
reduced burst and collapse pressure capacities inspecting CT strings. Much of the hardware and software
reduced tension and compression capacity associated with CT string inspection is still being devel-
oped and does not have a proven track record.

Ballooning

Necking

Ovality

Figure 5. CT string defects - string geometry.

Page 6 of 8
 COILED TUBING SERVICES MANUAL Section 130
CT STRING MAINTENANCE Rev A - 98

• Location/time of inspection – should the inspection be • Tension

carried out while RIH, POH, spooling, periodically or
continuous. • Fatigue

Assessment • Geometry

Physical measurement or estimate – once an indication is String records must always be clearly marked to identify
found that a defect exists, how is the extent of the defect derating.
measured?
3 CT STRING WELDING
• Subjective assessment – what are the guidelines for
assessing a defect that cannot be measured? Gas Tungsten Arc Welding (GTAW) is currently the pre-
ferred welding technique for tube-to-tube welding of coiled
Classification tubing. In some cases, Shielded Metal Arc Welding (SMAW)
is used. SMAW is less desirable due to inherent process
• Nature of defect – does the defect cause an immediate limitations for thin-walled, small diameter tubing.
hazard?
A high quality weld has several desirable characteristics
• Acceptance criteria – at what level of severity does each regarding strength, hardness, dimensions and fatigue life.
type of defect become hazardous?
• The tensile load capacity of the weld and the heat affected
• Go/no go – ultimately a decision must be made as to zone should equal or exceed the specified strength of the
whether the CT string can or cannot be used. pipe body.

Once string damage has been identified, steps must be • The outer diameter of the weld should be within the
taken to resolve each defect. If the defect is discovered dimensional tolerances of the pipe body.
during an operation, the implications for that operation have
to be considered, and a decision made as to whether the • The wall thickness through the weld area should equal or
operation can continue. Consideration must also be given exceed the pipe body thickness, but internal restrictions
to the implications for future operations (e.g. subsequent should be minimized.
runs in the hole).
Ideally, the fatigue life of the weld and heat affected zone
The condition of adjacent tubing must be investigated. An should approach that of the pipe body; however, long weld
assessment must also be made as to whether there is any fatigue life has not been achievable in the past.
significant life remaining in the undamaged portion of the
string. If there is, the options are to repair or derate the string 3.1 Weld Related Problems
or part of the string. This means that the string may still be
used operationally, but with a diminished capability. Even Coiled tubing string welds can fail in service due to very low-
if damage is localized, it may be necessary to derate the cycle fatigue failure. Weld fatigue life can be reduced by a
entire string, e.g., the pressure capacity of the entire string variety of conditions, such as:
must be derated in the case of localized wall thinning.
• Root concavity
A clear decision must be made on whether the derating is
permanent or interim. An interim derating may apply, for • Internal inclusions
example, until a more accurate assessment of the damage
is possible. The implications must be considered for the • Planar weld defects
following factors:
• Porosity
• Pressure

Page 7 of 8
 Section 130
COILED TUBING SERVICES MANUAL
Rev A - 98 CT STRING MAINTENANCE

• Grinding marks External

• Corrosion pits As with internal protection, inhibitors are used to keep

corrosion to a minimum on the external surface of a CT
• Sharp re-entrant angle of cap or root pass string. To prevent the occurrence of surface rust, the
following conditions must be met:
• Heat affected zone softening
• The tubing surface must be clean and free from corrosive
• Poor internal flash transition from longitudinal weld fluids or moisture.

• Incomplete joint penetration • A suitable protective coating must be applied to the entire
tubing surface.
A comprehensive program of non-destructive testing and
inspection is essential for maintaining CT weld quality. • The coating must not interfere with the operational use of
tubing, measurement or well control equipment.
4 CT STRING STORAGE
• The coating and its means of application must not cause
When coiled tubing is to be stored, even for a relatively a hazard to personnel or environment.
short period of time, several considerations should be
made to ensure that the work string and associated • The best external protection can only be applied to the
documentation package are kept in a satisfactory condi- tubing’s external surface as it is being spooled onto the
tion. reel (either during operation or during maintenance proce-
dures).
Coiled tubing is made of carbon steel materials which can
quickly corrode when exposed to atmospheric, industrial
and marine environments. Such corrosion can occur on the
inner surface of the tubing (internal corrosion), as well as on
the outer surface (external corrosion).

Internal

Internal corrosion has an obvious detrimental effect on the

working life of a CT string. Small amounts of moisture
condensing inside the tubing can cause localized corro-
sion, leading to thinning of the tubing wall and stress risers.

An internal corrosion inhibitor is applied to ensure that the

coiled tubing is delivered in as close to as-manufactured
condition as possible. This inhibitor protects the CT under
various transportation and storage conditions, but does not
adversely affect tubing performance.

Once the string has been used, the protection of internal

surfaces begins with the flushing and neutralizing of the reel
contents. Subsequent purging with nitrogen is frequently
required to allow safe loading and transportation of the reel.
Whenever possible and practical, reels should be blown dry
with nitrogen to minimize the residual fluid which collects at
the bottom of the tubing wraps.

Page 8 of 8
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98

COILED TUBING UNIT

Contents Page
Introduction .................................................................................................... 2
1 COILED TUBING INJECTOR HEAD ............................................................... 2
1.1 Description ........................................................................................... 2
1.1.1 Principal Functions ............................................................................... 2
1.2 Features ............................................................................................... 3
1.2.1 Drive and Brake Systems .................................................................... 3
1.2.3 Traction and Tension Systems ............................................................ 11
1.2.4 Guide Arch Assembly ........................................................................ 13
1.2.5 Weight Indicator ................................................................................. 14
1.2.6 Depth Measurement Equipment ......................................................... 14
1.2.7 Stripper Mount ................................................................................... 14
2 COILED TUBING REEL ................................................................................ 15
2.1 Description ......................................................................................... 15
2.2 Features ............................................................................................. 16
2.2.1 Reel Drum .......................................................................................... 16
2.2.2 Reel Drive/Brake Systems ................................................................. 18
2.2.3 Reel Swivel and Manifold ................................................................... 19
2.2.4 Levelwind Assembly .......................................................................... 20
2.2.5 Tubing Measurement Accessories ...................................................... 21
2.2.6 Tubing Lubrication Equipment ............................................................. 21
2.2.7 Crash Protection Frame ...................................................................... 21
3 CT POWER PACK ........................................................................................ 21
3.1 Description ......................................................................................... 21
3.2 Features ............................................................................................. 22
3.2.1 Power-Pack Engine ............................................................................ 23
3.2.2 Hazardous Area Designation .............................................................. 23
3.2.3 Zone II Engine Protection Equipment ................................................. 23
3.2.4 Hydraulic Pumps ................................................................................ 24
3.2.5 Pressure Control Valves ..................................................................... 24
3.2.6 Hydraulic Fluid Reservoir .................................................................. 25
3.2.7 Filters and Strainers ........................................................................... 25
3.2.8 Hydraulic Fluid ................................................................................... 25
3.2.9 Accumulator ....................................................................................... 26
4 CONTROL CABIN ........................................................................................ 26
4.1 Description ......................................................................................... 26
4.2 Features ............................................................................................. 28
4.2.1 Injector Inside Chain Tension .............................................................. 28
4.2.2 Injector Outside Chain Tension ........................................................... 28
4.2.3 Injector-Head Drive ............................................................................. 29
4.2.4 Reel Controls ..................................................................................... 29
4.2.5 Lubrication Controls ........................................................................... 29
4.2.6 Engine Controls .................................................................................. 30
4.2.7 Blowout Preventers (BOP) ................................................................. 30
4.2.8 Strippers ............................................................................................ 30
4.3 Operating Technique ........................................................................... 31
4.4 Instrument Scanning .......................................................................... 32
5 CTU COMPONENTS - APPROXIMATE SIZES ............................................ 33

Page 1 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

Introduction The following functions apply to the majority of injector

heads.
There are many different designs and configurations of CT
unit. Most have evolved over a relatively short period as the • Pull the CT string
understanding of criteria critical to the reliability of CT
services have become better understood. In addition, the • Push the CT string
operating conditions in many geographical areas often
determine the most appropriate CTU design. • Hold the CT string

Regardless of manufacturer, model and design, every CTU • Guide and support the CT string
comprises the following principal items.
• Secondary/support functions include:
• Injector head
• Weight indicator mount
• CT reel
• Depth system mount
• Power pack
• Stripper mount
• Control cabin

• Pressure control equipment Pull (Tensile Force)

The following section provides an overview of these items The injector head pull capacity should be compatible with
of CT equipment, describing their function and principal the weight of the CT string in use plus:
components or subsystems.
• Effect of fluid density inside/outside the CT string

1 COILED TUBING INJECTOR HEAD • Overpull (tension) to be applied at the BHA

1.1 Description • Effect of drag (friction) caused by the string or BHA

The coiled tubing injector head provides the effort and • Friction or drag created by the stripper(s)
traction necessary to run and retrieve the CT string into and
out of a wellbore. Several hydraulic systems are used to Push (Snubbing Force)
enable the coiled tubing unit (CTU) operator to exercise a
high degree of control over any CT string movement. A The injector head snubbing capacity should be compatible
thorough understanding of the injector head control and with:
monitoring systems is essential to ensure the equipment is
operated efficiently, safely and without risk of damage to • The force required to overcome the wellhead pressure
the well equipment, pressure control equipment, CT string
or the CTU. • Acting on the cross-sectional area of the CT string

1.1.1 Principal Functions • Friction or drag created by the stripper(s)

The basic functions required of all CT injector heads Hold

includes safely pulling, pushing and holding the CT string
under the specific wellbore and treatment conditions. The injector head should be capable of safely holding the
However, there are several secondary or support functions CT string stationary. This holding function should be
that are vital to ensure safe and reliable CT operations. available with the hydraulic systems or power pack in both

Page 2 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

normal operating conditions and disabled modes. In addi- The global CTU fleet includes several injector head models,
tion, the transition from stationary to in-hole and out-of-hole the most common of which are shown below.
modes should be smooth and easily controlled.
The explanation of systems and components in this manual
Guide the tubing section will be generic although some of the more signifi-
cant variations in design, specification and operation may
Components of the injector head (guide-arch or gooseneck) be outlined.
serve to support and guide the CT string from the delivery
(fleet) angle of the reel into the wellbore. The principal features and components of injector heads
are illustrated in Figures 1 through 5.
Weight indicator mount
The capacity (maximum pull) of an injector head is the
Injector heads are typically configured with the traction and major factor in determining the operating capability of the
drive components mounted on a “floating” inner chassis. CTU. The table in Figure 5 summarizes the key perfor-
This is contained within a fixed outer frame with the weight mance data and specifications of common injector head
indicator sensor(s) connected between the two frames. models

Depth system sensor The principal components of an injector head can be

categorized in the following systems or major assemblies.
The injector head provides a convenient mounting position
for friction wheel depth measurement systems. At least two • Drive and brake system
independent sensors are typically required on every CT
operation, e.g., one reel mounted and one injector head • Chain assembly
mounted system.
• Traction and tension system
Stripper mount
• Guide-arch assembly
The primary stripper is generally permanently mounted to
the injector head. Unless the injector head is otherwise In addition, secondary or support systems, include:
supported, the mounting point bears all of the forces
necessary to run and retrieve the CT string. The stripper • Weight indicator
mount also provides a reference point with which the drive
chains and guide-arch are ultimately aligned. • Depth sensor mounts

1.2 Features • Stripper mount

The design and configuration of injector heads have devel- 1.2.1 Drive and Brake Systems
oped over several years to meet specifications which
reflect the evolving nature of CT applications. The trend Note: The injector head drive and brake systems are
toward larger tubing sizes which enable greater circulation capable of exerting high forces on the CT string, wellbore
rates, requires the injector head be capable of handling a tubulars or wellhead equipment. Significant damage may
wider range of tubing. Similarly, since CT has commonly result if the systems are not operated, controlled or moni-
become the preferred intervention method in extended tored correctly. Therefore, it is vital that the CTU operator
reach or horizontal wells, the “average string” length has is aware of the design and layout of the specific system in
increased in recent years. These factors, especially in use. The operator must be familiar with the location and
combination, demonstrate the increased demands being setting of the system control and relief valves. In addition,
placed on injector heads and other key items of CT handling the limitations of the CT string must be understood when
equipment. adjusting system pressures etc. to avoid the application of
excessive force to the string.

Page 3 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

Gooseneck

Lubricant reservoir

Stripper assembly

Injector drive motor

Inside chain
tension system

Accumulator

Stripper assembly

Figure 1. Typical injector head.

Page 4 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

Figure 2. - Hydra-Rig HR 480.

Figure 3. - Hydra-Rig HR 440. Figure. 4 Stewart and Stevenson SS 400.

Page 5 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

R T- 20

M A R I TI M E H YD R AU L I CS ( CA N) L TD .
CA L
G AR Y, ALB ERTA, CANA DA

Figure 5. Stewart and Stevenson SS 800.

Injector Model Approximate Dimensions Snub Pull CT Size Range

Height Width Depth Weight Capacity (in.)
(in.) (in.) (in.) (lb) (x1,000 lbs)

HR240 164 52 55 7,800 20 40 1 to 1-3/4

HR260 180 52 55 9,200 20 60 1 to 2-3/8

HR440 80 52 55 6,750 20 60 1 to 2-3/8

HR480 109 60 60 11,200 40 100 1-1/4 to 3-1/2

SS 400 82 42 58 5,700 20 40 3/4 to 3-1/2

SS 800 82 42 58 6,125 20 80 3/4 to 3-1/2

Figure 6. Injector head specification table.

Page 6 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

All injector heads currently in common use are hydraulically Some early injector heads are equipped with hydraulic
driven using either two or four hydraulic motors. The motors brakes controlled manually from the control console. On
are typically connected and synchronized through a gear early models of Uniflex injector heads, external pneumati-
system located at the top of the injector head. Drive is cally operated disc brakes were fitted.
directed to the chain drive sprockets (one for each injector
chain set) via the drive shafts located at the top of the Several injector head hydraulic motors are equipped with an
injector head. internal speed shift facility which provides a high/low gear
option that can be selected remotely from the CTU the
The direction of rotation and speed of the motors is control console. Two speed capability allows the injector
controlled and shifted by a four-way hydraulic control valve head to operate more efficiently with the available hydraulic
located on the CTU power pack. The functions of the power supply, i.e. supply pressure and rate. When set in low
hydraulic valve, plus the hydraulic system pressure and speed mode the injector drive motors can apply maximum
rate, are remotely controlled from the CTU control console. torque or pulling force. In high speed mode, available pulling
force is typically halved and the running speed doubled.
Protection devices, such as pressure relief valves and
crossover relief valves, are installed in the system to The injector head drive system includes several compo-
protect the tubing and hydraulic components from damage nents necessary for control and safety purposes. Almost
due to operator error or component failure. all injector heads are equipped with two pilot-operated
counterbalance valves, located on the injector drive sys-
The injector-head brake is generally mounted integral to the tem lines between the drive motors and the pressure filters.
motor assembly and is hydraulically controlled. Hydraulic The valves function as load holding valves by closing the
pressure is required to release the brake so the system is motor outlet line until a pilot pressure, obtained from the
considered fail-safe in operation. Application of the brake is motor inlet line, is sufficient to open the valve. This
typically automatic and controlled by the drive system arrangement enables a smooth transition between station-
hydraulic pressure, i.e., the brake is applied when the drive ary and operating modes. In addition, it enables the weight
system hydraulic pressure falls below a preset value. of the CT string to be supported by the hydraulic fluid
trapped by the counterbalance valve, effectively providing

Figure 7. CT chain assembly on tubing

Page 7 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

a fail-safe facility in the event of brake failure. operating the pilot valve on the control console. These
systems enable the operator to preset the maximum force
The hydraulic lines between the counterbalance valves and that can be applied to the tubing.
the motor are high-pressure welded steel pipe. This is a
safety feature since the line can contain hydraulic fluid at Some injector heads are offered with auto-driller control
high-pressure while the string load is held by the counter- options. The purpose of auto driller control systems is to
balance valve. increase the operator’s ability to control the injector head at
very slow speeds, such as may be encountered during
High pressure filter assemblies are fitted on the injector drilling operations. Most systems also enable finer control
head to protect the motor from extraneous materials which of the force exerted on the tubing.
may be trapped during rig-up of the drive hose connections.
1.2.2 Chain Assembly
Hydraulic Supply System Overview
The majority of injector heads are configured with two sets
Coiled tubing units are designed with two basic options for of opposing endless chains on which are mounted a series
the primary injector drive hydraulic system, i.e., open or of gripper blocks. The gripping profile of each block is
closed loop. Actual operation of the injector head and CTU precisely shaped to suit a specific tubing size. To facilitate
differs little between the two systems, however, each larger tubing sizes and the increasing range of sizes
system has associated advantages and disadvantages. commonly used, chain designs with removable gripper
inserts are commonly specified on most new injector
System pressure is controlled by pilot operated relief heads. The gripper insert enable a range of tubing sizes to
valves located on each circuit. The maximum pressure for be run without the need to remove and replace the entire
each circuit is preset by adjusting the relief valve (typically chain assembly. This facility reduces the time and effort
located on the power pack). The system pressure can then required to reconfigure the injector head when running a
be controlled from zero up to the preset maximum by different size of CT string. In addition, gripper inserts

Figure 8. HR240/260 chain assembly

Page 8 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

reduce the inventory items (quantity and cost) required for predicted fatigue life of the string. Consequently, the effect
replacement when the gripper contact area becomes worn, of any components and equipment in contact with the string
or redressing when another tubing size is to be run. surface should be understood and carefully monitored.
The force required for the chain to provide adequate grip on
the tubing string is provided by the inside chain tensioner The majority of chain systems are assembled from stan-
system (also known as the skate system or traction dard ANSI chain components and custom built parts
tensioner system). This force is applied to the back of the enabling relatively easy replacement of worn or damaged
chain assembly. To enable the chains to rotate easily with items. The principal chain components and assemblies
relatively high loads applied, the chains are fitted with commonly found on injector heads are shown below. A
bearings which roll smoothly over the tensioner system relatively recent chain design featuring a single chain
components while transmitting the load. traction system is also included.

Some special applications may require tapered OD string HR 240/260 Chain Assembly
to be run, e.g., 1-1/2-in. and 1-3/4-in strings joined and hung
off in a velocity string installation. The ability to change the The HR 240/260 chain assembly incorporates a single
chain gripper inserts as the tubing join passes through the piece gripper block design which is compatible with only
injector head provides a clear advantage in such applica- one tubing size. This design was generally regarded as the
tions. industry standard until the introduction of chain with re-
placeable inserts. With the introduction of larger tubing
The entire CT string load is held by the face of the gripper sizes, a limitation of the single piece gripper resulted from
block or insert. This is often achieved under significant the limited space afforded by the relatively small chain
force. Therefore, the selection, operation and maintenance pitch used in early injector heads. Larger pitch chains were
of chain components should be undertaken with a view to introduced on some injector head models, However, the
minimizing the risk of damage to the CT string and flexibility of the insert chain system brought obvious
optimizing the life expectancy of consumable components. advantages.
Recent studies indicate that even relatively light damage
on the string surface can have a significant effect on the

Figure 9. HR480 chain assembly.

Page 9 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

Figure 10. SS800 chain assembly.

Figure 11. Dreco Chain Assembly - open. Figure 12. Dreco Chain Assembly - closed.

Page 10 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

HR 480 Chain spring loaded locking pin which protrudes from the carrier
block into the back surface of the insert.
The HR 480 chain assembly incorporates carrier blocks
each of which contains two gripper inserts. The inserts are The Varia-Block chain system is designed so the as-
supported by elastomeric elements which help ensure an sembled chain has a flat back which rides on the rollers
even application of the gripping force transmitted to the CT mounted on the chain tension or traction system, i.e.,
string. This system is designed to reduce the risk of unlike conventional chains the Varia-Block chain assembly
distorting the CT string when high loads are applied in deep has no roller bearings.
or heavy-duty applications. The gripper block contact face
is machined with a smooth surface and profile to minimize DRECO Chain
the risk of damaging the CT string surface. Gripper inserts
are available in a range for 1-1/4-in. to 3-1/2-in. The DRECO chain and drive system features a unique
single chain system. A hinged gripper assembly is housed
Gripper inserts are secured to the carrier block by a detent in a carrier assembly (bucket) which in turn is attached to
profile and held in place by a locking pin which locates the drive chains. The chain assembly is aligned with the
through the side of the carrier block. tubing axis thereby reducing eccentric loading on the chain
and gripper components. In addition, the hinged gripper
SS 800 Chain arrangement ensures that the gripping force is isolated from
the drive chain components. These features are intended
Stewart and Stevenson injector heads are equipped with to provide smooth operation and long component life.
the Varia-Block chain system which can be fitted with
gripper inserts to suit a range of CT string sizes from 1-in. Gripping force is applied to the tubing through the action of
through to 3-1/2-in. The gripper insert is secured within the the hinged gripper block. The cam rollers on the griper block
gripper block by a detent profile and locked in place by a arms are forced closed by pressure beams which are in
effect the equivalent of conventional skates or tensioner
bars. Hydraulic rams are used to control the force applied
by the pressure beams using a control and monitoring
system similar to convention hydraulic tensioners.
Chain Lubrication

Injector head chains are submitted to significant forces and

a high degree of movement during operation. To ensure the
components function efficiently over an optimized chain
life, efficient lubrication of moving components is required.
This should be achieved without jeopardizing the essential
friction between the tubing and the gripper block or insert.
The lubricating oil is typically SAE 30, or equivalent.

The fluid reservoir and control manifold are typically mounted

on the injector head enabling the system to be remotely
activated from the CTU control cabin. In addition to lubricat-
ing the chain components, the lubrication system is also
sometimes used to lubricate the timing gears which syn-
chronize the multiple motor and chain drive train.

1.2.3 Traction and Tension Systems

The injector head traction or inside chain tensioner system,

Figure 13. HR240/260 chain tension assembly. (also known as the skate system) provides the force

Page 11 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

required to securely grip the tubing in the chain gripper

blocks. The necessary force is provided by a hydraulic To ensure adequate tension is maintained in the chain
system which is typically split into three distinct sub- section outside the vertical drive plane, the injector head is
systems, i.e., top, middle and bottom traction systems. fitted with an outside chain tensioner system. Current
This enables some flexibility in operation and provides a production injector-head models are equipped with a hy-
high degree of contingency or back-up for one of the most draulic tensioner system which is controlled and monitored
important injector head functions. from the control console. Hydraulic rams provide the
tension by acting on the external idler gears. The idler gears
The inside chain tensioner pressure required during a CT are allowed to float horizontally allowing both chains to be
operation is a function of the tubing load, size, condition, tensioned with a single set of rams. Early injector head
gripper-block condition and presence of oil or similar designs required that the tension be checked and adjusted
between the tubing and block. Since the consequences of manually through a mechanical adjustment mechanism.
attempting to run CT with too little inside tension on the
chains can be catastrophic, the natural tendency of the The chain tension applied is based on the injector-head
operator is to apply excessive pressure to the system. manufacturer’s recommendations for the specific operat-
While in operating terms this should ensure adequate ing conditions. The outside chain tension is critical while
control over the tubing slip, it will almost certainly be the tubing is being injected with a negative load on the
sufficient to significantly affect the life span of the injector injector chains (while snubbing against high wellhead
chain bearings and the CT. pressures). Damage to the CT string and chain drive
components may result if outside chain tension is not
The force is hydraulically applied through three separate properly applied under these conditions.
sets of hydraulic cylinders. Each set is independently
controlled and monitored from the control cabin. The use of
three separate sets reduces the risk of a major operating
failure should a component in the system fail.

Recommended Guide Arch Radii

Coiled Typical Reel Typical Tubing

Tubing OD Core Radii Guide Arch Radii
(inches) (inches) (inches)
0.750 24 48
1.000 20-30 48-54
1.250 25-36 48-72
1.500 30-40 48-72
1.750 35-48 72-96
2.000 40-48 72-96
2.375 48-54 90-120
2.875 54-58 90-120
3.500 65-70 96-120

Figure 14. Comparison of guide arch sizes and recommended guide arch radii.

Page 12 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

1.2.4 Guide Arch Assembly

The gooseneck and pipe straightener (where fitted) act as

a guide, turning the tubing through the angle between the
wellhead and the CT reel. The CT string is supported by
rollers located at ±10-in. intervals around the gooseneck
circumference. The top rollers used to restrain the tubing
are removable to enable easier installation and removal of
tubing from the injector head. The guide arch rollers are
typically profiled with a “V” of 120° and may be manufac-
tured from steel, aluminum or polyurethane. Most guide
arch designs incorporate a flared end which reduces the
risk of damage to the tubing caused by misalignment when
the tubing is being spooled to the edges of the reel drum.
This is especially noticeable when the reel is located close
to the injector head.

The guide arch radius has a significant influence on the

fatigue induced in the CT string, e.g., a 50 in. radius guide
arch will have a more detrimental effect on tubing life than
a 72-in. radius guide arch. Guidelines extracted from API
RP 5C7 are shown in Figure 14 for various tubing sizes.

The pipe straightener, where fitted, is located immediately Figure 15. Weight indicator equipment.
above the injector head. It performs two main functions.

Figure 16. Depth measurement equipment.

Page 13 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

• Ensures the tubing is as straight as possible before 1.2.6 Depth Measurement Equipment
entering the injector-head chains.
Depth measuring equipment, electronic or mechanical, is
• Guides the tubing cleanly into the injector-head chains, frequently mounted on the injector head. Depth information
thereby reducing damage caused by misalignment. is commonly gathered by two methods.

The pipe straightener generally consists of one adjustable • Mounting a friction-wheel-type counter assembly between
roller located between two fixed opposing rollers. the injector chains and stripper, or

1.2.5 Weight Indicator • Mounting an encoder assembly to the injector-head chain

drive shaft.
The weight-indicator load cell (or strain gage on electronic
weight indicators) is typically located on the lower front 1.2.7 Stripper Mount
edge of the injector head. The weight or load information is
transmitted, from the load cell to the weight-indicator dial or The outer frame of the injector head is equipped with a
display, either electronically or hydraulically. stripper mount facility which secures the injector head to
the pressure control stack. The stripper is generally perma-
The injector-head frame is typically constructed in two nently bolted in place. With the injector head outer frame
distinct assemblies comprising the inner and outer frames fixed to the pressure control stack and the inner injector
(see Stripper Mount section). Pivot points between the head assembly supporting the tubing string, some limited
frames enable the weight-indicator load cell to accurately movement is allowed to ensure correct alignment and
measure the force between the assemblies. Such force operation of the weight indicator load cell.
may act up or downward, resulting from the weight of the CT
string (tension) or action of high wellhead pressure (com- In some larger models of injector head, the stripper is
pression). mounted on a subassembly which can be removed during
transportation.

Tubing
measurement
and coating
accessories

Levelwind
assembly

Reel drum

Figure 17. Typical CT reel configuration.

Page 14 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

2 COILED TUBING REEL Almost all reels rely totally on hydraulic power to operate
the drive, braking and spooling guide (levelwind) systems.
2.1 Description Previous reel designs have used pneumatics, or a combi-
nation of pneumatics and hydraulic power, to control some
The primary function of the coiled tubing reel is to safely of the brake and levelwind systems.
store and protect the CT string. This should be achieved
while avoiding excessive damage to the string through The reel levelwind is frequently used as a mounting position
fatigue (bending) or mechanical damage from spooling. In for a variety of tubing protection, monitoring and measuring
addition, the reel typically incorporates several features equipment.
which, although less obvious, are equally important to the
successful operation of the CTU. Most significant of which Figures 17 identifies the principal components of a typical
is the swivel facility which enables fluids to be pumped CT reel.
through the tubing string while the reel drum rotates.

Figure 18. Truck mounted reel (fixed). Figure 19. Truck mounted reel (skid).

Figure 20. Skid mounted reel. Figure 21. Special application reel.

Page 15 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

2.2 Features The evolution of CT string sizes and the general trend
toward longer CT work strings has resulted in many
CT Reels are commonly available in a number of configu- different reel designs, many of which are still in common
rations and can be categorized as shown below. Local use. However, the facilities and components identified
conditions and the nature of the CT operations will deter- below are found on almost all reels:
mine the type of reel required.
• Reel drum
• Truck mounted (fixed) - permanently fixed to the truck
chassis (Figure 18) • Reel drive and brake systems

• Truck mounted (skid) - may be changed out (Figure 19) • Reel swivel and manifold

• Skid mounted - for offshore operations (Figure 20) • Levelwind assembly

• Trailer mounted - for large capacity (length) or heavy • Depth measurement accessories
weight strings
• Tubing lubrication equipment
• CT logging reel - fitted with electrical swivel/collector
• Crash protection frame
• Special application reel - typically for completion applica-
tions (Figure 21) 2.2.1 Reel Drum

With the advent of larger CT sizes, that are installed as The reel drum assembly typically consists of a reel drum,
completion tubulars, there is increased use of special reels axle, flanged connection on the axle to allow the swivel to
and spooling stands designed to handle large tubulars. be connected, and chain sprocket on the axle by which the
These structures typically enable the shipping spool to be drum is driven. A second chain sprocket on the axle is often
fitted in place of the drum assembly, thereby avoiding used to drive the levelwind leadscrew. Direct drive reels
unnecessary spooling, which in large tubing sizes can be have a motor and gearbox mounted directly on the axle. The
difficult and hazardous. reel axle bearings are mounted and secured on support
posts which form part of the reel chassis.

Page 16 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

A facility to lock the reel drum while being transported is

Freeboard required on all reels. This is commonly achieved by
securing with a chain and binder between the reel drum rim
and a point on the reel chassis. This must be in addition to
A
any hydraulic or pneumatic brake which is operated from
the control cabin. Reels that have wireline installed require
a modified axle to allow an electrical collector to be fitted to
the axle.

The theoretical tubing capacity (Figure 22) of any drum can

C be calculated using the procedure shown below. This
method of calculation assumes perfect spooling across the
width of the drum. Since in practice this is difficult to
achieve, an allowance must be made to maintain the reel
capacity within its practical limitations.

L = (A+C) (A) (B) (K)

where:
L = tubing capacity (ft)
B A = tubing stack height (in.)
B = width between flanges (in.)
C = reel drum core diameter (in.)
K = K value for different tubing sizes.
Figure 22. Reel drum capacity.

Figure 23. Reel back tension.

Page 17 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

The K values for different tubing sizes are: 2.2.2 Reel Drive/Brake Systems

Tubing OD (in.) K value All reels are hydraulically driven, although the control
1 0.262 system and type of motor vary between manufacturers and
1-1/4 0.168 reel models. Most reels can be powered in an “in-hole” and
1-1/2 0.116 “out-hole” direction. However, during normal operations,
1-3/4 0.086 only the out-hole option should be selected, since it is the
2 0.066 action of the reel drive motor in this direction that provides
2-3/8 0.046 the back tension applied to the CT string while running in
2-7/8 0.032 and out of the well.
3-1/2 0.021
The hydraulic pressure in the drive system can be varied to
control the torque output of the motor which allows the
The freeboard is the amount of clearance between the OD tension on the tubing (between the injector head and reel)
of the reel flanges and the OD of the wrapped tubing at to be varied. Generally, only sufficient tension to keep the
maximum capacity (L). The minimum recommended free- tubing straight between the reel and injector head should be
board varies with the tubing size: applied (Figure 23). Applying excessive tension may result
in premature failure of the hydraulic and drive components
Tubing OD (in.) Freeboard (in.) or damage to the tubing. This combined with incorrect
1 and 1-1/4 1.5 spooling will almost certainly result in some tubing damage.
1-1/2 and 1-3/4 2.0
2 3.0 The amount of hydraulic pressure required to achieve a
>2 10.0 satisfactory tension will depend on the amount of tubing
contained on the reel and the distance from the injector

Figure 24. Typical reel manifold configuration.

Page 18 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

head. The distance from the reel axle to the top tubing wrap rated within the motor assembly. This is set/released by a
may be regarded as a lever through which the drive system dedicated hydraulic circuit which is controlled from the
torque must be transmitted to tension the tubing string. The control cabin.
greater the distance, the more torque will be required to
maintain a constant tension. To increase the torque output Generally, the reel brake is applied whenever the tubing is
of the drive system, the hydraulic pressure must be stationary. However, consideration must be given to the
increased. Therefore, while pulling out of the well, the consequences of actions or operations which may affect
distance from the reel axle to the top wrap is increased, the stability of the CT string in the injector head, e.g. if high-
requiring that the hydraulic pressure in the drive system density fluid is to be pumped through the CT at depth, the
must be increased to keep a constant tubing tension. While increase in weight may cause the CT to slip through the
running in the hole (RIH), the pressure required to maintain injector chains. With the reel brake applied, the resulting
sufficient back tension will reduce as the number of wraps force/tension would then be applied to the reel.
on the drum is reduced.
2.2.3 Reel Swivel and Manifold
In addition to the torque changes with varying reel capacity,
the change in weight will also affect the pressure required The design and configuration of reel swivels and manifolds
to drive the reel. This is particularly noticeable when vary according to the manufacturer and model of the reel.
starting from rest especially when the reel contains high- Early models were of simple design and often contained
density fluids or electric cable. threaded connections on the swivel or manifold. It is a
requirement many organizations that all treating equipment
The reel drive motor is either mounted on the base of the be of integral or of non-pressure union construction. This
reel chassis, or mounted directly on the axle. If mounted on restriction also prevents the use of Swagelok fittings to
the reel chassis, it is connected by a chain and sprocket to connect the tubing end within the reel core. Therefore, the
the reel axle. CT string is typically terminated with a 1502 Weco union
which has been welded in place and has undergone the
Reel brake systems may be air or hydraulically operated. required quality control procedures.
Most current models have a hydraulic reel brake incorpo-

Figure 25. Reel levelwind assembly.

Page 19 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

All reels should have a valve fitted as close as practical to

the end of the CT string. This valve can be closed in the
event of a swivel seal failure while the CT is being run,
thereby isolating the contents of the string. Reels that have
wireline installed require a modified manifold to enable
wireline access (pressure bulkhead) downstream of the
isolation valve.

The reel fluid manifold is generally considered in two parts

- the external manifold which consists of treating iron
outboard of the swivel, and the internal manifold which is
mounted within the reel core.

2.2.4 Levelwind Assembly

Accurate and even spooling of the CT onto the reel drum is

important for several reasons:

• Badly spooled damage is liable to damaged at the contact

points. Even apparently minor surface damage can affect
tubing life or performance.
Figure 26. UTIM device mounted on CT reel
levelwind. • For the reel drum to achieve maximum capacity the CT
must be properly spooled.

Figure 27. CTL reel configuration.

Page 20 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

• Poorly spooled tubing may shift and slacken on the reel which is used to transmit power and data between the BHA
while being transported. This may result in damage or and surface equipment.
problems when the tubing is drawn from the reel for the
next operation. The following items are required to complete the surface
equipment hook-up associated with the CT reels to be used
• Corrosion protection of the external surface is more on coiled tubing logging operations:
effective if the tubing is closely and evenly spooled.
Pressure Bulkhead (PBH)
To help achieve a satisfactory spooling standard, the
levelwind assembly guides the tubing onto the reel drum The pressure bulkhead is used to allow electrical connec-
and automatically follows the progress of the spooling tion of the reel mounted electrical components to the
tubing. A manual override facility allows minor adjustments logging cable inside the CT string. This must be achieved
to be made to the position of the levelwind head when while maintaining the pressure integrity of the reel manifold.
required. In addition, some vertical adjustment of the
levelwind assembly is necessary to allow the fleet angle of Reel Collector
tubing to suit the equipment rig-up.
The reel connector is used to allow an electrical connection
2.2.5 Tubing Measurement Accessories to be made between the cable in the rotating reel core and
the surface electrical equipment.
The levelwind travelling head provides an ideal mounting
position for friction wheel depth counters or encoders. 3 CT POWER PACK
Back-up mechanical counters that display large-sized
digits can, in most cases, be read from the operator’s 3.1 Description
console. The travelling head also provides the mounting
position for tubing monitoring equipment such as the Dowell The function of the power pack may be simply stated as
Universal Tubing Integrity Monitor (UTIM) device. providing the hydraulic power to operate the coiled tubing
unit (CTU) and pressure control equipment, e.g., BOP
2.2.6 Tubing Lubrication Equipment system. To perform this function satisfactorily under var-
ied conditions and for the duration of any coiled tubing (CT)
Current reel designs include a fixed tubing lubrication/ operation, current generation power packs are designed to
inhibition system, part of which is permanently mounted on operate independently of exterior power or air supplies once
the reel chassis, with the control system located on the started.
operator’s console.
In addition to the hydraulic power supplied when running,
2.2.7 Crash Protection Frame the power pack incorporates an accumulator facility to
allow limited operation of pressure control equipment fol-
The degree of protection required depends on anticipated lowing engine shutdown.
application and use of the CTU (e.g. offshore skid-mounted
or truck-mounted reel). In addition to the practical efficiency A compressor mounted on the engine provides an air
of the crash frame, consideration must be given to the supply for operation of the engine controls and pneumatic
requirements of certifying or regulatory authorities. For systems on the CTU, e.g., the stripper air-operated pump,
example, a DNV certified unit for offshore use must have injector-head chain lubrication, lights and transfer pumps.
a fitted reel roof, coated with a non-slip material, to assist The power-pack air receiver will provide sufficient storage
the seamen in attaching the load to the crane hook. to allow an engine restart shortly after shutdown, provided
the unit pneumatic systems are isolated.
2.2.8 Wireline Reels
The environment in which the CTU is to operate will
Wireline reels are used in CT logging operations and determine the engine protection facilities required by the
incorporate a logging cable installed inside the CT string relevant local and national authorities. For example, off-

Page 21 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

Lay er 1 High Exhau st Low Oil Lo ss of

TemhpCoola
Hig eratu re
nt Tem pe ratu re Pre ssure C oola nt

Coo lant Oil

Te mper atur e Pr essu re

En gine
Tach omet er
Per missive
star t

St art
Eng ine Em ergen cy
Air
Kill Kill Pr essur e

Figure 28. CT power pack.

shore skid units operating in the North Sea are required to continuing satisfactory operation of all CTU functions. The
be fitted with an engine (and electrical, where fitted) importance of the relevant power-pack checks being thor-
protection package that allows the unit to be operated in oughly and regularly completed is obvious. In addition the
Zone II areas, hence the designation of Zone II unit. completion of the required reports will provide a useful
record of the power unit performance, identifying possible
The CTU configuration will determine the location of the problems before the operation of the CTU is affected.
power pack and corresponding control equipment.
3.2 Features
• Truck or trailer mounted using the truck engine as a power
source. The majority of CTUs in use are assembled by Hydra-Rig.
The evolution of CTU design to the current standards has
• Truck or trailer mounted with an independent power resulted in several different designs of the power pack
source. being supplied. Figure 28 shows the power pack/control
cab skid from a three-piece Hydra-Rig CTU.
• Skid mounted with the control cab and power pack
incorporated on one skid, designated a three-piece unit, In general, all power packs will include the following major
i.e., control cab/power pack, reel and injector-head/BOP components:
transport basket.
• Engine
• Skid mounted with the control cab mounted separately
from the power pack, designated as a four piece unit. • Hydraulic pumps

Regardless of the type of unit to which the power pack is • Pressure Control Valves
fitted, the function and facilities contained within the power
pack will be similar. • Hydraulic Reservoir

Successful operation of the CTU requires the delivery of • Filters and Strainers
precisely controlled hydraulic power on demand. Mainte-
nance checks performed on the CTU, such as those • Hydraulic Fluid
identified in the CT STEM program, are designed to ensure

Page 22 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

• Heat Exchanger and Thermostatic Valve Engine instrumentation will generally include the following.

• Accumulator • Oil Pressure Gauge

Operation, or even start-up of the CTU power pack, must • Coolant Temperature Gauge
not be attempted until a series of maintenance and opera-
tional checks has been completed. Failure to follow the • Air Pressure Gauge
prestart-up procedure may expose equipment and person-
nel to unacceptable risks. • Ammeter (where applicable)

The prestart-up operational checks will vary with the 3.2.2 Hazardous Area Designation
location and application of the CTU but should include the
following points as a minimum requirement. Engines and electrical equipment are often required to be
specially protected or isolated before their use is permitted
• Ensure any location requirements, such as a permit to in certain environments.
work systems, are complied with fully and that actions
need for such requirements have been completed, e.g., The identification of designated hazardous areas or zones
positioning of gas detecting and fire-fighting equipment. in and around wellhead and process plant areas is the
principal basis upon which equipment suitability is as-
• Ensure operating and associated personnel are aware of sessed. The extent of the zoned area is generally deter-
the above requirements, and that only qualified personnel mined by the relevant national authorities. Consequently,
are authorized to operate the equipment. international variations exist both in terminology of areas
and in the extent to which they apply; however, zoned areas
3.2.1 Power-Pack Engine will generally be based on relevant API guidelines.

Almost all engines fitted to CTU power packs are of the The inspection and certification of equipment as being in
General Motors Detroit series. They may be of 8V, 6V or compliance with the operator’s standards are often con-
(more recently), six cylinder, in-line configuration. Coiled ducted by third-party inspection companies. Examples are
tubing units manufactured after 1990 are likely to be fitted Det Norske Veritas (DNV) and the American Bureau of
with Caterpillar engines. This is primarily due to the superior Shipping (ABS).
engine noise and emission control specifications achieved
by the Caterpillar engine. 3.2.3 Zone II Engine Protection Equipment

Engine controls are likely to be remotely operated from the Diesel engine driven equipment that is intended for use
control console and from the engine control panel located within Zone II areas and which is in compliance with the
on the power pack. Some three-piece units may only be most rigorous standards set by operating companies will
equipped for single-station operation, i.e., all engine con- typically be fitted with the following engine protection
trols are located on the operator’s console. equipment.

The following engine controls are found on standard engine • Air-inlet shutoff valve - designed to shut down the engine
sets. when an overspeed condition is detected by increased
airflow through the shutdown valve or by the overspeed
• Engine Start governor, where fitted.

• Engine Stop • Liquid-cooled exhaust gas manifold/heat exchanger.

Designed to maintain engine surface temperatures below
• Emergency Kill 392°F (200°C)

• Engine Throttle • Exhaust gas spark arrestor and flame trap

Page 23 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

Open loop: Return flow to reservoir Directional,

pressure and Load holding
flow control (counterbalance)
valves valves
Injector head
Fixed
drive motors
displacement
pump

Closed loop:

Directional Crossover
control relief
valves valve
Injector head
Variable
drive motors
displacement
pump

Figure 29. Open and closed loop hydraulic systems.

• Engine breather and air-box breather flame traps Balanced vane-type hydraulic pumps for this application
are commonly supplied by Abex Denison. Most of the
• Screw-secured oil-filler cap and dipstick models used are high-performance double pumps, thereby
allowing two separate hydraulic systems to be run from one
• Heavy-duty radiator pump assembly. In this case, the pump contains two
separate pump cartridges supplied by a common suction
• Plastic blade fan line but having separate discharge ports. The construction
of the pump body allows cartridges of a different size, and
The protection package will initiate engine shutdown in two therefore output, to be fitted. Consequently, the output
ways. capability of the hydraulic pump array is tailor made to the
requirement of the system it supplies.
• In the case of engine overspeed, by closing the air-inlet
shutoff valve. 3.2.5 Pressure Control Valves

• In the case of high exhaust temperature, high water Each hydraulic circuit must be fitted with a device to control
temperature and low engine oil pressure, by cutting off the the maximum pressure within the system. On Hydra-Rig
fuel supply, generally by an actuator moving the engine CTU hydraulic circuits, this is achieved in several ways.
fuel rack.
• Preset relief valves
3.2.4 Hydraulic Pumps
• Pilot-operated relief valves
The hydraulic pump array will vary with the model and
manufacturer of the CTU. The hydraulic systems on most • Unloader valves
CTUs consist of balanced vane type pumps operating in an
open-loop system (Figure 29).

Page 24 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

Preset Relief Valves 3.2.7 Filters and Strainers

This type of valve is manually adjusted and set to the The hydraulic fluid and system are kept clean by passing
maximum desired pressure in the system. Once this the fluid through filters and strainers as it flows through the
pressure is reached, the relief valve lifts allowing excess circuits.
flow to be directed back to the hydraulic reservoir. This
action imparts considerable energy to the hydraulic fluid, A strainer is a coarse filter, commonly made from wire
causing the system temperature to rise if the valve relieves mesh, which is generally fitted to the suction line inside the
over a prolonged period. reservoir. The strainer is generally specified by a mesh
number or standard sieve number.
Pilot-Operated Relief Valves
Filters retain much smaller particle sizes than strainers and
Pilot operated relief valves are similar to preset relief are commonly located on the reservoir return lines. Filters
valves, but have the additional facility of allowing the relief are generally specified by a micron number and as being
pressure to be remotely controlled by a pilot control valve either nominal or absolute. A nominal filter rated at 10
connected to the relief valve by a pilot control line. The micron will trap most of the particles of that size; however,
pressure may be remotely varied up to the preset maximum an absolute filter will trap all particles of that size and
setting of the relief valve. greater.

Unloader Valve In addition to the filters placed in the reservoir return lines,
some circuits have an in-line filter installed upstream of the
Unloader valves are similar to relief valves, but differ in that valve gear, particularly where there is a limited flow through
when the preset maximum pressure is reached, the valve the system, e.g., on the priority supply line to the Monsun
reacts to isolate the system and direct the flow to the Tison valve, the main control valve of the injector head.
reservoir under no load. When the system pressure is
reduced, the valve opens to recharge the system, closing Many filter assemblies incorporate a filter condition indica-
again when the desired pressure is reached. Unloader tor. This simply gives some indication of the differential
valves are commonly fitted to systems that require little pressure being applied across the filter. A filter which is
flow during operation and that are also fitted with accumu- partially plugged will create a larger differential, the indica-
lators. Hydraulic circuits that supply BOP operating pres- tion of which is commonly displayed by a colored indicator
sure are generally fitted with an unloader-type valve. system. A green display during operation is normal; a red
display indicates the filter requires changing. In addition to
3.2.6 Hydraulic Fluid Reservoir this feature, or as an alternative, a bypass system may also
be incorporated into the filter assembly. This allows fluid to
The hydraulic fluid reservoir performs several functions. bypass the filter should the back pressure caused by a
blocked, or partially blocked filter, become too severe.
• Stores the hydraulic fluid
3.2.8 Hydraulic Fluid
• Allows the fluid to cool
The hydraulic fluid has four main functions
• Allows settling of dirt and metal particles
• Power Transmission - to transmit power efficiently, the
• Allows entrained air to be released. fluid must flow easily through lines and components.
Resistance to flow caused by friction will result in power
The reservoir is generally mounted high in the power pack loss. The fluid should also be as incompressible as
to provide a positive head of pressure at the hydraulic pump possible to transmit power immediately on start-up.
suction port. Suction lines from the reservoir to the pumps
are commonly fitted with strainers and isolation valves. • Lubrication - most hydraulic components are lubricated by
the fluid; therefore, for a long component life, the fluid

Page 25 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

should contain the necessary additives to ensure high Accumulators fitted to the power pack generally contain an
antiwear characteristics. internal bladder which is precharged with nitrogen. The
precharge pressure is dependent on the application and
• Sealing - in many cases, the close mechanical fit and volume of the accumulator. For example, the BOP circuit
hydraulic fluid provide the only seal against leakage is fitted with a large-capacity accumulator which, when fully
within the hydraulic component. Therefore, the mechani- charged, will allow limited operation of the BOP following
cal fit and fluid viscosity will determine the leakage rate. shutdown of the power pack.

• Cooling - heat generated by the components in the system 4 CONTROL CABIN

is dissipated by the fluid as it passes through the lines and
reservoir. 4.1 Description

In addition to the four main functions of the fluid, a number The control cabin contains all of the controls and instru-
of other quality requirements are desirable. ments necessary to allow the CT operation to be run from
one control station. The location of the control cabin will
• Prevent rust, corrosion or pitting. vary depending on the configuration and type of the coiled
tubing unit; however, the cabin is generally situated behind
• Prevent sludge formation. the CT reel, in line with the wellhead/injector head. To help
achieve maximum visibility from the control station, the
• Depress foaming. cabin is commonly elevated.

• Maintain stability over a wide temperature range. The level of control and instrumentation fitted will greatly
depend on the model and version of the CTU. However,
• Separate out water. typical design objectives include ability to:

• Be compatible with seal and gasket materials. • Control and monitor the operation of all of the CTU
operating functions.
The excess generation of heat and associated problems is
a relatively common problem in incorrectly designed or • Control and monitor the operation of well pressure control
operated hydraulic systems. To combat this potential equipment.
problem and to assist with heat dissipation during periods
of high load or high ambient temperature, most CTUs are • Monitor and record the principal well and CT string
equipped with a heat exchanger. parameters of wellhead pressure, circulating pressure,
tubing weight at the injector head and tubing depth.
Heat exchangers may rely on air or water to cool the fluid,
and are generally located on a main reservoir return line. The principal benefit of this comprehensive control and
This ensures that the majority of the fluid passing through instrument package is that it provides the operator with an
the system goes through the heat exchanger. increased awareness of the CTU operating conditions. This
in turn provides three important prerequisites that are
3.2.9 Accumulator crucial to achieving adequate service quality:

Hydraulic systems that operate at a static pressure and • The CTU can be operated safely and efficiently.
have a low fluid flow rate are commonly fitted with accumu-
lators. In this application, the accumulator performs two • Potential problems can be identified and rectified before
functions. they interfere with the operation of the CTU.

• Energy storage (e.g., BOP accumulator) • An accurate CT string work record is developed, based
on the primary factors which influence the useful life of the
• Shock absorption (e.g., tensioner circuit accumulator). tubing.

Page 26 of 33
 COILED TUBING SERVICES MANUAL Section 210
Schlum berger
COILED TUBING UNIT Rev A - 98

EMERGENCY
SHEAR RAM BLIND RAM TRACTION SUPPLY
CLOSE OPEN CLOSE OPEN INJECTOR OUTSIDE
TENSION PRESSURE CLOSE OPEN
150 PSI MAX

INSIDE TRACTION
PRESSURE DRAIN AIP SUPPLY
INJECTOR INSIDE PRESSURE
TRACTION PRESSURE ENGINE EMERGENCY
B 1500 PSI MAX STOP STOP
O ON
SLIP RAM P PIPE RAM
30 GPM
CLOSE OPEN CLOSE OPEN OFF PUMP

PRESSURE BLEED
ON
60 GPM
TOP OFF PUMP
TUBING WEIGHT INDICATOR
ON PRESSURE
OFF OFF THROTTLE
ON CIRCULATING PRESSURE WELLHEAD PRESSURE
REEL BRAKE
OFF
INSIDE TRACTION
BOP SUPPLY SUPPLY PRESSURE
AIR HORN
BOP PRESSURE BOP SUPPLY PRESSURE
MIDDLE INSIDE TRACTION
PRIORITY PRESSURE INJECTOR DIRECTIONAL
Schlumberger
ON PRESSURE 2,000 PSI MAX CONTROL VALVE
STRIPPER STRIPPER PILOT PRESSURE Dowell
#2 #1 OFF PRESSURE ADJUST
REEL PRESSURE

IN INJECTOR CHAIN
LUBRICATION
RETRACT NEUTRAL PACK RETRACT NEUTRAL PACK

UP HIGH

STRIPPER SYSTEM PRESSURE BOTTOM

5000 PSI MAX LEVELWIND INJECTOR OUT
ARM SPEED INJECTOR INJECTOR MOTOR
#2 #1 ON PRESSURE MOTOR PRESSURE PRESSURE ADJUST REEL PRESSURE REEL TUBING
STRIPPER STRIPPER INJECTOR ADJUST
OFF LUBRICATION
DOWN LOW CONTROL LEVELWIND REEL CONTROL
STRIPPER OVERRIDE
PRESSURE ADJUST
AIR REG. CONTROL

Figure 30. Typical control panel layout - flat panel.

CLOSE OPEN

INSIDE TRACTION
PRESSURE DRAIN
BOP PRESSURE STRIPPER #1 STRIPPER SYSTEM STRIPPER SYSTEM SYSTEM
PRESSURE PRESSURE PRESSURE AIR PRESSURE

TUBING WEIGHT INDICATOR

STRIPPER PRESSURE BLEED
BOP SYSTEM STRIPPER #2 BLEED INSIDE TRACTION CHARGE PRIORITY
PRESSURE PRESSURE SUPPLY PRESSURE PRESSURE DEPTH SYSTEM PRESSURE
OUTSIDE TENSION
INJECTOR WELLHEAD PRESSURE CIRCULATING PRESSURE

SHEAR RAM BLIND RAM NEUTRAL INSIDE TRACTION

EMERGENCY
CLOSE OPEN CLOSE OPEN RETRACT PACK TRACTION SUPPLY

ON OFF
STRIPPER PRESSURE ADJUST
#1 INJECTOR LUBE REEL LUBE

HIGH LOW ON OFF

B INJECTOR
O CONTROL
SLIP RAM P PIPE RAM ON OFF
INJECTOR REEL BRAKE ENGINE EMERGENCY
CLOSE OPEN CLOSE OPEN STOP
TOP TRACTION 2 SPEED STOP
INJECTOR TOP IN REEL BRAKE
TRACTION CYL. PRESSURE Schlumberger
Dowell
NEUTRAL
RETRACT PACK
ON OFF

STRIPPER MIDDLE TRACTION

#2 OUT
BOP SUPPLY INJECTOR MIDDLE INJECTOR REEL PRESSURE
AUX BOP TRACTION CYL. PRESSURE ADJUST ADJUST
ON
CLOSE OPEN
OFF INJECTOR SLOW THROTTLE
SPEED CONTROL
ON OFF

BOTTOM TRACTION LEVELWIND LEVELWIND REEL CONTROL

STRIPPER
PRESSURE ADJUST INJECTOR BOTTOM INJECTOR CONTROL INJECTOR MOTOR REEL PRESSURE OVERRIDE ARM
TRACTION CYL. PILOT PRESSURE PRESSURE AIR HORN

Figure 31. Typical control panel layout - split panel.

Page 27 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

4.2 Features Inside Traction Pressure Adjust

Controls and instruments can be grouped by function as This is a pressure reducing valve used to adjust the
follows. hydraulic pressure to the cylinders (increase and decrease
pressure). The hydraulic supply is from the priority circuit
• Injector chain inside tension (2,000 psi); the maximum chain tension pressure should
not exceed 1,500 psi.
• Injector chain outside tension
Inside Traction Supply Pressure Gauge
• Injector-head drive
Displays system pressure as determined by the pressure
• Reel adjust valve.
·
• Lubrication controls Control Valve (3)

• Power unit May be used to isolate each of the three inside chain
tension cylinder sets.
• BOP
· Pressure Gauges (3)
• Stripper
· Displays the hydraulic pressure downstream of the control
• Principal gauges valves.
·
• Emergency hydraulic supply equipment Inside Traction Pressure Drain
·
• Electronic equipment This valve is used to bleed pressure from the system when
the control valves are open. Caution must be exercised
The illustrations in Figure 30 and Figure 31 show typical when opening this valve when tubing is suspended in the
console layouts. injector chains because a sudden drop in the cylinder
pressure will result. Fine pressure adjustment should be
The explanations given below summarize the function of made by the pressure adjust valve.
each control or instrument group.
4.2.2 Injector Outside Chain Tension
4.2.1 Injector Inside Chain Tension
This system is served by the following controls and
This system is served by the following controls and instruments.
instruments.
Injector Outside Tension Pressure Gauge
Emergency Traction Supply
Displays the current hydraulic pressure within the outside
A three-way valve that is used to apply full priority pressure tension cylinders.
in the event of an emergency (runaway) situation. In the
normal operating position, the pressure to each of the three Pressure Valve
tensioner cylinder ram sets is determined by the pressure
adjust valve. A needle valve which isolates the supply pressure from the
system.

Page 28 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

Bleed Valve 4.2.4 Reel Controls

A needle valve used to bleed pressure from the system. This system is served by the following controls and
instruments.
4.2.3 Injector-Head Drive
Reel Control
This system is served by the following controls and
instruments. The reel directional control valve. Should be locked in the
out-hole direction for all normal operations.
Injector Motor Pressure Adjust Valve
Reel Pressure Adjust
A remote pilot valve used to control the injector drive
pressure. A remote pilot valve used to adjust the reel drive system
relief valve from zero to the preset maximum.
Injector Control Pilot Pressure Gauge
Reel Pressure Gauge
Displays the pilot control pressure, which is equal to the
discharge pressure of the Husco valve. Displays the hydraulic pressure to the reel motor.

Injector Control Valve Reel Brake

Provides directional and speed control of the injector- head A valve used to apply/release the reel brake.
motors by controlling the output of the Husco valve. Pulling
the valve handle backward selects the out-hole direction; Levelwind Override
pushing the handle forward selects an in-hole direction.
Advances or retards the position of the levelwind traveling
Injector Speed High/Low head.

Valve used to control injector-head motor speed selection. Levelwind Raise/Lower

Injector Motor Pressure Control to raise or lower the levelwind assembly.

Displays the injector motor hydraulic pressure. 4.2.5 Lubrication Controls

30-GPM Pump/60-GPM Pump This system is served by the following controls and
instruments.
These two valves are used to control the injector-head
motor speed. One or more of the pumps must be selected Reel Tubing Lubrication
in order to operate the injector head. For high injector head
speeds both pumps may be selected. A pilot valve used to control (on/off) the reel tubing
lubrication system.
Priority Pressure Gauge
Injector Chain Lubrication
Displays the priority system pressure. The priority system
pressure is used to operate several of the remote pilot A pilot valve used to control (on/off) the injector-head chain
functions associated with the other controls. lubrication system.

Page 29 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

4.2.6 Engine Controls 4.2.8 Strippers

This system is served by the following controls and This system is served by the following controls and
instruments. instruments.

Emergency Stop Stripper Selection Valve

A valve which operates the engine’s air inlet shutoff valve. Three-way valve which directs the hydraulic supply to the
Should only be used in an emergency. The shutoff valve appropriate stripper.
must be manually reset at the power pack to allow further
operation. Stripper-System Pressure Gauge

Engine Stop Displays the discharge pressure of the stripper supply

pump.
A valve which remotely shuts off the diesel fuel supply to
the engine. Stripper Pressure Adjust

Throttle Air regulator control which controls the operation of the

stripper supply pump. Stripper pressure decrease cannot
Used to control the engine speed. be achieved by this control.

Air-Supply Pressure Gauge Retract/Neutral/Pack Valve (2)

Displays the pneumatic system pressure. Control valve for each stripper selecting the desired func-
tion. The neutral position bleeds stripper pressure.
4.2.7 Blowout Preventers (BOP)
Stripper Pressure Gauge (2)
This system is served by the following controls and
instruments. Displays the hydraulic pressure of the selected function, as
selected by the retract/neutral/retract valve.
BOP-Supply Pressure Gauge
4.2.9 Principal Gauges
Displays the BOP’s hydraulic supply pressure.
Wellhead Pressure Gauge
BOP Pressure
Displays wellhead pressure at the BOP pressure port,
Displays the hydraulic pressure in the BOP circuit down- generally located at the center of the BOP stack.
stream of the BOP supply valve.
Circulating Pressure Gauge
BOP Supply Valve
Displays pressure at the reel-manifold pressure sensor.
Valve used to isolate the BOP circuit from the hydraulic
supply. Weight Indicator

Ram Control Valve (4) Displays the weight exerted by the tubing on the injector
head.
Used to open/close each of the four ram sets (blind, shear,
slip and pipe rams).

Page 30 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

4.2.10 Emergency Hydraulic Supply The equipment operator should coordinate the control and
instrumentation functions to affect a high level of control
The emergency pump console contains the pressure gauge over the CTU. Good control, together with smooth operation
and valves to allow the selection and monitoring of emer- will help to improve the reliability and longevity of the
gency hydraulic supply to the stripper, BOP and chain components, system controls, tools and tubing used.
tensioner systems, as selected. Control of pressure is then
by manual effort. During operation, consideration must be given to the speed
and levels of force applied to the CT. These must be
4.2.11 Electronic Equipment consistent with the well conditions and equipment limita-
tions.
The following electronic equipment may be fitted or in-
stalled to monitor and record the CTU, tubing, and well data. Starting/Stopping

• Electronic Depth Sensors The process of starting and stopping the movement of the
CT must be conducted by applying or reducing the driving
• Electronic Pressure Sensors force slowly and smoothly. Sudden changes may exert
unacceptably high forces to the tubing, reel, injector head,
• Tubing Monitoring Equipment power pack and pressure control equipment components.

4.3 Operating Technique NOTE: If any of the defined operating limits are met, or
exceeded, the injector-head drive must be disengaged as
The controls and systems of any CTU must be operated in quickly as possible. Operation may commence only when
a manner which ensures that the following general require- the appropriate course of action has been determined.
ments are met:
Changes in the injector head direction must only be
• The safety of personnel associated with the operation and attempted after the tubing has been brought to a complete
maintenance of the CTU and ancillary equipment must halt.
not be jeopardized by the actions of the CT operator.
Several precautions must be taken when the injector-head
• Operation or maintenance of any controls or system of the drive is to be engaged. These may include, but not be
CTU must not compromise the efficiency of the well limited to:
control barriers. The operation of primary, secondary and
tertiary (where required) well control barriers must be • Check that the BOP rams and wellhead valves are open
understood. In addition, the consequences of their opera- (including the subsurface safety valve, where appli-
tion must be understood. cable). Ensure that all pressure control systems are
appropriately energized.
• The operating limits of key components and systems
associated with the CTU or ancillary equipment should • Ensure that parking devices such as BOP slips, reel
not be exceeded. brakes, etc., are released and that the appropriate reel
back tension is applied.
• The operating limits defined by appropriate CT software
models should not be exceeded. In the event that this • Note (reset if applicable) the depth system readout.
information is not available, the operation should be
conducted within the operating limits identified during the • The weight indicator reading at the maximum allowable
job design phase. tension (Tmax), as determined during the job planning
phase, must be known and noted by the operator prior to
• Applicable safety and environmental policies must be commencing the operation.
understood and complied with.

Page 31 of 33
 Section 210
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING UNIT

Running the CT The control and operation of the CTU should be consistent
with any conditions, known or suspected, which may affect
The location of the CT BHA in relation to the wellbore the CT operation.
tubulars and restrictions should be a constant consider-
ation. Appropriate precautions must be taken as the CT The following instruments and gauges are generally vari-
BHA passes restrictions or variations in the wellbore able throughout a CT operation and are assigned an “A”
diameter. These may include, but not be limited to, the priority.
following.
• Weight indicator display
• Close observation of the weight indicator display.
• Wellhead pressure gauge
• A reduction in the running speed.
• Circulating pressure gauge
• Coordination with operators of a specialist tool string, e.g., In addition, the following locations are assigned an “A”
CT Logging company. priority.

• Checking the actual vs predicted weight/depth plots. • Injector head and wellhead area

• The operator must, at all times, be prepared to quickly • CT reel

disengage the injector-head drive should abnormal condi-
tions be observed. The following instruments and gauges are generally less
likely to change rapidly and are assigned a “B” priority.
Pressure Control Equipment
• Depth measurement system
With the exception of strippers and equipment designed to
be operated while the tubing is in motion, operation of • Stripper pack pressure
pressure control equipment must only be attempted when
the tubing is stationary. • Inside chain tensioner system

The operation of BOP functions which may damage the CT, In addition, the following locations are assigned a “B”
e.g., the blind rams or shear rams, must only be attempted priority.
after considering the implications of such action. Lockout
devices should be fitted to all BOP controls that may initiate • Pump and choke parameters
severe damage to the CT if unintentionally actuated.
• Auxiliary equipment
4.4 Instrument Scanning
The following instruments are generally static throughout
To ensure that unusual circumstances during a CT opera- the operation. They do not normally require adjustment and
tion are detected as early as possible, it is necessary for the are assigned a "C" priority.
operator to constantly scan the CTU instrument array.
• Power-Pack Engine Gauges
The priorities assigned to each instrument group are
intended to initiate a regular scanning sequence which • Priority Circuit Pressure Gauge
should become habitual to the operator during normal
operations. However, during special or emergency opera- • BOP Circuit Pressure Gauge
tions, some instrument groups may require extra attention.
• Stripper System Supply Pressure Gauge

• Injector Motor Pressure and Direction Pressure Gauges

Page 32 of 33
 COILED TUBING SERVICES MANUAL Section 210
COILED TUBING UNIT Rev A - 98

• Outside Chain Tension Pressure Gauge 5 CTU COMPONENTS - APPOROXIMATE SIZES

• Inside Chain Tension Supply Pressure Gauge Figure 32 shows approximate sizes for the following CTU
components:
• Reel Back Tension Pressure Gauge
• Injector head
The frequency of scanning should ensure that all of the
systems and locations are checked every four to five • Reel
minutes.
• Control cabin
The B priority items should be checked every two to three
minutes. • Power pack.

Attention should be maintained on the A priority items at all

times other than when B and C items are being checked.

Width Length Height Weight

(ft) (ft) (ft) (tons)

Injector Head 4 4 10 7
Reel (Small) 8 8 10 20-30
Reel (Large) 9-10 9-10 12 40-50
Control Cabin 8 8 8 7
Power Pack 8 12 8 12
Control Cabin/Power 8 16 8 16
Pack Combined

Figure 32. Approximate sizes of CTU components.

Page 33 of 33
This page left blank
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98

PRESSURE CONTROL EQUIPMENT

Contents Page
Introduction .................................................................................................... 3
1 STRIPPER SYSTEMS ................................................................................... 4
1.1 Description ............................................................................................ 4
1.2 Stripper Functions ................................................................................. 4
1.3 Conventional Stripper ............................................................................ 5
1.3.1 Packing stack/arrangement ................................................................... 5
1.3.2 Guides and Bushings ............................................................................ 8
1.3.3 Hydraulic Operating System ................................................................. 8
1.3.4 Connection ............................................................................................ 8
1.4 Tandem Stripper .................................................................................... 8
1.5 Side Door Stripper ................................................................................. 9
1.5.1 Packing Arrangement .......................................................................... 10
1.5.2 Guides and Bushings .......................................................................... 10
1.5.3 Hydraulic Operating System (Down) .................................................... 10
1.5.4 Hydraulic Operating System (Up) ........................................................ 12
1.5.5 Well Seals .......................................................................................... 12
1.5.6 Connections ........................................................................................ 12
1.6 Tandem Side-Door Stripper.................................................................. 13
1.7 Radial Stripper .................................................................................... 13
1.7.1 Packing Arrangement .......................................................................... 14
1.7.2 Hydraulic Operating System ............................................................... 15
1.7.3 Wellbore seals .................................................................................... 15
1.7.4 Connections ........................................................................................ 15
2 BLOWOUT PREVENTERS .......................................................................... 15
2.1 Description .......................................................................................... 15
2.2 BOP Ram Functions ........................................................................... 15
2.2.1 Blind Ram ........................................................................................... 16
2.2.2 Shear Ram .......................................................................................... 16
2.2.3 Slip Ram ............................................................................................. 16
2.2.4 Pipe Ram ............................................................................................ 17
2.2.5 Shear/Seal Rams ................................................................................ 17
2.2.6 Pipe/Slip Rams ................................................................................... 17
2.3 BOP Body .......................................................................................... 18
2.4 Ram Bonnet and Actuator ................................................................... 18
2.5 Equalizing Valve .................................................................................. 20
2.6 Side Port and Pressure Port ............................................................... 20
2.7 Top and Bottom Connections .............................................................. 22
2.8 Hydraulic System ............................................................................... 22
2.9 Controls and Instruments .................................................................... 22
2.10 Pressure Testing Procedures ............................................................... 23
2.11 BOP Operating Sequences ................................................................. 25

Page 1 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

PRESSURE CONTROL EQUIPMENT

Contents Page
3 WELLHEAD CONNECTIONS AND CROSSOVERS ..................................... 26
3.1 Description .......................................................................................... 26
3.2 Features ............................................................................................. 26
3.3.1 API Flanges ........................................................................................ 26
3.3.1 API Flange Data ................................................................................. 28
3.4 Pin and Collar Unions .......................................................................... 29
3.4.1 Pin and Collar Union Data ................................................................... 29
3.4.2 Pin and Collar Adapters ...................................................................... 30
3.4.3 Specifying Pin and Collar Unions ........................................................ 30
3.5 Stub ACME Pin and Box Connections ................................................ 31
3.5.1 Specifying Stub ACME Pin and Box Connections ............................... 31
3.6 O-ring Seals ........................................................................................ 32
3.6.1 O-ring Size .......................................................................................... 32
3.6.2 O-Ring Materials ................................................................................. 33
3.6.3 O-ring Support .................................................................................... 33

Page 2 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

Introduction • Operating company pressure control philosophy

The pressure control equipment and practices associated • Service provider pressure control philosophy
with CT operations are designed and prepared to provide a
high degree of safety and reliability. This key feature • Requirements of applicable regulatory authority
enables CT to be widely accepted as a live well intervention
method, proven on oil and gas wells under a wide variety of Such documents may make reference to barrier principles
conditions. or philosophies and possibly identify the resulting require-
ments relating to equipment and procedures. The defini-
The pressure control equipment required and selected for tions listed below are based on general understanding of
any application depends on a number of factors. Such some commonly used terms, however these may vary
factors may relate to wellbore conditions, the application or within documents of specific organizations.
treatment to be conducted or the regulatory requirements
applicable in the region a specific wellsite. However, there • Primary Pressure Control: Equipment and practices
are always several items of pressure control equipment which provide or ensure the primary barrier against
required for any operation. The assembled equipment is wellbore pressure and fluids. Such equipment is typically
commonly referred to as the pressure control stack. In operated during normal operating conditions, e.g. equip-
assembling this equipment stack, it is not only important ment such as the stripper (including tandem or back-up
that each individual item be correctly specified and oper- stripper systems).
ated, but that each item is compatible with the specifica-
tions and functions of the assembled stack. • Secondary Pressure Control: Equipment and practices
which provide or ensure the secondary barrier against
The basic terms and principles associated with pressure wellbore pressure and fluids. Such equipment is typically
control equipment and procedures can lead to some confu- operated in support of normal operating conditions, or as
sion. This possibly results from the varying requirements a contingency, e.g. BOP, typically comprising blind ram,
brought by different operating environments (e.g., onshore/ shear ram, pipe ram and pipe ram functions, or combina-
offshore), geographical region (e.g. North Sea, West Texas, tions thereof.
Alaska), or wellbore conditions (e.g. pressure, tempera-
ture, corrosive service requirements). For the purpose of • Tertiary Pressure Control: Equipment and practices which
this manual the following terms and definitions will apply (as provide a tertiary barrier against wellbore pressure and
determined by the International Well Control Forum): fluids. Such equipment is typically operated in contin-
gency or emergency situations, e.g. Shear/seal BOP,
• Well Control: Relating to the equipment and procedures typically comprising blind ram and shear ram functions in
required for working on a well which is normally “dead”, i.e. a single ram set.
equipment and procedures associated with drilling and
workover operations and where a fluid column is the Pressure control equipment and associated issues can be
primary method of preventing the well from flowing. categorized as shown below and is the basis by which this
manual section has been structured.
• Pressure Control: Relating to the equipment and proce-
dures required for working on a well which is normally • Stripper systems
“live”, i.e. equipment and procedures associated with well
intervention operations where a physical barrier(s) is used • Blowout Preventers (BOPs)
to contain wellbore pressure and fluids.
• Wellhead Connections and Crossovers
While the technical requirements of any pressure control
stack is largely determined by the wellbore conditions and • Lubricators and Risers
intended application, there are several “non-technical”
factors which may influence the ultimate selection. • Live Well Deployment Systems

Page 3 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

Issues relating to the operation of pressure control equip- 1 STRIPPER SYSTEMS

ment can be categorized as follows.
1.1 Description
• Pressure Control Philosophy
The stripper assembly provides a dynamic seal or packoff
• Equipment Stack Configurations around the CT string as it is being run (or stripped) in and
out of the wellbore. Therefore, stripper seal material and
• Control and Operating Systems mechanism must be compatible with the fluid and pressure
conditions anticipated, or reasonably foreseeable.
• Function and Pressure Testing
The force required to energize the stripper sealing element
is applied hydraulically, and is controlled and monitored
from the CTU operator control station. Since the stripper is
a major item of pressure control equipment, there are
generally at least two independent hydraulic power supplies
that can be used to energize the system. Similarly, in some
cases, some redundancy of operation may be required.
This is achieved by locating two strippers in the pressure
control stack (tandem or dual stripper system).

The stripper packer inserts are consumable items which, in

some cases, may need to be replaced during an operation.
The stripper assembly and components are therefore
Stripper designed to enable the replacement of packer inserts while
Primary presure the equipment is rigged up and the tubing is in place.
control equipment
The stripper is flange mounted to the injector head and
Quad BOP when rigged up typically supports most of the injector head
Secondary presure weight. While this weight is supported in a vertical axis, the
control equipment stripper must also be designed to withstand some lateral
loading/bending moment that would result from the injector
head movement during rigging up and operating.

Shear/seal BOP 1.2 Stripper Functions

Tertiary presure
control equipment The desired functions of modern stripper systems are
(optional) shown below. These do not apply to all strippers or every
application, however, the functions identified will have been
incorporated into some models or configurations of stripper
at some time.

• Provide a dynamic seal against wellbore fluids and

pressure

• Maintain an efficient seal throughout an operating range

of pressure, temperature and compatible fluid types

Figure 1. Primary, secondary and tertiary pressure • Enable replacement of principal sealing components with
control equipment. the CT string in place

Page 4 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

• Support/transmit the weight (and forces) applied by the 1.3 Conventional Stripper
injector head to the pressure control stack and wellhead
The majority of strippers in use today are of a design similar
• Provide access to the wellbore for pressure sensing to that shown in Figure 3. This conventional stripper design
equipment (pressure port) and configuration has been well proven and has evolved
from a relatively small ID and low pressure rating item (2-
• Provide access to the wellbore for application of inhibitor 1/2-in. 5,000psi), to a larger, higher rated device capable of
or lubricant operation in a wide range of aggressive environments.

• Provide lateral support and guidance for the CT string With the packing stack accessed from above, the conven-
between the injector head and the wellbore (pressure tional stripper suffers the disadvantage of relatively awk-
control stack bore) ward servicing, especially when the tubing is in place.

There are several distinct types and models of CT stripper, The principal components of a conventional stripper can be
each performing the same basic functions but using differ- summarized as follows.
ent operating principles or configuration. The evolution of
design broadly follows the sequence in which the models • Packing stack/arrangement
are listed.
• Guides and bushings
• Conventional stripper
• Hydraulic operating system
• Tandem stripper
• Connection
• Side-door stripper
1.3.1 Packing stack/arrangement
• Tandem side-door
The conventional stripper packing stack or arrangement
• Radial stripper comprises three principal components:

• Energizer

• Packer insert

• Non-extrusion ring

Energizer

The stripper energizer is generally manufactured from a

urethane sleeve which is formed around a steel spring. The
energizer is of one-piece construction and cannot be
Stripper replaced with the tubing in place (i.e. the CT string passes
mounted to injector through the spring). Energizers intended for use with larger
head frame base tubing sizes may not have a spring.

The energizer ID and OD are specific to the stripper model

and the size/type of insert to be used.

Figure 2. Stripper location.

Page 5 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

Packing
arrangement Top bushing and
retaining pins

Non-extrusion ring

Mounting Packing insert

flange

Hydraulic pack
and retract
mechanism
Stripper energizer

Stripper connection to
tandem stripper, BOP
or lubricator
Lower bushing

Figure 3. Conventional stripper. Figure 4. Conventional packing stack arrangement.

Packer Insert Non Extrusion Ring

Packer inserts are formed as split sleeves of urethane, The non extrusion ring is placed between the stripper
nitrile, viton or a similar elastomeric material. The inserts packer (or energizer and inserts) and the upper wear
are assembled inside the energizer, the split construction bushing. It is manufactured from glass re-enforced teflon
enabling the inserts to be removed and replaced with the and is split at an angle to allow removal while the tubing is
tubing in place. A high proportion of the force required to in place, yet provide maximum support to the packer. The
seal the stripper packing arrangement is needed to seal the bottom of the ring is profiled to fit the bevel on top of the
vertical flow path formed by the split of the packer insert. packer or packer insert.
Interlocking packer inserts (Figure 5) have been developed
to reduce the force required, thereby reducing the operating The single greatest improvement in resistance of elas-
pressure required to maintain a seal. tomers to high-pressure failures is to limit the extrusion
gap. This is best achieved by fitting a close tolerance non-

Page 6 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

An alternative to the energizer and insert assembly is the

stripper packer (Figure 6). This comprises a split sleeve
which replaces both the energizer and the packer insert.
The stripper packer is generally manufactured in dual
hardness material, with the harder compound formed on the
outside or top to reduce extrusion. Being formed in two
halves enables the entire sealing element to be replaced
with the tubing in place.

A similar interlocking stripper packer, which is used without

an energizer, will operate successfully with only 25% of the
packing force required by a conventional packing arrange-
ment.

The energizers, packer inserts and stripper packers are

manufactured in a variety of sizes and materials to suite a
Figure 5. Interlocking packer insert. range of wellbore conditions. Since the stripper is a primary
pressure control item, it is essential that appropriate
components are selected and correctly installed. Some
elastomer materials fail catastrophically if exposed to
temperatures or fluids outside their rated operating range.
Consequently, provision should be made to adequately
identify the stripper parts by manufacturer, material and
hardness when they are received from the supplier.

A summary of common materials, including advantages

and disadvantages of use, is shown below.

• Urethane - A tough material that will tolerate abuse. In the

right conditions, it is generally the longest wearing mate-
rial and has a wide operating temperature range, however,
performance deteriorates rapidly as the temperature ap-
proaches 200°F.

• Nitrile - The most common oilfield rubber compound with

very good oil and water resistance. Nitrile has a higher
temperature range than urethane but has less resistance
to abrasive wear.

Figure 6. Interlocking stripper packer. • Viton - Has a high resistance to most oil and gas well
chemicals and a good resistance to gas permeation.
Viton has a higher temperature operating range, although
the abrasion resistance is not as good as nitrile or
extrusion ring which is designed to support the elastomer urethane.
(stripper insert or packer) and minimize the gap for extru-
sion. Since such related problems increase with wellbore • EPDM - Has an excellent resistance to steam and
pressure, Strippers used in high pressure operations should geothermal (hot-water) fluids. However, EPMD is not
be inspected more frequently, and the tolerance on bushing compatible with hydrocarbons. The abrasion and wear
and extrusion ring wear should be tightened. characteristics are similar to viton.

Page 7 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

The relative hardness of the above materials is indicated by should be capable of applying 5,000 psi although most
a “Shore A’” hardness number. In general, the higher Shore applications will require much less.
A hardness number material will better resist abrasive wear
and high-pressure extrusion. However, with a specific The stripper will be fitted with two hydraulic hoses which run
material, the compounding can be altered to extend the back to the control cabin/console. These hoses should be
temperature range and improve the wear characteristics. identified as “PACK” or “RETRACT” or suitably marked to
avoid confusion during rig up. If a single hose is used, care
1.3.2 Guides and Bushings must be taken to ensure that it is connected to the PACK
connection on the stripper during normal operations. The
Wear bushings situated above and below the packer help RETRACT port must be allowed to vent any pressure which
keep the CT centralized as it passes through the packing may occur as the piston moves into the PACK position.
arrangement. The bushing material is a bronze alloy which Venting may be achieved by removing the quick connector
ensures minimum friction and damage to the tubing as it (where fitted), or fitting a quick connector with the check
runs through the stripper. In a conventional stripper, the valve removed.
upper bushing is split and is secured by the split cap halves.
The lower bushing locates on the top of the actuating piston A double-seal arrangement, with vent to atmosphere be-
and is of single-piece construction. The force required to tween the seals of the stripper, ensures that well pressure
pack off the packing assembly is applied by the piston cannot communicate with the hydraulic system should a
through the lower bushing. seal failure occur.

When performing a pull test or pulling out of the hole, the CT Typical examples of stripper control and hydraulic systems
connector will typically contact the lower stripper bushing. are shown in Figure 7. Provision is made in this example for
This gives a positive indication on the weight indicator that the use of a second or tandem stripper. The principle of
the CT connector is at surface. Since this action effectively operation on units which have provision for only one stripper
energizes the stripper packing arrangement it is advisable will be similar.
to use only the minimum force required to confirm connec-
tor or tool location. 1.3.4 Connection

Uneven wear of the bushing material may indicate an The bottom connection of a conventional stripper was
alignment problem with the injector head chains or the historically made up to the top connection of the BOPs.
stripper mount. (Typically a Bowen-type pin and collar 6-5/16-in. OD, Acme
4 TPI 4-3/8-in. sealbore diameter.) However, to enable
1.3.3 Hydraulic Operating System some flexibility in rig up and accommodate the many
connections found in pressure control equipment, a range
The majority of strippers currently in use are dual acting, i.e. of connections may be commonly found on strippers.
there is provision to PACK and RETRACT the stripper
actuator piston hydraulically. The major advantage of this A wellhead pressure port is located on the body of the
system is that the bottom bushing is lowered hydraulically stripper, just above the bottom connection. Hoses, piping
enabling an easier and quicker change of packing ele- and fittings used tapped off this port must have a working
ments. pressure rating equal to that of the stripper (commonly
10,000 psi). They must also be suitable for use with
The hydraulic system supply and control arrangement will corrosive/hazardous wellbore fluids, e.g. H2S.
varies between coiled tubing units. However, this must be
compatible with the requirements of the stripper model in 1.4 Tandem Stripper
use, e.g. minimum and maximum pressures. To provide
necessary contingency levels, there are generally at least Tandem stripper assemblies are designed to be used in
two independent sources of hydraulic pressure to operate conjunction with a fixed stripper fitted to the CT injector
the stripper. Most commonly this include an air-operated head. This configuration provides a backup or contingency
hydraulic pump and a manual back up. Both systems stripper facility should the primary stripper fail or wear out

Page 8 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

STRIPPER STRIPPER
#2 #1

RETRACT NEUTRAL PACK RETRACT NEUTRAL PACK

STRIPPER SYSTEM PRESSURE

5000 PSI MAX
#2 #1
STRIPPER STRIPPER

STRIPPER
PRESSURE ADJUST
AIR REG. CONTROL

Figure 7. Stripper controls and instrumentation.

during operation. Several secondary or backup stripper The components and operating principals of the tandem
systems have evolved in recent years. stripper are similar to those described for the conventional
stripper assembly above. When selecting a tandem strip-
In order to simplify the terminology, the following definitions per, the material and operating specifications should gen-
are used in this manual. erally be equal to, or greater than, those of the primary
stripper.
• Dual Stripper - Dual strippers were originally designed to
be fitted as an adaptation of the primary stripper, i.e. the 1.5 Side Door Stripper
dual stripper assembly cannot be removed to allow single
stripper operation without reassembly of the primary The side-door stripper was developed by Texas Oil Tools
stripper. (TOT) to permit easier access to the stripper packing
arrangement. While conventional stripper systems require
• Tandem Stripper - Tandem strippers are designed as a the packing to be removed from the top of the stripper
complete assembly, with appropriate connections top assembly, (i.e. within the injector-head frame) strippers of
and bottom. In this way, removal or installation is a the side-door design allow the packing arrangement to be
straightforward process which allows greater flexibility removed from the side (i.e. below the injector head). This
with equipment rig-up. configuration provides several advantages.

The illustration in Figure 8 shows a Texas Oil Tools (TOT) Since there is no longer a requirement for access to the
Model DT Tandem Stripper Packer. The features noted stripper from above, the stripper assembly can be mounted
below apply to this model of stripper, although generally, closer to the injector-head chains. In this way, the amount
they will apply to any model of tandem conventional of exposed, unsupported CT is reduced. This is an impor-
stripper. tant consideration when snubbing against high wellhead
pressures.

Page 9 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

Top connection The upward operating system is a relatively recent devel-

opment which overcomes several of the disadvantages
associated with the downward operating system while
further increasing the access and utility provided by the
stripper.
Packing
arrangement The principal components of a side-door stripper are similar
in function, although different in operation, to that of a
conventional stripper and can be summarized as follows.

• Packing stack/arrangement

• Guides and bushings

Hydraulic pack
and retract • Hydraulic operating system
mechanism
• Well seals

• Connections

1.5.1 Packing Arrangement

The OD of the side-door stripper packing arrangements is

3.50 in. Interlocking packing inserts manufactured in this
size do not require an energizer, thereby increasing the
Bottom connection to amount of material available for extended wear (Figure 11).
BOP or lubricator However, if it is desirable to use the standard sized packing
inserts (2.50-in. OD) in the side-door stripper, a split,
interlocking energizer (3.50-in. OD x 2.50-in. ID) is avail-
able.

1.5.2 Guides and Bushings

Figure 8. Typical tandem stripper assembly.
The upper wear bushings of the side-door stripper are
The packing arrangement is more accessible, therefore considerably longer than those of the conventional stripper.
inspection and replacement are easier and safer - espe- This increases the stability of the CT within the stripper and
cially when the tubing is in place. By fully retracting the improves centralization which in turn promotes a longer
stripper hydraulic function, the packing arrangement is fully packing life. The degree of acceptable wear on bushings
exposed for inspection or replacement. A stop-guard de- and non- extrusion rings will depend on the wellhead
vice locating on the side-door prevents accidental opening pressures to be encountered. High wellhead pressures
of the packer cylinder sleeve during normal operation. require that the extrusion ring functions more effectively
than with low pressures.
Sidedoor strippers are available in two distinctly different
operating systems: 1.5.3 Hydraulic Operating System (Down)

• Downward operating hydraulic system (Figure 9). On earlier models of side-door stripper, the hydraulic
packoff mechanism is located above the packing arrange-
• Upward operating hydraulic systems (Figure 10). ment. In this configuration the operating system is isolated
with no means for wellbore pressure to access the hydraulic

Page 10 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

Hydraulic pack
and retract
mechanism

Mounting
Mounting
flange
flange

Side-door and
packing
arrangement

Side-door and
packing
arrangement
Hydraulic pack
and retract
mechanism

Bottom connection to
Bottom connection to
tandem stripper, BOP
tandem stripper, BOP
or lubricator
or lubricator

Figure 9. Side-door stripper - downward operating Figure 10. Side-door stripper - upward operating
hydraulics. hydraulics.

chamber in the event of a seal failure. However, in to this applied to the stripper to enable an efficient seal. If the test
system of operation, the hydraulic force applied to the pressure is bled off quickly on conclusion of the pressure
stripper packing must first overcome the force exerted by test, a sudden high force may be applied to the tubing
the wellhead pressure before a packoff can be efficiently through the stripper packing. If the tubing geometry and
achieved. specifications are not sufficient to withstand this force,
some significant collapse damage may occur.
Certain operating conditions may result in the application of
damaging forces. For example, while pressure testing the The hydraulic supply and the controls/instrumentation
pressure control equipment rig up, a relatively high “well- required for successful operation of the side-door stripper
head pressure” will be applied by the test pump (e.g. 5000 are the same as that described for the conventional stripper
psi). A corresponding hydraulic pack pressure will be system.

Page 11 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

1.5.4 Hydraulic Operating System (Up) systems are required for this design of stripper. The PACK
and RETRACT hydraulic system operates as normal using
The more recent models of side-door stripper incorporate the supply and controls typically associated with conven-
an upward acting operating system which, like conven- tional or earlier side-door stripper systems. An additional
tional strippers, utilizes wellhead pressure to assist in hydraulic system is required to open and close the side-
making/maintaining the pack-off. Two separate hydraulic door, thereby allowing access to the internal components.
In many cases this additional supply is provided by a
temporary system (hand pump) connected only when
servicing is required. Safety latches acting on the door
assembly prevent accidental opening during normal use.
Upper tubing
guide
1.5.5 Well Seals

The design of both side-door strippers (upward and down-

ward actuation) exposes one seal on the side-door mecha-
nism to wellhead pressure. To provide a backup, in the
event of a seal failure with the tubing in place, a standby
Tubing guides seal is located in a recess in the side-door body. In the
event of a seal failure, wellhead pressure must be isolated
by the BOPs to allow the packer cylinder sleeve to be safely
retracted. The failed seal can then be cut and removed and
the standby seal relocated in the seal recess. Safety
considerations which apply when changing the packing
arrangement with the tubing in place will also apply when
replacing the M-Seal.

Upper bushing 1.5.6 Connections

To enable greater flexibility and to allow high pressure

operations to be undertaken without elastomeric seals in
Upper extrusion the pressure control stack connections, some recent
ring stripper models are equipped with a flanged bottom connec-
tion. The flange connection can then be fitted with one of the
following connectors:
Stripper
packer
• Pin and collar adapter

Lower extrusion • Hydraulic quick connector

ring
• Flanged connection to tandem stripper

Lower bushing On more recent models of side-door stripper, the main

components are designed to accommodate a range of top/
bottom subs which enable different connection configura-
tions to be easily fitted. As with all connections, it is
essential the mating faces are maintained in good condition
and the connection is adequately identified to ensure that
Figure 11. Side-door stripper packing and bushing pressure control stack components can be properly made
arrangement. up with the necessary crossovers or adapters.

Page 12 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

1.6 Tandem Side-Door Stripper • Reduced height - In many applications, especially off-
shore, significant height restrictions are imposed. The
The TOT Tandem Side-Door Stripper is an adaptation of the radial stripper is shorter although wider than conventional
side-door stripper described above and is designed to allow or side-door stripper models.
the packing arrangement to be inspected and replaced
easily with the tubing in place. Used in conjunction with the • Retractable packing elements - The stripper packing and
side-door stripper, the packing arrangements can be changed bushings can be fully retracted hydraulically, thereby
in both strippers as often as is required. This provides a high enabling full bore access through the stripper. This facility
degree of contingency and enables CT operations to be is useful if externally upset components are to be run
completed safely in a wide range of aggressive conditions, through the pressure control stack. Also, when used in
e.g. high-temperature, high-pressure or in conditions where tandem stripper equipment configurations, retracting the
the tubing surface may result in extreme stripper wear. packing and bushings ensures that no unintentional wear
will occur.
The illustration in Figure 12 identifies the main features of
the TOT Tandem Side-Door Stripper. The model illustrated
includes an optional integral chemical injection system.
This may be used for the injection of a wide variety of
Top connection
inhibiting or lubricating fluids between the two strippers.

Several CT applications, especially CT completion related

activity, require the assembly of external components or
passage of externally upset components through the pres-
sure control stack. The configuration of modern tandem Tubing guides
strippers is designed to complement such operations by and door operat-
enabling the internal components (packing and bushings) ing system
to be removed to provide through-bore access. When used
in conjunction with other pressure control equipment, the
access window can also provides a safe means of attach-
ing external components (e.g. hanger slips) to the CT
string.
Side-door and
packing
1.7 Radial Stripper
arrangement
The operating principles for radial strippers are significantly
different to those of conventional or side-door stripper
systems. While both the conventional and side-door strip- Hydraulic pack
pers energize the stripper packer by the application of axial and retract
force (up or down) the radial stripper is energized by mechanism
actuators acting radially (Figure 13).

This unique configuration incorporates features which offer

several advantages over alternative designs.

• Single piece body - The body of a radial stripper is forged

from a single steel block, eliminating threads or welds Bottom connection to
which are potential leak paths or high-stress areas under BOP or lubricator
high bending forces.

Figure 12. TOT tandem side-door stripper.

Page 13 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

Figure 13. Radial stripper.

• Convenient packer replacement - similar to side-door

models, the radial stripper consumables are accessed
from the side, below the injector head.

The principal components of a radial stripper are similar in

function, although different in operation, to that of conven-
tional or side-door stripper systems and can be summa-
rized as follows.

• Packing stack/arrangement

• Hydraulic operating system

• Wellbore seals

• Connections

1.7.1 Packing Arrangement

The packing and bushing components of a radial stripper

are similar but not interchangeable with side-door stripper
components. Force applied by the hydraulic actuators is
transferred through the energizer to the bushings (upper
and lower) and the stripper packer. As the stripper mecha-
nism is actuated, the bushings close around the CT string.
Once the bushings segments have engaged, the applica-
tion of further force will energize the packer to effect a seal. Figure 14. Typical quad BOP assembly.

Page 14 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

Since the tubing guides and bushings operate (PACK and Coiled tubing BOPs are typically equipped with four sets of
RETRACT) in conjunction with the stripper packer it is rams, hence the designation quad BOP (Figure 14). How-
essential that they are inspected and cleaned regularly to ever, some of the ram function can be combined, e.g.,
ensure proper operation of the stripper seal and to minimize shear/seal, pipe/slip, enabling a variety of BOP configura-
any risk of damage from incorrect closure on the tubing tions. BOPs are now available with one, two, three or four
surface. ram sets, each which can be equipped with a variety of ram
functions to enable the desired functional and safety
1.7.2 Hydraulic Operating System specifications to be met.

The force to energize (operate) a radial stripper is provided The BOP rams are hydraulically actuated, although rams
by a set of opposing hydraulic ram assemblies. The may be actuated and locked manually under certain condi-
assemblies are double acting enabling positive PACK and tions. All ram functions require that the tubing must be
RETRACT functions with a high degree of control. The stationary before activation. Severe damage to the BOP
configuration of the energizer/packer assembly and a and CT may result if this requirement is not observed.
pressure equalizing port connecting the ram cavity and the
lower wellbore, means that wellhead pressure has a rela- The BOP may be considered as a barrier or line of defense
tively small bearing on the hydraulic pressure required to against a producing well, allowing well operations, produc-
operate the stripper. tion and simultaneous activities to proceed in a controlled
and safe manner. In many cases, the existence and
An additional hydraulic function/system is used to assist in maintenance of these barriers have legal requirements.
removal of the stripper bonnets for packer/guide inspection Consequently, the efficiency of the various BOP functions
and replacement. This system typically utilizes a tempo- must not be jeopardized by improper operation or by
rary supply (handpump) connected for inspection and operation outside of the design limits to which the equip-
servicing purposes. ment is certified.

1.7.3 Wellbore seals 2.2 BOP Ram Functions

The integral construction of the stripper means only two The components for each of the BOP rams are assembled
seals (in addition to the stripper packer) are exposed to onto a stainless steel ram body. The design provides for
wellbore pressure and fluids. Internal and external seals are easy maintenance and interchangeability of parts, allowing
fitted to the bonnet/piston rod assembly. the same ram body to be used over a range of CT sizes, e.g.
by changing pipe seal or slip inserts.
1.7.4 Connections
The ram functions detailed and illustrated below generally
Radial strippers are typically configured with flange con- apply regardless of the BOP configuration.
nections top and bottom. This enables a wide variety of
adapters or quick-latch connectors to be fitted without Single function Rams
adding excessive height to the assembled stack.
• Blind rams - designed to close and seal when there is no
2 BLOWOUT PREVENTERS CT or toolstring in the BOP body.

2.1 Description • Shear rams - designed to close on and cut through the CT
string and any installed conductors or conduits.
The function of the CT blowout preventer (BOP) is to
provide a means of holding the CT and isolating the wellbore • Slip rams - designed to close on and hold the CT without
pressure during emergency, unusual and normal operating damaging the tubing surface.
situations. The configuration of the BOP rams and side-port
facility allows well control operations to be conducted under • Pipe rams - designed to close on and seal around the CT
a variety of conditions. when in place.

Page 15 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

Combination Function Rams the tubing has been severely deformed a significant
restriction may hinder well kill operations.
• Shear/seal - combination shear and blind ram functions
The cutting profiles of the blades shown in Figure 16 are
• Pipe/slip - combination pipe and slip ram functions designed to minimize the tubing distortion when the cut
is made. Cutting blades are generally made from high-
2.2.1 Blind Ram strength, high-hardness materials. However, it is com-
monly known that these types of materials are suscep-
Blind rams are designed to isolate pressure from the well tible to sulfide stress cracking (SSC) when exposed to an
while the BOP bore is unobstructed by CT or a bottom- hole H2S environment. Since in the course of operation the CT
assembly. When the ram set has closed, the configuration BOP may well be exposed to H2S, a compromise is made
of seals on each ram body is designed to use the pressure in the design and construction of the BOP shear blades.
differential from below to assist in keeping the ram closed The blades are case hardened only. This results in a
(Figure 15). The greater the pressure differential acting from hardened outer shell surrounding a softer inner core which
below the ram, the greater will be the force keeping the rams maintains the integrity of the blade in an H2S environ-
closed. Even moderate differential pressure will exert ment. Blades which are hardened throughout may fail due
sufficient force to prevent the rams being opened hydrau- to SSC before they are actually used.
lically by the ram actuators.
2.2.3 Slip Ram
To allow the rams to be opened in these circumstances,
and to prevent the severe damage which would occur to the Slip rams are designed to close on, and hold, the CT in
ram face seal when opened under pressure, equalizing the BOP. This must be achieved while causing minimal
valves are fitted to each ram set capable of isolating damage to the tubing surface, since even apparently
pressure, e.g., blind rams and pipe rams. No attempt minor damage to the tubing surface may cause prema-
should be made to open the blind rams until the differential ture failure due to fatigue or localized corrosion (Figure
pressure across the rams has been equalized. 17).

Since the operation of the blind ram does not depend on the
CT, it is not required to be changed when the BOP is
dressed for a change in CT size.
Ram body
Front and rear seals are commonly manufactured from seal
Viton to provide the best service in an H2S environment;
however, seals of alternative materials are available for
Steam or Arctic service.

2.2.2 Shear Ram Ram body

Shear rams are designed to cut the CT and any wireline or

hydraulic line that may have been installed in the CT string.
With the CT cut and the upper portion removed from the Ram seal
BOP bore, the blind rams may be closed to isolate and Retainer
control the well pressure. bar

A major consideration in the design of any tubing shear

equipment is the deformation which occurs to the cut ends
of the tubing, since, in most cases, it is desirable to pump
kill fluid through the tubing once the cut has been made. If
Figure 15. Typical blind ram configuration.

Page 16 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

Ram body Retainer

screw

Shear
blade

Shear
blade
(inverted)

Figure 16. Typical shear ram configuration.

The hardened slip inserts are profiled to match the OD of the assist in keeping the ram closed. In such models, no
CT string and are designed to hold the tubing against attempt should be made to open the rams until the
upward or downward force. Slip inserts over a range of CT differential pressure has been equalized (Figure 19).
sizes are available for use in each ram body.
The shear rams used in quad and combi BOPs are
2.2.4 Pipe Ram designed to minimize the deformation to the tubing while
the cut is made, thereby permitting kill fluid to be pumped
Pipe rams are designed to close and seal around the CT. through the suspended CT string. This is not a primary
Pipe rams almost are always fitted to the bottom ram set consideration in the case of shear/seal BOPs. However, a
on a BOP. In this configuration, the resulting seal is as side port is generally fitted to the shear/seal BOP body
close to the wellhead as possible (Figure 18). allow kill fluid to injected below the rams.

Like the blind rams, the pipe-ram body is fitted with a rear 2.2.6 Pipe/Slip Rams
seal which uses the wellhead pressure to apply a force
acting to keep the rams closed. No attempt should be made Pipe/slip rams are designed to seal around the CT string
to open the pipe rams until the differential pressure across and secure it against upward and downward forces. The
the rams has been equalized. design incorporates a number of moving parts in the ram
body is more complex than a any of the other rams
2.2.5 Shear/Seal Rams described. The principal reason for this complexity is the
need to apportion the closing force between the holding
Shear/seal rams are designed to cut the CT and seal the action (slip ram function) and the sealing efficiency (pipe
wellbore. The rams should be capable of cutting the CT ram function). For example, it would be undesirable for the
string and sealing without the need for the cut tubing to fall, pipe ram function to prevent sufficient ram travel or force to
or be extracted from, the sealing elements of the ram. safely hold the CT string in the slips.

Some models of shear/seal BOP have the ram seals Most models of pipe/slip rams have the ram seals config-
configured to use the pressure differential from below to ured to use the pressure differential from below to assist in

Page 17 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

keeping the ram closed. In such models, no attempt should

be made to open the rams until the differential pressure has
Ram body been equalized (Figure 20).

2.3 BOP Body

To avoid potential weaknesses associated with joints,

connections or welds, almost all BOP bodies are manufac-
tured from a solid steel block. The top, bottom and side- port
connections on the BOP bodies, currently produced, are
commonly flange-type connections incorporating a ductile
metal seal ring. However, earlier versions of the body are
Retainer machined with a pin and collar box top connection.
pin
Slip insert Internal surfaces of the BOP body are generally coated with
tuff-green plastic to provide protection against corrosive
fluids.

Most current models of BOP have the hydraulic fluid

passages pre-drilled through the BOP body and ram bon-
Figure 17. Typical slip ram configuration.
nets. In this way, the requirement for external plumbing is
minimized, thereby reducing the possibility of system
leaks or damage while handling or rigging up the BOP.
Ram body
The common means of describing a BOP is by size (bore)
seal
and the number of ram sets, e.g., quad (4), combi (typically
2), triple combi (3) or shear/seal (typically 1). Typical BOP
configurations for each type are shown in Figure 21 through
Figure 24.

2.4 Ram Bonnet and Actuator

Ram body
The ram bonnet and actuator form a complete assembly
which must be removed to inspect or replace the ram
bodies and inserts. The well pressure seals and hydraulic
system seals are separated by a vent and weep hole to
prevent accidental pressuring of the hydraulic system in
the event of a well- pressure seal failure.

The ram position is indicated by the ram indicator rod which

is attached to the actuator piston. Full travel of the indicator
Retainer rods should be observed each time the rams are function
bar tested (Figure 25).
Ram seal
Ram actuator are generally fitted with a manual locking or
closing facility which is operated by a handwheel on the end
of the actuator. Manual operation is limited to closing and
locking the BOP rams only - the rams must be hydraulically
Figure 18. Typical pipe ram configuration. opened, once the locking mechanism has been retracted.

Page 18 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

Ram body
seal

Shear/seal blade

Ram body

Retainer
bar
Shear/seal blade
(inverted)

Figure 19. Typical shear/seal ram configuration.

Ram seal Ram seal

Slip insert
Push rod Push rod
Pipe ram

Ram body Ram body

Figure 20. Typical pipe/slip ram configuration.

Page 19 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

When closing the rams manually, the hydraulic control 2.5 Equalizing Valve
valve for the applicable ram set must be placed in the close
position to allow the hydraulic fluid to vent back to the An equalizing valve is fitted to each ram set of capable of
hydraulic reservoir. If this is not possible, the hydraulic sealing in the BOP bore. Since the design of sealing rams
connectors on the BOP or the control lines must be allowed uses the well pressure to maintain an effective closure, this
to vent freely. pressure must be equalized before attempting to open the
rams (Figure 26).
The number of turns made by the handwheels must always
be counted. This is to confirm the rams have traveled the The equalizing valve is integral to the BOP body and does
full distance required to achieve a closing seal, and not require or involve any external plumbing. A 1/4-in. Allen
conversely, that the rams may be fully opened by reversing key is used to open and close the valve; however there is
the number of applied turns. no visual indication of the valve position. The valve must
always be left in the closed position when not in operation,
If the rams are hydraulically closed, they may be locked in but a full function test should be performed prior to every
place by the same procedure. If any of the BOP rams are job.
to be closed and left unattended for prolonged periods, they
should be manually locked. 2.6 Side Port and Pressure Port

Before hydraulically opening the rams and resuming opera- The side port, often called the kill port, is located between
tions, the manual locking mechanism must be fully re- the shear rams and the slip rams. The flanged connection
tracted. Severe damage will result to the internal compo- is commonly fitted with a Weco 1502 union adapter to allow
nents of the actuator if an attempt is made to hydraulically a kill valve and line to be rigged up to the BOP. This allows
open the actuator while the manual locks are closed. well control fluids to be pumped down the CT/well tubular
annulus, or down the CT following operation of the shear
NOTE: It is common practice to post a notice on the rams.
operator’s console when any of the BOP functions have
been manually locked, or if the side-port valve (kill valve)
is left open. This is particularly important when the opera-
tion is being conducted by crews on a shift rota.

Blind/shear rams
Blind
rams

Shear
rams Pipe
rams
Slip
rams
Slip
Pipe rams
rams

Figure 21. Typical quad BOP configuration. Figure 22. Typical triple-combi BOP configuration.

Page 20 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

Blind/shear rams

Shear/seal ram

Pipe/slip rams

Figure 23. Typical combi BOP configuration. Figure 24. Typical shear/seal BOP configuration.

Figure 25. BOP hydraulic actuator components.

Page 21 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

To avoid exposure of the BOP to abrasive or corrosive 2.8 Hydraulic System

fluids, the side port should only be used to circulate fluids
during well control operations or when pressure testing the Since the BOP is a major item of well control equipment, it
BOP and well control equipment prior to commencing an is generally capable of being operated from several hydrau-
operation. lic supplies. These supplies generally consist of a powered
supply, i.e., hydraulic supply from the CTU power pack, and
The pressure port is typically located above the blind rams, backup pneumatic or manual pumps. In addition, all CTUs
allowing wellhead pressure to be monitored only when the are equipped with an accumulator which stores hydraulic
blind rams are open. power, allowing the BOP rams to be cycled several times
following engine shutdown.
2.7 Top and Bottom Connections
The BOP accumulator allows limited operation of all BOP
It is becoming common for the BOP body to have flange functions following shutdown of the power-pack engine.
connections on the top and bottom. This is advantageous Most CTUs are fitted with a 10-gal capacity bladder-type
for the following reasons. accumulator which is pre-charged with nitrogen gas. The
capacity of an accumulator to store energy is a function of
Crossovers or adapters can be fitted to allow a wide range the accumulator volume, precharge pressure and system
of connections to be used. operating pressure.

Some CT applications and clients require that the BOPs be 2.9 Controls and Instruments
located directly above the wellhead using only metal- to-
metal seals in the connection. All BOP controls and instruments are located in the control
cabin. Generally, the BOPs require at least two control
If the threads on a crossover or adapter become damaged, levers to be shifted to operate the rams. This is to prevent
it is a relatively simple process to change the adapter, accidental or unintentional closure of the BOP rams. A
pressure test the flange connection and resume operation. typical layout of controls and instrumentation is shown in
BOPs with machined thread connections may not be so Figure 27.
easy to maintain, because work done on the BOP body may
require that the BOP be NDT inspected and certified.

Needle
valve
Seals

Valve
body

Figure 26. BOP equalizing valve assembly.

Page 22 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

Following rig up, it is essential that a check is made to The following pressure and function testing procedures are
ensure that the controls correspond to the correct ram set recommended before every CT operation. Function test
operation. and pressure test results should be recorded (pressure
tests recorded on electronic file or Martin Decker recorder,
2.10 Pressure Testing Procedures function tests should be noted on the operation report).

Since there any many possible variations in how CT • Function test of each BOP ram, including a test of the
pressure control equipment can be rigged up and operated, backup hydraulic supply system.
pressure test procedures must be prepared for the specific
operation to be conducted. In general, test pressures need • Function test of each equalizing valve.
to be defined for the BOP pressure test procedure of any rig
up. The first known as PT1 is defined as the minimum of the • Pressure test the BOP body, blind ram and wellhead
following pressures. connections (including flanges, hydraulic release con-
nectors, crossovers, kill line and kill valve) to the
• 1-1/2 times the maximum possible wellhead pressure. pressure PT1.

• The maximum allowable working pressure (MAWP) of the • Pressure test the CT, pipe ram and stripper to PT2.
BOP, connectors or crossovers.
• Rig up BOP to wellhead and secure all hydraulic connec-
• The MAWP of the wellhead. tions, function test each BOP actuator; close and open.
Use accumulator supply.
The second pressure is identified as PT2 and is the
minimum of PT1 and the PMAW for the CT.

SHEAR RAM BLIND RAM

CLOSE OPEN CLOSE OPEN

SLIP RAM PIPE RAM

CLOSE OPEN CLOSE OPEN

ON
OFF

BOP SUPPLY
BOP PRESSURE BOP SUPPLY PRESSURE

Figure 27. Typical BOP control and instrumentation layout.

Page 23 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

• Visually inspect tattletale travel, BOP bore and ram faces. • It is recommended that the weight indicator be zeroed
following an upward movement of the CT.
• Rig up treating equipment lines from pump unit(s) to CT
reel, wellhead and CT). Fill lines with pressure test fluid • Close the slip rams and pull test to the maximum pickup
and test lines. tension predicted for this job by the tubing forces model
or Tmax, whichever is least. (With tapered strings, Tmax for
• Ensure that each isolation valve is tested, including the the thin wall tubing could be less than the maximum
reel manifold internal valve. pickup tension that will occur with the thicker wall tubing.)

• With the CT stabbed and secured in the injector head and • Close the pipe rams and open the pipe ram equalizing
sufficient traction system tension applied, fill reel with valve and close the isolation valve mounted on the BOP
fluid. kill line.

• A safety clamp is recommended as a means of securing • With the stripper system pressure at zero, pump through
the CT in the injector head. the CT until fluid is seen leaking past the stripper packing.

• Flush as required to remove debris from the reel. • Extreme care must be taken when pumping fluid due to the
restriction of the equalizing port.
• Fill the BOPs with fluid through the kill line or flow tee, and
close the blind rams. • Close the pipe ram equalizing valve. Pressure test the
pipe rams by pumping through the CT to the pressure PT2.
• Open the blind ram equalizing valve and establish
circulation through the equalizing port. • Energize the stripper packer (minimum hydraulic pressure
250 psi).
• Due to the extreme restriction of the equalizing port and
the potential for plugging it is recommended that a • Open the pipe ram equalizing valve and test the stripper
centrifugal pump is used to establish circulation. and connections above the BOP.

• Close the blind ram equalizing port and pressure test BOP • When the pressure has equalized, and no leaks are
through the kill line or flow tee to P T1. apparent, open the pipe rams. If the test pressure de-
creases, restore to PT2.
• Bleed off the pressure through the treating line. With the
pressure at zero, open the blind rams. • Bleed off pressure through the kill line or flow tee and open
the slip rams.
• Fit the CT connector and BHA. Pull test CT connector
(minimum 10,000 lb, maximum Tmax ). Hold tension for a • Increase the traction hydraulic system pressure as
minimum of five minutes; during this time check the required and pressure test through the kill line or flow tee
condition of the hydraulic load cell. Release the tension against the check valve to the Pcol value output by a
on the connector and with connector tagging the stripper software model. For dual acting load cells, check the
zero all depth counters. compression indicated due to the pressure test. For
single acting load cells, ensure that the limit bolts are
• Rig up the injector to the BOP, zero the weight indicator, properly adjusted.
and RIH to a point where the CT is positioned across the
pipe rams. • Bleed off the pressure through the kill line.

• POH and tag the stripper, to correlate depth and ensure

that the CT did not collapse.

Page 24 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

NOTE: Where there is insufficient room to run the BHA

below the pipe rams, it is recommended that the test is
conducted with a minimum BHA consisting of the CT
connector, check valves and circulation tool. On success-
ful completion of this test the remainder of the BHA is
installed and an integrity test is conducted on the BOP/
injector head connection.

2.11 BOP Operating Sequences

The increasing sophistication of CT applications and de-

ployment techniques often requires the BOP rams to be
functioned in several ways or combinations.

Isolation of the wellbore pressure with no CT in the BOP

• Before closing the blind rams, the operator must confirm

that the BOP bore is unobstructed.

Isolation of the wellbore pressure with CT in the BOP bore

• Record the weight indicator reading before closing the

slips (if time permits).

• The slip rams should always be closed prior to closing the

pipe or shear rams.

• When opening the BOP rams, the pipe rams should be

opened before the slip rams.

Shearing the CT

• Close the slip rams.

• Close the pipe rams.

• Apply 1,000 to 2,000 lb tension to the CT and close the

shear rams.

• Withdraw the CT from the BOP sufficient to close the blind

rams. If possible, the tubing should be kept inside the
stripper. However, in conditions of poor visibility, it is
preferable to ensure that the tubing is clear of the blind
rams.

• Close the blind rams and open the shear rams.

Page 25 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

3 WELLHEAD CONNECTIONS AND CROSSOVERS There are three types of connection which are commonly
used when rigging up CT and pressure control equipment:
3.1 Description
• API flange
The connection between CT pressure control equipment
and the wellhead is critical in any CT operation. A pressure- • Pin and collar unions
tight connection is almost inevitably required. The connec-
tion may also have to support the weight of the CT pressure • Stub ACME pin and box connections
control equipment, the injector head and suspended tubing.
In some applications (e.g. operating from a semi submers-
Flanged connections and pin and collar connections are
ible), the connection must be capable of supporting the
commonly found on permanent production wellheads, while
weight of the tubing string and flowhead while operating at
the stub ACME pin and box type of connection is normally
the rated pressure.
used when connecting to temporary flow or testing equip-
ment.
Safety is a critical factor. Manufacturers have to subject
their products to a vigorous program of quality control and
Whatever connection is used, full compatibility with the
independent testing before the connection can be used by
connection specified by the client or third party is an
the industry.
obvious minimum requirement. The inconvenience, ex-
pense and embarrassment of providing incorrect or incom-
There are several types of connection commonly used in a
patible connections or crossovers can be avoided in most
variety of sizes and service ratings. Although on most
cases by conducting adequate checks. Actual physical
occasions the connection will be made to the client’s
checks, by making up connections or unions prior to
wellhead or equipment, it is sometimes necessary to liaise
loading out equipment, should be conducted wherever
with third-party companies (e.g. well testers) to ensure that
possible.
the connections are compatible.
3.3.1 API Flanges
Correct identification of all connections and crossovers is
essential to ensure that the CTU is rigged up safely and
efficiently. When pressure control equipment and the wellhead are
connected by API flanges, the usual configuration is to
3.2 Features have a studded flange facing up and an open flange facing
down. This allows for easier aligning and securing of
Exact specifications and tolerances for a wide range of components, lower rig upheight and is a general convention
connections have been set by the American Petroleum to ensure that equipment is correctly assembled. However,
Institute (API). This ensures that the connections, which due to the increasing number of special applications, it is
are produced by a number of different manufacturers, are recommended that a check be made of the assembly
freely compatible. configuration.

All connections and crossovers should be completed to the There are two types of API flange used in connecting
relevant API specifications. Reference to such specifica- pressure control equipment and the wellhead: 6B and 6BX
tions is contained in API Standard 6A – Wellhead Equip- flanges. The main difference between these flange types is
ment. illustrated in Figure 28.

Connections which have been manufactured to API speci- The API 6B flanges are of ring joint type and are not
fications are normally stamped with the API logo and designed for face to face makeup. The connection makeup
identifier. Connections which are not API approved must be bolting force reacts on the metal ring gasket. 6B flange
clearly identified and physically checked for compatibility. joints use R or RX ring gaskets, which are described below.

Page 26 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

The API 6BX flanges are also of ring joint type but are
designed for face-to-face makeup (Figure 29). The connec-
tion makeup bolting force reacts primarily on the raised face
of the flange. Therefore, at least one of the flanges in a 6BX
connection must have a raised face. 6BX flange joints use
BX ring gaskets, which are described below.
BX ring
Ring gaskets have a limited amount of positive interfer-
ence, which ensures that they will be joined in a sealing
relationship with the ring groove sides which are pitched at Closed
Standoff
23°. These gaskets should not be reused. face

The differences between these gasket types are as follows.

RX and BX gaskets provide a pressure-energized seal. R or RX
Note however that RX and BX ring gaskets are not ring
interchangeable. R ring gaskets are energized only by the
makeup bolt force of the connection. All BX rings have a
pressure passage while only selected sizes of RX rings are API 6B flange API 6BX flange
machined with the passage.

An example of the different ring gasket profiles is shown in Figure 28. API 6B and 6BX flanges.
Figure 30.

B
E
C

D
A
H

F G

A = Nominal bore (in.) E = Bolt circ. diameter

B = Flange OD (in.) F = Number of bolts
C = Face OD (in.) G = Bolt hole diameter
D = Flange height (in.) H = R or RX ring number

Figure 29. API flange features.

Page 27 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

3.3.1 API Flange Data When specifying API flanges, the following information
should be presented:
There are a number of dimensions which need to be
provided when specifying the size of an API flange. Full • Type of flange (6B or 6BX)
details of API flange data and size ranges are contained in
API Specification 6A. • Pressure rating

API flanges are specified by size and pressure rating. The • Nominal bore
pressure rating is commonly defined in “lb” rather than psi
(e.g. a 3-1/8-in. 5,000-lb flange). • Flange OD

There are four series of ring-joint flange connections • Face OD (where applicable)
commonly found on wellhead and pressure control equip-
ment: • Flange height

• Bolt circle diameter

• 3,000 lb.
• Bolt hole diameter
• 5,000 lb.
• Number of bolts
• 10,000 lb.
• Service (H2S or STD)
• 15,000 lb.
• Type of ring gasket (R, RX or BX)

• Ring gasket groove/pitch diameter

"R" Ring gaskets - oval or octagonal in crossection

Rx ring gasket Bx ring gasket

(asymetric octagonal) (with pressure passage)

Figure 30. R, RX and BX ring gasket profiles.

Page 28 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

3.4 Pin and Collar Unions Within each basic union design there may be several minor
design differences. These may include the manner in which
The pin and collar union is the most commonly used the collar is retained on the pin and the machined finish on
connection in the well service industry. Pin and collar the collar exterior surface. Consequently proper identifica-
unions are made to many different designs and specifica- tion of the union will, in most cases, require close exami-
tions, some of which are interchangeable. In some cases, nation and accurate measurement of the sealbore.
two union halves from unions of differing design appear to
correctly makeup. However, the difference in the specifica- 3.4.1 Pin and Collar Union Data
tion and tolerance results in a dangerously weak connec-
tion, which will probably fail before the apparent pressure There are several ways in which a union design, or
rating is reached. To avoid such errors, great care must be manufacturing standard, can be quickly identified. The
exercised in the identification and connection of unions. location of the seal arrangement and a profile of the mating
surfaces are useful means of quickly identifying the union
The most common unions encountered during CT opera- design.
tions are designed to the following company standards:
Figure 31 shows the features typically found on a pin and
• Otis collar union.

• Bowen

• Texas Oil Tools

• Flopetrol

• Schlumberger
Thread
• Hydrolex OD
Sealbore
diameter

Pin assembly

Collar

Seal arrangement
and location

Box assembly

Nominal ID

Figure 31. A typical pin and collar assembly.

Page 29 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

3.4.2 Pin and Collar Adapters Confirmation must be made that all adapters, regardless of
type or size, have been correctly identified and that they
Adapters may used to connect a pin and collar union to a fulfill the pressure and service requirements of the applica-
different type of fitting. There are two types of adapter tion.
commonly in use:
The specifications (mentioned previously) that apply to the
• Flanged pin and collar adapter, used to connect a pin and flange and pin and collar connections also apply to the
collar union to an API flange. See Figure 32. relevant adapter connections.

• Threaded pin and collar adapter, used to connect a pin and 3.4.3 Specifying Pin and Collar Unions
collar union to a stub ACME pin and box connection. See
Figure 33. Pin and collar unions are called out by the thread OD, thread
pitch and seal bore diameter:
The type of adapter required is obviously determined by the
wellhead fittings. Threaded adapters are generally required • Thread OD - Unions are commonly available with a thread
on wellheads of a low pressure rating. Each type of adapter OD range of 4-3/4-in. to 13-in.
comes in a large variety of size and pressure combinations.
• Thread Pitch - Most unions are machined with a 4-
Threaded adapters may be machined with a pressure threads-per-inch (TPI) ACME thread; however, some
sealing thread, e.g. EUE tubing thread, or may be machined unions are designed with a 5 TPI pitch. A double-start, 4-
with an ACME type thread and fitted with single or double TPI thread, which effectively halves the number of collar
seals. Flanged adapters are generally associated with rotations required to make up the union, is a design
wellheads of medium to high pressure rating and are also variation commonly found on Bowen- compatible unions.
available in a wide variety of flange and union combina-
tions.

Figure 32. Flanged pin and collar union adapter. Figure 33. Threaded pin and collar union adapter.

Page 30 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

• Sealbore Diameter - Measurement of the sealbore diam- determined by the standard to which the thread has been
eter is critical for accurate union identification. Several machined. Whenever the stub ACME threads are speci-
unions may use the same thread OD and pitch but differ fied, the standard and/or the dimensions must be given.
in sealbore diameter.
3.5.1 Specifying Stub ACME Pin and Box Connections
When ordering or specifying pin and collar unions, the
following information should be presented: Stub ACME pin connections are called out by the thread
OD, thread pitch and seal arrangement.
1. Type of union (e.g. Bowen, Otis)
• Thread OD
2. Thread OD
Pin threads are commonly machined in a range from 4-3/
3. Thread pitch (TPI) 8 in. to 8-1/4 in.

4. Single or double lead thread • Thread pitch

5. Sealbore diameter Thread pitch in this type of connection is commonly 4 or

6 TPI.
6. Nominal and actual bore
• Seal arrangement
7. Collar OD
The original design of many of these connections fea-
8. Pressure rating tured only one O-ring. The industry drive toward double-
seal isolation has resulted in some double seal options
9. Service

3.5 Stub ACME Pin and Box Connections

The stub ACME pin and box connection is commonly found

on temporary well testing flowheads. In most cases, the
lifting nubbin or handing sub is attached to the flowhead
using this type of connection.

It generally features a modified ACME type thread, which

allows easy assembly yet is strong enough to support the
high tensile loads associated with this type of application.
Single or double O-rings located at the nose of the pin
provide the seal without requiring a high torque to the
connection. A stub ACME pin and box connection is shown
in Figure 34.

NOTE: The designation ACME thread refers to a 4-TPI

square-cut thread which is 0.1350 inches in depth (such as
commonly found on the pin and collar unions, e.g. Bowen).

Stub ACME threads are a modification of this standard and

are commonly available in 4, 6, 8 and occasionally 10 TPI. Figure 34. Features of a stub ACME pin and box
The dimensions of the thread and connection will be connection.

Page 31 of 33
 Section 220
COILED TUBING SERVICES MANUAL
Rev A - 98 PRESSURE CONTROL EQUIPMENT

being built. The double-seal pin is longer than that of the The operating temperature, pressure and fluid compatibility
single, and the two connections are not generally inter- of a seal application are taken into account at the time of
changeable. the O-ring selection.

When ordering or specifying stub ACME pin and box The extrusion gap is determined by the component design,
connections the following information should be presented. component wear or distortion under operating conditions.

• Thread OD 3.6.1 O-ring Size

• Thread pitch (TPI) O-rings are commercially available in a wide range of sizes.
The diagram in Figure 35 illustrates the standard means of
• Seal configuration (single or double) measuring and classifying O-rings by size.

• Service Identification of O-ring size is commonly made by a code

numbering system which complies with the American
• ID of connection components Standard Number 568A (AS 568A). This system has also
been adopted as standards set by DIN 3771 (Part 1) and
• Standard or compatibility (e.g. Otis or Schlumberger ISO 3601 (Part 1).
Flowhead)
Many manufacturers and suppliers of O-rings and compo-
3.6 O-ring Seals nents integrate the three digits of the standard numbering
system into the part numbering system for the O-rings in
The O-ring is commonly used to provide a pressure-tight their assembly.
seal in a wide variety of applications. O-rings are suitable
for use in wellhead connections and crossovers because:

• An effective seal is possible over a wide range of

temperatures and pressures.

• The seals and backup rings are easily installed.

• Torque or alignment of the connection is not critical.

Cross section
• The seal area design is simple and does not require
complex machining or additional strengthening. ID

• O-ring failure is generally easily identified.

• Replacing an O-ring is relatively inexpensive.

Criteria which affect the efficiency of an O-ring seal include:

• Temperature

• Pressure

• Fluid compatibility

• Extrusion gap Figure 35. Standard O-ring dimensions.

Page 32 of 33
 COILED TUBING SERVICES MANUAL Section 220
PRESSURE CONTROL EQUIPMENT Rev A - 98

3.6.2 O-Ring Materials • EPDM (Ethylene-Proylene Rubber)

The elastomer from which the O-ring is manufactured must Has excellent resistance to extreme temperatures but is
be chosen to suit the intended seal application. A wide not compatible with mineral oils. Commonly used in
range of materials is used to manufacture stock O-rings steam or geothermal service equipment.
which are commonly available for use in every industry. O-
rings suitable for use in the oilfield will generally be The hardness of the O-ring elastomers is generally given as
manufactured from the types of elastomer shown below: a Shore A number – the higher the number, the harder the
material. A softer O-ring material settles into the micro fine
• Nitrile (Acryl-Nitrile Butadiene Rubber- NBR) imperfections of the seal surface more easily than that of
a hard material. This is an advantage where the system
The most common oilfield rubber compound. Has good oil pressure is low; therefore, the general rule is for low
and water resistance although is not suitable for use in pressure equipment use a softer O-ring.
H2S environments.
3.6.3 O-ring Support
• Viton (Fluorocarbon Rubber - FPM)
In high-pressure applications, it is common for the O-ring to
Excellent oil resistance and greater temperature resis- be supported by a ring or device to minimize extrusion.
tance than Nitrile. Resistant to effects of H2S; conse- Figure 36 shows two commonly used methods of minimiz-
quently it is widely used on H2S service equipment. ing extrusion, and therefore improving high pressure reli-
ability.
• Hydrin (Epichlorohydrin Rubber - CO, ECO)
O-rings which are supported by a Parbak support last longer
Has good low-temperature flexibility and resistance to and are less prone to failure in service.
effects of hydrocarbon fluids. Is widely used in Arctic
service equipment.

Metallic ring with a profile to

match the seal groove minimizes
the extrusion gap as components
Parbak backup ring shift during operation

Parbak backup ring

O-ring
O-ring

Figure 36. O-ring support rings.

Page 33 of 33
This page left blank
 Section 225
Schlumberger COILED TUBING SERVICES MANUAL
Rev A - 98

DEPLOYMENT SYSTEMS

Contents Page Contents Page

INTRODUCTION ......................................... 1 4 COILED TUBING CONVEYED TCPS ....... 10

1 LUBRICATOR DEPLOYMENT .................... 1 4.1 Circulation ball firing head (CBF) .... 10
2 TOOL DEPLOYMENT SYSTEM .................. 2 4.1.1 CBF Operation ................................ 11
2.1 Tool Deployment Sequence .............. 2 4.2 CIRP Deployment System ............... 12
3 SAFE DEPLOYMENT SYSTEM .................. 2 4.2.1 Operation ......................................... 14
3.1 Safe Deployment Sequence .............. 6 4.3 Depth Correlation of Guns When
Conveyed on Coil ............................ 18

INTRODUCTION 1 LUBRICATOR DEPLOYMENT

As the complexity of CT applications has grown, so too The evolution of solutions to this problem started by
has the average length of toolstring required to perform treating the CT equipment and toolstring in a similar
the desired service or work. Since one of the major fashion to wireline, i.e., rig-up sufficient riser or lubricator
benefits of CT applications is safe life well working, it to “swallow” the toolstring and support the entire assembly
was a fundamental requirement that some means of by a crane and necessary guide wires (Figure 1).
safely installing long toolstrings in live wells was devised.
The conditions under which this must be achieved vary While this configuration could be used to complete a
considerably. For example, the configuration of many variety of operations it resulted in a heavy suspended
offshore locations is such that up to 60ft of riser can be load (injector head) and provided little in the way of
fitted between the wellhead (swab valve) and the contingency options. For example, if a problem was
operating level (impact deck or rig floor). Conversely, encountered with the injector head, it was very difficult to
onshore locations carry the inherent disadvantage of reach and inspect/repair while 60 ft above ground level.
already having the swab valve located above the safe
working level (ground level). The principal disadvantages of this system included:

Four basic systems have been used within the Dowell • A large crane (capacity and height) was required to
organization and are outlined in the following section. support the injector head
Note the first two methods described have evolved into
the improved safe deployment system and are not • Operator visibility of all CT and pressure control
generally recommended for use on live wells. components was limited

• Lubricator deployment• • Injector head access is restricted

• Tool deployment • Personnel are exposed to suspended loads during

the rig up procedure
• Safe deployment

• CIRP

* Mark of Schlumberger

Page 1 of 18
 Section 225
COILED TUBING SERVICES MANUAL Schlumberger
Rev A - 98 DEPLOYMENT SYSTEMS

c. Pressure is vented from the lubricator allowing the

bottom connection to be broken, gaining access to
the deployment bar top connection. This connection
is broken and the lubricator assembly and running
tool is laid down.

d. A short riser section is attached to the stripper and

Injector head
the appropriate connection is made up to the CT
stripper
toolstring.

e. The injector head is lowered slowly until the toolstring

connection can be made up to the deployment bar.
Assembled Wireline The toolstring connection is made up, after which the
height up lubricator injector head is further lowered to enable the riser
to 60ft connection to be made (Figure 4).

f. When all connections have been made, confirmation

of pressure integrity is made, the pressure is equal-
ized and BOP rams are open allowing the tool string
to be RIH (Figure 5).
Quad BOP
Wellhead While this system provided a major advancement in the
Connection handling of long toolstrings in live wells, some major
factors still required addressing.

• There is a high dependency on crane operator skills

during crucial stages of the operation.
Fig.1 Lubricator deployment -
equipment configuration. • Operators are still exposed to suspended loads
during the rig-up and rig-down periods.
2 TOOL DEPLOYMENT SYSTEM
3 SAFE DEPLOYMENT SYSTEM
Since the disadvantages listed above were significant
operational and safety issues, an alternative deployment Overcoming the deficiencies summarized above required
method was developed. The system relied on a bar the development of new equipment and techniques to
(deployment bar) installed in the BHA to provide a enable greater control and safety associated with the
means of holding and sealing on the BHA to enable the deployment operation. A deployment bar is still utilized
operation to be conducted in stages. This enabled the in the BHA, however, several new items of surface
working height of the injector head to be significantly equipment are required (Figure 6 and 7).
reduced and provided a means of ensuring pressure
integrity (pressure testing) at all stages. Quick Latch

2.1 Tool Deployment Sequence Provides a quicker and safer means of connecting the
lubricator/injector head assembly to the wellhead
The installation (deployment) sequence entailed: equipment. The quick latch (QL) is operated remotely,
thereby removing the risks associated with operators
a. The tool string and lubricator assembly is rigged as working beneath suspended loads.
for wireline operations and the toolstring RIH until the
deployment bar is opposite the BOP slip and pipe
rams (Figure 2).

b. The pipe and slip rams are closed to secure wellbore

pressure and hold the bar in place (Figure 3).

Page 2 of 18
 COILED TUBING SERVICES MANUAL Section 225
Schlumberger
DEPLOYMENT SYSTEMS Rev A - 98

Sleeve wheel and

stuffing box

Tool string passing

through lubricator

Wireline
lubricator

Blind rams

Shear rams
Ouad BOP
Slip rams
Wellhead
connection Pipe rams

Fig. 2 Insalling the toolstring.

Lubricator removed
leaving deployment
bar exposed

Lubricator
removed Blind rams

Shear rams
Ouad BOP
Slip rams
Wellhead
connection Pipe rams

Fig. 3 Hanging off the toolstring.

Page 3 of 18
 Section 225
COILED TUBING SERVICES MANUAL
Rev A - 98 DEPLOYMENT SYSTEMS

Injector head
assembly lifted
and connected to
lower pressure
control assembly

Tool connection
made

Blind rams

Shear rams
Ouad BOP
Slip rams
Wellhead
connection Pipe rams

Fig. 4 Connecting the toolstring and running string.

Injector assembly
and pressure
control stack
connected and
tested
Lubricator riser
connection made and
tested

Blind rams

Shear rams
Ouad BOP
Slip rams
Wellhead
connection Pipe rams

Fig. 5 Running the toolstring.

Page 4 of 18
 COILED TUBING SERVICES MANUAL Section 225
DEPLOYMENT SYSTEMS Rev A - 98

Wireline
PEH - E head
AH - 38 adaptor
Wireline adaptor
with landing Balance housing
collar for guide
Spacer (for ABOP)
tool location

Conductor
deployment bar
assembly Turndown
section for pipe
and slip rams

Tool String

Fig. 6 Safe deployment system tool string.

Hydraulic supply and Injector head

return

Stripper
1 - QL Open
2 - QL Close Short Riser
3 - Pressure
4a - Return
4b - ABOP Return Quick Latch
5 - Stripper
6 - SDDT Close
7 - SDDT Open Side door
8 - ABOP Close deployment tool
9 - ABOP Open

Hydraulic Control
Panel Annular BOP

Ouad BOP

Wellhead
connection

Fig. 7 System components.

Page 5 of 18
 Section 225
COILED TUBING SERVICES MANUAL Schlumberger
Rev A - 98 DEPLOYMENT SYSTEMS

Side Door Deployment Tool 3.1 Safe Deployment Sequence

Enables the toolstring to be connected after the injector The safe deployment sequence includes the following
head assembly has been connected and secured. This basic steps.
provides several operational and safety benefits.
Note: this sequence is provided for information purposes
• CTU operator controls toolstring connection process. only and does not include all details of checks and
procedures necessary when designing a procedure.
• Injector head is grounded (electrically) before
toolstring connections are made up. a. Rig up equipment as shown in Figure 7

Annular BOP b. Assemble toolstring and install in wireline lubricator.

Make up the QL connector to the lubricator.
The annular BOP (ABOP) provides a contingency
pressure containment function by sealing the annular c. Lift the lubricator on to the wellhead assembly and
gap around the tool sting or CT string as required latch the QL.
(double barrier).
d. Equalise pressure to the lubricator, open the well-
Hydraulic Control Panel head valves and lower toolstring into wellbore until
the tool locates in the SDDT guide (Figure 8).
To ensure all operating functions can be completed
from a position with clear line of sight, all safe deployment e. Close BOP slip and pipe rams (and the ABOP) and
systems are controlled from a hydraulic control panel. vent the lubricator pressure.
The hydraulic connections (flow and return) to the panel
is typically made through the auxiliary BOP hydraulic f. Open the SDDT window and disconnect the running
supply on the CTU. tool and remove the lubricator assembly (Figure 9).

Downhole Equipment g. Fit upper QL connection to injector head assembly

and make up upper toolstring.
The downhole equipment consists of a deployment bar
and a quick connect union system to enable easy and h. Lift the injector head assembly, latch QL, and secure
safe make-up of the toolstring. A guide tool fitted in the guy wires/chains.
SDDT enables positive indication that the deployment
tool is properly positioned across the BOP rams. i. Open the SDDT window, run in with CT until toolstring
connection can be made up (Figure 10 and 11).
Additional Operating Requirements
j. Close the SDDT and pressure test completed rig up
The following operating requirements have been (constrained by WHP below pipe rams/ABOP).
identified as key factors which may jeopardise the
safety or efficiency of the operation. k. Equalise pressures and release pipe and slip rams,
tag stripper to verify depth settings and proceed to
• Cranes must be certified as capable of operating at RIH (Figure12).
the required height, reach and weight.

• Wellhead equipment should be inspected to ensure

that the additional weight and loading can be safely
supported and secured.

• Sufficient securing points should be available at

ground level.

• A work platform should be erected to enable easy/

safe access to the SDDT.

Page 6 of 18
 COILED TUBING SERVICES MANUAL Section 225
DEPLOYMENT SYSTEMS Rev A - 98

Toolstring run/
assembled using
lubricator and
wireline deployment
Tools run through
technique
system to place
deployment bar within
BOP

Quick latch

SDDT
Blind rams

Annular BOP Shear rams

Ouad BOP Slip rams

Wellhead Pipe rams
connection

Fig. 8 Installing the toolstring.

Lubricator removed
at quick latch for
second tool stage Running string
removed from
deployment bar
Quick latch

SDDT

Annular BOP
Blind rams
Quad BOP Shear rams

Wellhead Slip rams

connection
Pipe rams

Fig. 9 Hanging off the toolstring.

Page 7 of 18
 Section 225
COILED TUBING SERVICES MANUAL
Rev A - 98 DEPLOYMENT SYSTEMS

Injector head assembly

connected to lower Second tool stage con-
pressure control stack nected to deployment
bar

Quick latch

Blind rams

Annular BOP Shear rams

Slip rams
Wellhead Pipe rams
connection

Fig. 10 Connecting the running string and toolstring.

Swivel connection to
enable connection to
be made up without
rotating assemblies

Guide tool to
enable safe and
easy stabbing to
connections

Fig. 11 Guide tool and swivel connector.

Page 8 of 18
 COILED TUBING SERVICES MANUAL Section 225
Schlumberger
DEPLOYMENT SYSTEMS Rev A - 98

Window closed

Injector head assembly

connected to lower
pressure control stac,
window closed and
assembly tested

Blind rams

Shear rams

Slip rams
Annular BOP
Pipe rams
Wellhead
connection

Fig. 12 Running the toolstring.

Page 9 of 18
 Section 225
COILED TUBING SERVICES MANUAL Schlumberger
Rev A - 98 DEPLOYMENT SYSTEMS

4 COILED TUBING CONVEYED TCPS Features

In addition to the increase of coiled tubing in conventional • Fired by predetermined tubing pressure, only when
applications in recent years, there has been a similar ball is in seat.
growth in the volume of perforating operations being
carried out on CT. This brought the requirement for a • Unaffected by absolute (hydrostatic) pressure.
specialized firing head to enable the safe conveyance of
the gun string and reliable initiation of the perforating • Unaffected by water hammer while running in hole
process. Additional features required of the system (firing pin release sleeve moves upward).
included the ability to place an underbalance cushion
and the option to release the guns in the rathole. • While running in hole, tubing is filling up.

4.1 Circulation Ball Firing Head (CBF) • Insensitive to vertical drops.

The Circulation Ball Firing Head (CBF) was developed • Allows circulation in either direction, both prior to and
using existing Schlumberger technology and utilizes after gun firing.
standard firing mechanisms, shear pins and operating
principles (Figure 13). • Adaptable to all Schlumberger guns.

Before firing After firing

Fig. 13 CBF Firing head components

Page 10 of 18
 COILED TUBING SERVICES MANUAL Section 225
erger
33
DEPLOYMENT SYSTEMS Rev A - 98

Injector head and

stripper assembly
above quad BOP
Injector head

Stripper (Dual) Quick latch

Quick latch
Gate valve
Quad BOP
Quad BOP adapted
for CIRP systems

Shear\seal BOP

Wellhead Shear\seal BOP

on wellhead

Fig. 14 Equipment configuration (general) for Fig. 15 Typical equipment configuration for CIRP
conventional CT operations operations

• Shear pinnable for pressures up to 6,000 psi above resisted by a set of shear pins. These are loaded by the
hydrostatic, in 500 psi increments. head of the piston rod pushing upwards on the inner
sleeve of the shear set.
Other derivations of the CBF are available. The CDF
and BCF permit gun detonation if direct ball drop is not When sufficient pressure is applied through the coil, the
possible, or if wellbore restrictions require alternative piston, the piston rod, shear set inner sleeve and release
tool assemblies (e.g., slimmer tools). sleeve all move upward. When the lower end of the
release sleeve passes the ball bearings, the balls drop
The CBF allows circulation in either direction before and out releasing the firing pin to detonate the guns.
after firing the guns. Fluid pumped down the CT string
tubing flows through a ball seat at the top connector The piston, piston rod, shear set inner sleeve, and
housing and out of the upper set of ports in the connector release sleeve all continue to move upward, until the
housing to the wellbore. piston is above the upper ports, gain allowing circulation
when pumping through the coil tubing.
4.1.1 CBF Operation
Once pumping ceases, the piston, piston rod, shear set
When ready to fire, a ball is pumped through the coil and inner sleeve and release sleeve stay in place allowing
lands on the ball seat. The fluid from the CT string is then reverse circulation whenever desired.
diverted to the annular space between the double walls
of the connector housing, through the lower set of ports If they drop downward, below the upper ports, the ball
and upward to the bottom side of the piston. can be pumped off its seat, allowing reverse circulation.
If pumping through the coil is resumed, the inner parts
The top side of the piston is open to wellbore pressure will move as described.
via the upper ports. Upward movement of the piston is

Page 11 of 18
 Section 225
COILED TUBING SERVICES MANUAL Schlumberger
Rev A - 98 DEPLOYMENT SYSTEMS

4.2 CIRP Deployment System A sealed ballistic transfer is used on both sides of the
connection. Figure 16 shows the snaplock connector in
The CIRP Deployment System (Completion Insertion the disconnected and connected conditions.
and Retrieval of long gun strings under Pressure) is
designed to allow the running and retrieval of long tool The special BOP uses two modified rams to operate the
strings, regardless of available lubricator. Connections snaplock connector. Both rams have a secondary ram
are made inside the pressure control stack at wellbore located within the primary ram mechanism that provides
pressures utilizing the Safeconn connector system additional functions (Figure 16).
(Drexel).
The large lower ram serves as a no-go ram, closing to
Applications for this technology include the running of a diameter only slightly larger than the slick joint. It also
perforating guns, logging tools, sand screens, coiled has matching gear teeth that engage in the no-go
tubing drilling assemblies or any application where tool groove to prevent rotation of the lower portion of the
string length exceeds available surface riser/lubricator snaplock connector.
height.
The large upper ram closes to a diameter just slightly
The special snaplock connector allows long gun strings larger than the OD of the connector and serves as a
to be run and retrieved under pressure. Placed between centering guide. The smaller internal ram is equipped
two guns, the tool allows the operator to connect and with a rack that, when extended, engages the pinion
disconnect the guns inside a specially modified BOP gear teeth located at the top of the breech lock sleeve of
stack without direct access (Figure 14 and 15). On long the connector. The rack thus turns the breech lock
gun strings several connectors may be used. sleeve to unlock and lock the connector.

Fig. 16 CIRP System components

Page 12 of 18
 COILED TUBING SERVICES MANUAL Section 225
age 1 of 33
chlumberger
DEPLOYMENT SYSTEMS Rev A - 98

The lower half of the snaplock connector has a breech tool together vertically. A special key placed between
lock sleeve with a series of buttress type grooves the fork sub and the breech lock sleeve limits the
(Figure 17). Approximately 50% of the grooves have rotation of the breech lock to 15º, relative to the fork sub
been cut away longitudinally to make a series of vertical to ensure consistent locking and unlocking.
slots in the grooves. A fork sub inside the breech lock
sleeve has external grooves matching those in the A torsion spring attached to the breech lock sleeve and
breech lock sleeve. The fork sub also has approximately anchored to the fork sub with the torque ring, keeps the
50% of the grooves cut away longitudinally. This leaves breech lock sleeve in the locked (engaged) position
grooved fingers, which when lined up with the cut out unless forcibly overcome by an outside force (such as
section (slots) of the breech lock sleeve, allows the fork the ram rack). Approximately 20 foot pounds torque is
sub to slide into the breech lock sleeve until it shoulders. required to rotate the breech lock sleeve to the unlocked
position.
The stinger sub (upper half of tool) also has external
grooves on it which are partially milled away, creating During make-up or break-out, the guns can be run-in or
grooved fingers on the OD. When the remaining grooves retrieved under pressure using either coiled tubing or a
of the breech lock sleeve and the grooved fingers of the wireline. Using wireline (if available) is typically easier
fork sub are aligned vertically and rotationally, a slot is and faster since make-up and break-out of the lubricator
created so that the grooved fingers of the stinger sub is simplified.
can slide in and when properly aligned vertically, the
breech lock sleeve can be rotated (one half the width of The number of snaplock connectors and the number of
the fingers on the Fork Sub). This places the breech lock lifts required on a particular job is determined by the
sleeve grooves over half the fork sub fingers and half length of lubricator that can be used.
over the stinger sub fingers, locking the two halves of the

Pinion teeth

Sleeve
Deployment
stinger

Deployment
Fork sub connection

Latch spring

Deployment
receiver

Fig. 17 CIRP Deployment conectors

Page 13 of 18
 Section 225
COILED TUBING SERVICES MANUAL Schlumberger
Rev A - 98 DEPLOYMENT SYSTEMS

4.2.1 Operation

The following discussion is intended to provide basic With the master valve(s) open, the first gun section is
understanding of the system and does not contain lowered into the wellbore until the slick joint of the
sufficient information to enable job design or execution. snaplock connector is opposite the no-go rams (lower
set of rams) of the BOP stack (Figure 18).
The BOP stack is made up on the wellhead with single
or double master valves between it and the lubricator At this time, the no-go rams are closed on the slick joint
(Figure 14 and 15). A special pick-up and lay-down and the string slowly lowered until it stops. This should
assembly is typically required. This consists of a standard be when the ram lock groove at the top of the slick joint
pick-up nipple, a short gun (for weight) and the top half reaches the ram (Figure 19). Note: the slick joint below
of a snaplock connector. the ram lock groove is smaller than the upset above the
groove.
The top gun of a string is dressed with the lower half of
a snaplock connector. If more than one lift is to be made, The lock ram is then closed (Figure 20) to prevent
the lower end of each subsequent lift will also require the movement in the lower section of the snaplock and
upper half of a snaplock connector. locking it against rotation. Next the guide rams (upper
set of rams) are extended to centralize the upper end of
Although lengths may allow the firing head to be picked the snaplock.
up with the last lift, it is good practice to pick up the safety
spacer with the last gun lift and to make a special lift for A pull test is performed to ensure that the snaplock is
the firing head alone. This allows the firing head to be secured in the proper position within the BOP. The gun
connected with the guns safely below the BOP stack. string is then hung-off on the rams.

With the first lift (bottom of the gun string) made up on The robot arm (within the guide rams) is extended to
the pick-up and lay-down assembly and inside the rotate the snaplock connectors breech lock sleeve to
lubricator, the lubricator is made up on the wellhead as the unlocked position. The upper half of the snaplock
shown. The lubricator is then slowly pressurized to connector is then slowly pulled out of the lower half with
equal wellhead pressure. When the lubricator pressure the cable.
equals the wellhead pressure, the master valve(s) are
opened.

Wireline conveyed toolstring Inner ram - OPEN

Outer Ram - OPEN

Inner ram - OPEN

Outer Ram - OPEN

Fig. 18 Run in to position the slick joint

Page 14 of 18
 COILED TUBING SERVICES MANUAL Section 225
Schlumberger
DEPLOYMENT SYSTEMS Rev A - 98

Inner ram - OPEN

Outer Ram - OPEN

Inner ram - OPEN

Outer Ram - CLOSED

Fig. 19 Close no go rams and set down tool weight

Inner ram - OPEN

Outer Ram - OPEN

Inner ram - CLOSED

Outer Ram - CLOSED

Fig. 20 Close locks and perform pull test

Page 15 of 18
 Section 225
COILED TUBING SERVICES MANUAL
Rev A - 98 DEPLOYMENT SYSTEMS

Inner ram - CLOSED

Outer Ram - CLOSED

Inner ram - CLOSED

Outer Ram - CLOSED

Fig. 21 CIRP Close guide rams and engage rack to disconnect running tool

When the upper half of the snaplock connector is safely With the second lift inside the lubricator, the lubricator is
in the lubricator (above the top of the BOP stack and reconnected to the BOP stack and the internal pressure
valves), the master valve(s) are closed (Figure 21). slowly brought up to equalize wellhead pressure. When
the pressure is equalized, the master valve(s) are
With the master valve(s) closed, the pressure on the opened and the second gun section is slowly lowered to
lubricator is slowly bled off and the lubricator removed engage the snaplock connector (Figure 22). The stinger
ready for the next lift. on the bottom of the second lift enters the mating
snaplock section hung off on the no-go ram.

Inner ram - CLOSED

Outer Ram - CLOSED

Inner ram - CLOSED

Outer Ram - CLOSED

Fig. 22 Run in with next tool string

Page 16 of 18
 COILED TUBING SERVICES MANUAL Section 225
Schlumberger
DEPLOYMENT SYSTEMS Rev A - 98

Inner ram - OPEN

Outer Ram - CLOSED

Inner ram - CLOSED

Outer Ram - CLOSED

Fig. 23 Stab male stinger, open rack and pull test connector

With the second gun section landed, the robot ram is go rams are opened. The gun string is then lowered until
retracted, engaging the breech lock between the stinger the slick joint of the snaplock connector between the top
(attached to the bottom of the second lift) and the lower of the second lift and the pick-up and lay-down assembly
half of the snaplock (attached to the top of the first lift). is opposite the no-go ram.
The cable is then raised, applying a pull to the connection
to ensure it is correctly engaged. At this time, the no-go rams are closed on the slick joint
and the string slowly lowered until it stops. This should
When it is confirmed that the snaplock connector is be when the ram lock groove at the top of the slick joint
engaged, the overpull is decreased to equal the weight reaches the ram. The lock ram is then closed, as before,
of the gun string and the guide rams, lock rams and no- to prevent movement of the lower BHA section.

Inner ram - OPEN

Outer Ram - OPEN

Inner ram - OPEN

Outer Ram - OPEN

Fig. 24 Open guide rams, locks and no-go rams and RIH

Page 17 of 18
 Section 225
COILED TUBING SERVICES MANUAL Schlumberger
Rev A - 98 DEPLOYMENT SYSTEMS

The disconnection sequence as outlined above is The correlation procedure may be summarized as
repeated. follows:

The installation sequence is repeated on each gun • Perforation logs are taken from electric line logs.
section as required to run the desired total length of
guns. • CBL/VDL/GR log will show the casing pip tag on
Schlumberger depth.
The safety spacer with a snaplock connector looking up
is the second last section to be installed. After the safety • Five minute stations are done on the coil. Flags are
spacer lift is landed and locked in the no-go ram, the made on the coil at the top and bottom points.
pick-up and lay-down assembly is laid down, the wireline
stuffing box is removed from the lubricator, and the • Coil depth at the top and bottom flags are noted.
lubricator attached to the coiled tubing stripper. A coiled These depths are taken after moving in the up
tubing firing head such as the CBF with a snaplock direction only.
connector stinger on the bottom of the firing head is
prepared and attached to the bottom of the coiled tubing • MPL tools are generally run through the zone of
as shown in (Figure 23). interest, and this should include some GR
characteristics.
The lubricator is attached to the BOP stack.
• If the zone is flat with its GR response, choose
If it is necessary to pressure test the firing head it can be another nearby zone with some more activity.
safely done at this time, while the firing head in the
lubricator and not yet attached to the gun string. After • 300 ft is about the minimum logging interval and
testing, the lubricator pressure is equalized with the 1,800 ft per hour is the ideal speed.
wellhead pressure.
• The flagging procedure is repeated for a total of three
With the no-go ram open the string is then lowered in the up passes at the same speed.
well (Figure 24).
• Pull out of hole. Make a CCL time mark on each
4.3 Depth Correlation of Guns When Conveyed on memory unit and record carefully.
Coil
• Rig down tools and read memory.
When perforating with conventional TCP guns, a gamma
ray/CCL electric line lay is the normal practice prior to • Plot data corrected for time and depth.
setting the packer. The same technique is used when
electric line perforating is performed on CT. However, in • Logs can be corrected to match electric line log.
purely hydraulic the operation is more complex.
• When running TCP guns, run to bottom flag, and
The most common method uses a memory logging move accordingly up or down to compensate for
string. This involves performing an initial drift run with depth error, locate, and fire.
the CT, which is the memory PL string. The correlation
procedure requires a careful and methodical approach
in order to get it right without complications. Typically,
two tool strings would be run to provide full back up on
the tool functions. The reference point on this type of job
is the coil tubing check valve. This is because the check
valves are common to both BHAs.

Page 18 of 18
 Section 230
COILED TUBING SERVICES MANUAL
Rev A - 98

AUXILIARY SURFACE EQUIPMENT

Contents Page

Introduction .................................................................................................................. 2
1 COILED TUBING LIFTING FRAMES ........................................................................... 2
1.1 Description ....................................................................................................... 2
1.2 Features ........................................................................................................... 2
1.3 Operation ......................................................................................................... 4
2 COILED TUBING JACKING FRAMES ......................................................................... 6
2.1 Description ....................................................................................................... 6
2.2 Features ........................................................................................................... 6
2.2.1 Injector Head Support Frame ............................................................................ 6
2.2.2 Injector Head Support Substructure .................................................................. 7
2.2.3 Multi-Purpose Support Substructure ................................................................. 7
2.3 Operation ......................................................................................................... 8
3 CRANES ..................................................................................................................... 8
3.1 Description ....................................................................................................... 8
3.2 Operational Requirements .............................................................................. 10

Page 1 of 11
 Section 230
COILED TUBING SERVICES MANUAL
Rev A - 98 AUXILIARY SURFACE EQUIPMENT

Introduction Most lifting frames currently used are fabricated from flat
steel plate. Strengthening webs welded on the outside of
There are several items of equipment that may be required the frame also provide some protection for the winch
to enable CT services to be performed under certain supply and control lines.
wellbore, wellsite or application conditions. The items of
special equipment outlined in this section generally relate The lifting capacity of each lifting frame will vary depend-
to the handling of the injector head and pressure control ing on its design and intended purpose. However, most
equipment. lifting frames have a certified lifting capacity of ±300 tons.

1 COILED TUBING LIFTING FRAMES • Winch

1.1 Description When the lifting frame is suspended from the traveling
block and attached to the flowhead or tubing string, any
A lifting frame is required when performing CT operations heave of the ship or rig is seen as a movement in the
offshore from a drillship or semi submersible drilling or suspended string. To provide a safe and practical means
workover rig. The function of the lifting frame is to provide of installing the pressure control equipment and CT
a motion-compensated connection onto which the injector injector head, a winch which is attached to the “moving“
head and pressure control equipment can be assembled. lifting frame must be used.

The bottom connection of the lifting frame is generally Winches are generally of the air-operated tugger design
attached to a temporary or testing flowhead. In most cases, and are controlled remotely from the drill-floor level and/
a load-bearing hydraulic connector is used to expedite the or the lifting frame base via pilot control lines.
rigging up and down process.
The lifting capacity of the winch is generally ±7 tons.
The handling sub of the lifting frame is held in the rig Sufficient wire rope must be available on the winch drum
traveling block elevators. On rigs of this type, either the to allow loads to be lifted from the floor level while the
travailing block or crown block will have a motion-compen- frame is elevated.
sating device fitted to compensate for the wave action and
heave experienced by floating vessels. The weight or • Winch controls
tension in the tubing string, in effect, provides the anchor
on which the motion-compensation system operates. Winch operation is generally controlled by a three-way
pneumatic valve. This is connected to the winch control
1.2 Features spool by pilot lines of sufficient length to allow operation
of the winch from the floor level while the frame is
There are a variety of different lifting frames currently in elevated. The winch should be fitted with an automatic
use. The features described below and identified in Figure brake which engages immediately the winch control is
1 will apply to most designs. However, early designs may returned to the neutral position.
not incorporate some of the features.
• Flowhead/string connection
• Frame
There are three commonly used means of attaching the
Early frames, and some existing designs, use heavy- lifting frame to the flowhead or tubing string to be sus-
weight drillpipe for the frame sides. This offers the pended:
advantage of being able to disassemble the lifting frame
with relative ease for transport or storage. However, the • Bails and riser.
major disadvantage of this design is the lack of rigidity
when handling the frame during rigging operations. • Threaded connection.

• Extended JHS connector.

Page 2 of 11
COILED TUBING SERVICES MANUAL Section 230
AUXILIARY SURFACE EQUIPMENT Rev A - 98

Lifting sub

Air winch

Pad-eyes for lifting

and handling slings

Frame strengthening
webs

Inside connection

Bottom connection

Figure 1. Coiled tubing lifting frame.

Page 3 of 11
 Section 230
COILED TUBING SERVICES MANUAL
Rev A - 98 AUXILIARY SURFACE EQUIPMENT

The illustrations in Figure 2 through Figure 5 show a • Inside connection

typical arrangement of each method.
The inside connection is the connection on which the
The bail and riser method of connection is generally used BOP and injector head are made. This is typically
when a temporary flowhead and subsea completion are to designed to match the BOP bottom connection to avoid
be entered. Threaded connections and the extended JHS the use of crossover connections.
connector are typically used when connecting to well-
testing flowheads. • Lifting sub

The lifting sub is held in the rig elevators. It is commonly

machined to match a common drillpipe or tubing size to
avoid the use of special elevators.
Short lubricator
section passes 1.3 Operation
through hole in
base of frame The weight and size of a CT lifting frame together with the
requirement that it be used on a floating vessel indicate that
the handling and rigging operations must be conducted
using sufficient equipment and personnel to keep control of
the load at all times.
Short bails
Protection of the winch and connections from accidental
damage should be a priority during all handling operations.

Elevators on The illustrations in Figure 6 and 7 show the typical equip-

flowhead lift sub ment configuration during and after rig up.

Figure 3. Bail and elevator.

Threaded connection
supported by flange
attached to lifting
frame base

Figure 4. Threaded connection. Figure 5. Extended JHS connector.

Page 4 of 11
 COILED TUBING SERVICES MANUAL Section 230
AUXILIARY SURFACE EQUIPMENT Rev A - 98

Lifting sub

Air winch

300-ton capacity
frame

CT injector head
Rig tugger line passed
through shackle on
injector head
Non load-bearing
hydraulic connector

Rig tugger line BOP stack

secured to rig floor

Injector head
hydraulic connector

Temporary or testing Load bearing

flowhead hydraulic connector

Figure 6. Coiled tubing lifting frame rig-up detail. Figure 7. Coiled tubing lifting frame typical rig-up
configuration.

Page 5 of 11
 Section 230
COILED TUBING SERVICES MANUAL
Rev A - 98 AUXILIARY SURFACE EQUIPMENT

2 COILED TUBING JACKING FRAMES • Telescopic Legs

2.1 Description Four telescopic legs extend to provide the reach needed
to support the injector head in an elevated position. Pins
A CT jacking frame is designed to support and stabilize the and safety clips are used to secure the legs at the desired
injector head while performing a CT operation on a well height.
where there is no rig, crane or mast. The most common
application of the lifting frame is while operating on offshore • Hydraulic Rams
wellhead platforms. The jacking frame is adjusted hydrau-
lically, although during the CT operation the telescopic legs Each leg is raised by a hydraulic ram which is capable of
must be pinned and secured in position. independent operation to allow proper alignment of the
securing pins and holes.
Jacking frames or specially engineered substructures are
more commonly used on CT applications which are con- Hydraulic power for the jacking frame is supplied by the
ducted over an extended period, or involve several runs into coiled tubing unit (CTU) power pack via a flow and return
the wellbore. hose to the jacking frame control spool located on the
frame chassis. A valve and gauge manifold to allow
2.2 Features independent isolation, operation and monitoring of each
jack leg is located at the base of the jacking frame.
There are three distinct types of jacking frame currently in
use:

• Injector head support frame

Injector head mount
Jacks and supports the injector head. This type of jacking
frame is not designed to take the weight of the injector
head and CT string.

• Injector head support substructure

Jacks and supports the injector head, and has the added
Hydraulic ram
advantage that the injector head can be skidded to one
side, allowing the use of tools, etc. This type of jacking
frame is designed to take the weight of the injector head
and CT string.

• Multi-purpose support substructure

Performs the same functions as the support substruc-

ture, but may also be used in jacking jointed pipe. This
type of jacking frame is designed to take the weight of the
injector head and CT string. Hydraulic hose
reel and controls
2.2.1 Injector Head Support Frame
Frame base
Most jacking frames used on CT operations will include the
following features (see Figure 8).

Figure 8. Typical jacking frame features.

Page 6 of 11
 COILED TUBING SERVICES MANUAL Section 230
AUXILIARY SURFACE EQUIPMENT Rev A - 98

Figure 9. Typical injector head support substructure.

• Injector Mounts 2.2.2 Injector Head Support Substructure

The injector head is secured to the jacking frame by four There are many designs of injector head support substruc-
mounting pins, which are located in the injector-head ture, most of which have evolved from experience in CTD
sleeves normally used for the support legs. operations. In addition to the features listed above, these
structures typically incorporate a facility to hydraulically
• Frame Base skid the injector head off to the side. This enables access
for running and retrieving tools and downhole equipment
The lifting frame base generally has no special features. without the need for addition crane support (Figure 9).
However, consideration must be given to the distribution
of weight once the jacking frame is in use. In some cases, 2.2.3 Multi-Purpose Support Substructure
it may be necessary to use some type of spreader frame
to evenly distribute the equipment weight. Multi purpose support structures will typically include the
features mentioned in the two previous designs plus
The frame base is generally designed with one side open incorporate a jacking system which can be used to run and
to allow the frame to be positioned around the riser or retrieve jointed tubulars Figure 10).
lubricator without requiring the frame to be lifted over any
wellhead equipment.

Page 7 of 11
 Section 230
COILED TUBING SERVICES MANUAL
Rev A - 98 AUXILIARY SURFACE EQUIPMENT

Figure 10. Multipurpose support substructure.

2.3 Operation 3 CRANES

Since the configuration of the wellhead riser/lubricator and 3.1 Description

jacking frame varies depending on application or location,
then so does the rig-up procedure. The requirement for safe operation and maintenance of
cranes and lifting equipment is well documented by manu-
In most operations, almost all of the CT and wellhead facturers and national certifying authorities.
equipment weight will be supported by the wellhead. There-
fore, the primary function of the jacking frame is to allow the This manual section does not replace any of the documents
injector head to be lifted and lowered on the BOP connec- mentioned above, but is intended to outline minimum
tion, thereby permitting access to change or service the operating standards typically required on CT operations.
bottomhole assembly (BHA).
The illustrations in Figures 11 and 12 show the features
If the security or ability of the wellhead to support such found on cranes commonly fitted to coiled tubing units
weight is limited, it may be necessary for the jacking frame (CTU) and crane trucks.
or substructure to be used in such a manner that the
wellhead is protected from excess weight or forces. The specifications of such cranes vary by age and manu-
facturer. However, the capacity and limitations of each
crane must be known by the operator prior to use.

Page 8 of 11
 COILED TUBING SERVICES MANUAL Section 230
AUXILIARY SURFACE EQUIPMENT Rev A - 98

Extending boom
Winch

Boom elevating Slew ring

ram

Control station

Hook with
safety catch
Truck chassis

Extending outrigger

Figure 11. Typical CTU crane - side view.

Winch

Truck chassis
Control station

Extending
outriggers

Figure 12. Typical CTU crane - rear view.

Page 9 of 11
 Section 230
COILED TUBING SERVICES MANUAL
Rev A - 98 AUXILIARY SURFACE EQUIPMENT

3.2 Operational Requirements Vehicle Transportation

Operator Qualifications In addition to the standard safety considerations during

transport, the following points must be considered when
Operation of cranes shall be restricted to qualified person- transporting cranes.
nel within the following categories:
Before Transporting
• Certified, designated personnel that are competent and
experienced in the operation of the equipment to be used. • Ensure that all outriggers and stabilizers are properly
stowed and secured.
• Maintenance and/or test personnel operating the equip-
ment only insofar as it is necessary for the performance • Secure the load-line hook.
of their duties.
• Ensure that the boom is adequately secured.
• Service Supervisor or other CTU crew member operating
the equipment with a designated, experienced person • Ensure that all loose lifting and ancillary equipment is
present. secured.

In addition to the above requirements the operator must: During Transport

• Be able to demonstrate the ability to read, comprehend • Never travel with a load on the hook.
and interpret all placards, operator’s manuals, safety
codes and other information pertinent to the safe and • Ensure that there is sufficient safe clearance before
correct operation of the crane and lifting equipment. passing beneath overhead obstructions.

• Possess knowledge of emergency procedures and imple- Equipment Setup

mentation of same.
As with all mobile equipment to be spotted at the wellsite,
• Be familiar with all relevant safety codes and applicable prior planning of equipment location is of great importance.
government requirements. In addition to the equipment safety and loss prevention
standards applied to wellsite rig-up, the following consider-
• Recognize and be responsible for all maintenance require- ations apply when spotting cranes and lifting equipment.
ments of the crane operated by him or trainees under his
instruction. • The CTU and/or crane truck should be positioned in an
area free from overhead obstructions to allow the entire
• Be thoroughly familiar with the crane and control functions operation to be performed without repositioning the CTU
being operated. or crane.

• Have read and fully comprehend the operating procedures • The crane vehicle must be located on a firm, level surface
as outlined in the relevant Standards of Operation. that will provide sufficient support for the outrigger load-
ing. Use caution when setting up equipment near em-
Equipment Inspection bankments or excavations.

Before operation of the crane or lifting equipment can be • The truck brake must be applied and the drive axle
undertaken, the operator must ensure that current legal disengaged.
inspection requirements have been fulfilled.
• The outriggers must be fully extended to a firm surface
and should be elevated sufficiently to ensure that the
truck is level when viewed from side to side. The front

Page 10 of 11
 COILED TUBING SERVICES MANUAL Section 230
AUXILIARY SURFACE EQUIPMENT Rev A - 98

stabilizers should then be used to ensure that the truck is

level when viewed front to back. A level indicator should
be positioned at the operator's control station. A signal
person should observe the operation of any outriggers or
stabilizers not visible from the operator's control station.

• The crane unit must be positioned so that it is impossible

for any equipment to come within the minimum safe
distance from any energized power line.

A clearance of at least 10 ft must be maintained between

any part of the crane, load line or load and any electrical
equipment carrying up to 50,000V. One foot additional
clearance is required for each 30,000V (or part thereof)
carried. If the voltage is unknown (and therefore the
clearance required is unknown), the electrical utility or
operator should be contacted. Be aware of any extra
clearance required to compensate for wind deflection of the
cables or load line.

All overhead electrical cables should be considered live

until the relevant electrical authority verifies its safe condi-
tion, and the cables are visibly grounded.

Equipment Documentation

In addition to the documentation which must be carried on

trucks and vehicles, the following support documentation
should be available on all cranes.

• Crane manufacturer's operation and maintenance manual.

• A copy of the applicable location safety and loss preven-

tion standards.

• A copy of any applicable local or national regulations,

codes or insurance requirements.

• An illustration showing the standard hand signals to be

used when controlling crane operations.

• A copy of the current inspection record (where applicable).

• A copy of the appropriate crane capacity tables indicating

the crane capacity as determined by the boom radius at
which the load is being handled.

Page 11 of 11
This page left blank
 Section 240
COILED TUBING SERVICES MANUAL
Rev A - 98

DOWNHOLE TOOLS

Contents Page

Introduction ..................................................................................................... 2
1 DOWNHOLE TOOLS ...................................................................................... 2
2 COILED TUBING CONNECTORS ................................................................... 2
2.1 Grapple Connector ............................................................................... 3
2.2 Setscrew/Dimple Connector ................................................................ 4
2.3 Roll-On Connector ............................................................................... 4
3 COILED TUBING CHECK VALVES ................................................................. 4
3.1 Flapper Check Valves .......................................................................... 4
3.2 Ball and Seat Check Valves ................................................................. 4
4 NOZZLES AND JETTING SUBS ...................................................................... 5
4.1 Circulating Subs .................................................................................. 5
4.2 Jetting Subs ........................................................................................ 5
5 RELEASE JOINTS.......................................................................................... 6
5.1 Tension-Activated Release Joints ......................................................... 6
5.2 Pressure-Activated Release Joints ...................................................... 6
6 ACCELERATORS ........................................................................................... 6
7 JARS ........................................................................................................... 7
8 OVERSHOTS ................................................................................................. 8
9 SPEARS ........................................................................................................ 9
10 DEPTH CONTROL ........................................................................................ 10

Page 1 of 10
 Section 240
COILED TUBING SERVICES MANUAL
Rev A - 98 DOWNHOLE TOOLS

Introduction - Conveying retrievable flow control tools - a wide variety of

plugs and flow control devices are commonly used to
The one thing common to all CT operations is that there will selectively control production. The plugs, or locks, may
be something attached to the downhole end of the CT string, be located in specific landing nipples, tubing joints or on
i.e. a bottomhole assembly, toolstring or downhole tool. The the tubing wall.
most simple assembly will comprise a connector, check
valve and circulating nozzle. More complex assemblies will - Operating fixed completion equipment - this principally
contain several tool functions, may be powered through involves the operation (opening and closing) of sliding
electric conductors or hydraulic conduits installed in the CT sleeves, or circulation devices located in the production
string and may communicate (real-time data) with surface tubing or uncemented production liner.
monitoring equipment and systems.
- Conveying gauges or monitoring equipment - gauges and
Regardless of the configuration or complexity of a CT sampling or monitoring equipment can be conveyed by
toolstring, there are several factors which must be consid- wireline or CT, and if necessary secured in a tubing nipple
ered during the planning, design and execution phases of or similar locating device.
the operation. The two most important factors, shown
below, should be considered fundamental to all CT opera- - Wellbore servicing - a variety of well service operations are
tions. commonly performed, generally as preparatory work be-
fore performing other services e.g. tubing drifting, depth
- The dimensions of all tools must be confirmed and noted (fill) check, paraffin removal.
on an appropriate fishing diagram.
- Fishing - coiled tubing fishing operations can provide a
- Any limitations applicable to the tool function, strength or rapid and economic solution to a variety of light- to
pressure integrity must be known. medium-weight fishing problems.

1 DOWNHOLE TOOLS The operational features of CT conveyed tools and techniques

offer the following advantages over conventional wireline
Downhole tools of some description are used on almost all methods:
coiled tubing operations. Most tools currently in use can be
categorized as follows: - Coiled tubing is considerably stronger than slickline or
braided line allowing the application of greater forces and
- Primary tools - coiled tubing connectors and check valves lifting capacity.
are included in this category, i.e. tools which may be
considered essential for all operations. - The rigidity of CT allows access to highly deviated or
horizontal wellbores.
- Support tools - this category includes tools such as a
release joint and jar, i.e. tools which enhance or support - Fluids circulated through the CT can be used to improve
the toolstring function, or provide a contingency release access to the fish or wellbore equipment to be engaged.
function.
- Fluids pumped through the CT can also be used to power
- Functional tools - these are tools selected on the basis of specialized tools.
their ability to perform the intended operation.
2 COILED TUBING CONNECTORS
CT services conducted using nonelectric wireline tool
strings may be categorized as follows: oiled tubing connectors connect various downhole tools to
the end of the CT string. Connectors are commercially
available in a wide range of designs and sizes. However,
three general categories of connectors are typically recom-
mended.

Page 2 of 10
 COILED TUBING SERVICES MANUAL Section 240
DOWNHOLE TOOLS Rev A - 98

Coiled tubing

O-ring

Setscrew Crimped tubing

O-ring

Coiled tubing

Setscrew
Grapple connector Roll-on connector

O-ring

Dimple connector

Figure 1. Coiled tubing connectors

2.1 Grapple Connector

- Grapple connector
Grapple connectors use a wedge or slip collar arrangement
- Setscrew/dimple connector to lock the CT string inside the connector housing. A wide
variety of designs are available including single- and bi-
- Roll-on connector. directional slip assemblies. A double acting bi-directional
design is typically recommended since the CT connector
Selecting the appropriate connector is generally dependent may be exposed to significant compression forces in both
on the application and operator preference. directions, i.e., tension/compression.

Page 3 of 10
 Section 240
COILED TUBING SERVICES MANUAL
Rev A - 98 DOWNHOLE TOOLS

2.2 Setscrew/Dimple Connector

The Setscrew Connector is attached to the CT by set-

screws engaging in preformed dimples. A dimpling tool is
used to place the dimples in the same pattern as formed by Top connection
the screws on the connector. The setscrew connector
attaches to the outside diameter of the CT, and therefore,
interferes less with the internal flow path of the tubing.
Flapper
2.3 Roll-On Connector check valve
assembly
The roll-on connector attaches to the internal diameter of Seat
the CT and is held in place by crimping the CT around a Flapper
connector profile with a special crimping tool. However, the
roll-on connector poses a significant obstruction to fluids,
darts or balls pumped through the CT. In special applications
where an extremely slim bottomhole assembly is required, Bottom connection
and where low torque and tensile strength values are
required, the roll-on connector may be considered a practical
alternative to the grapple and setscrew connector.

3 COILED TUBING CHECK VALVES

The check valve is generally attached to the coiled tubing

connector at the end of the CT string. By preventing the flow
of well fluids into the CT, well security is maintained in the Top connection
event of failure or damage to the tubing at surface. Check
valves should be part of every CT bottomhole assembly and
should only be omitted when the application precludes its
use (e.g. where it is desired to reverse circulate through the Ball and
CT). In most cases it is recommended that tandem check seat check
valves be fitted to provide some redundancy of operation. valve assem-
bly Seat
3.1 Flapper Check Valves Ball

Flapper check valves are, by necessity, becoming more

commonly used. The fullbore (or near fullbore) opening
permits the use of more complex CT tools, fluids and
operating techniques by allowing balls, darts and plugs to Bottom connection
pass through to the toolstring from the CT without restriction.
Most flapper check valves are of similar design, although
some may incorporate a cartridge valve assembly for ease
of maintenance.

3.2 Ball and Seat Check Valves

The ball and seat check valve has been predominantly used
on conventional CT applications because of its simple
construction and ease of maintenance. However, this Figure 2. Coiled tubing check valves

Page 4 of 10
 COILED TUBING SERVICES MANUAL Section 240
DOWNHOLE TOOLS Rev A - 98

design has several limitations including restricted flow area

and bore obstruction. These limitations require using an
alternative when fullbore opening or unrestricted flow area
is required.
Single Large-
4 NOZZLES AND JETTING SUBS
Diameter Port
Nozzles and jetting subs for use on coiled tubing form the
downhole end of the CT bottomhole assembly. These
nozzles and subs are generally of simple design and
construction and are often locally manufactured. The required
jetting action generally determines the position and size of
the nozzle ports. In general, these tools will fall into two
categories.

4.1 Circulating Subs

Nozzles used on operations where fluids are to be circulated

without a jetting action require a large port area. This port
area may be composed of several small ports to increase Multiple Small-
turbulence, or a few large ports; the criteria being that there Diameter Ports
is relatively little pressure drop across the nozzle.

4.2 Jetting Subs

Nozzles used on operations that require jetting action will

have a relatively small port area, usually composed of
several small ports. The efficiency of a jetting nozzle is
largely dependent on the fluid velocity through the port. The
largest constraints on the jetting nozzle design are the
limits of the flow rate and pressure available at the nozzle.
These limits are a result of the relatively large friction
pressure induced within the CT string.

The position, shape and direction of the jet ports affect the
jetting action of the nozzle, and in most cases, are
determined by the intended application. Muleshoe Angled Jet
Nozzle
Combination nozzles are often used to perform special
operations. The various functions of combination nozzles
can be accomplished with a ball or sleeve mechanism
within the nozzle assembly, which is activated to block
certain ports. Simple versions are activated by dropping a
ball through the CT work string.

5 RELEASE JOINTS

Figure 3. Nozzles and jetting subs

Page 5 of 10
 Section 240
COILED TUBING SERVICES MANUAL
Rev A - 98 DOWNHOLE TOOLS

The tension-activated release joint may be regarded as a

weak point in the tool string which will part before any
Upper sub damage is inflicted on the retrieved tool string or the CT.
Most designs use shear pins or screws which, when
sheared, allow the top and bottom assemblies of the
release joint to separate.

5.2 Pressure-Activated Release Joints

Collet
Pressure-activated release joints are generally activated by
Outer housing applying pressure through the CT which in turn exerts a
pressure differential between the inside and outside of the
tool sufficient to activate the mechanism. In many cases, a
ball is circulated through the CT work string to land in a seat
Ball and seat located in the release tool.

This type of release joint is desirable when fishing or jarring,

because of its ability to withstand high-impact loads.
Disc spring
6 ACCELERATORS

A coiled tubing accelerator is used in conjunction with CT

jars. Accelerators generally consist of a sliding mandrel
which compresses a spring when forced in its operating
Lower sub
direction (i.e. up, down, or in some cases, either up or
down).

Placed in the tool string above the jar assembly, the primary
function of the accelerator is to store the energy to be
released when the jar fires. Accelerator action also helps
protect both the tools located above the accelerator, and the
Figure 4. Release joints CT work string from the shock load caused by the jar
impact.

Accelerators used in CT operations operate on one of the

The coiled tubing release joint releases the coiled tubing
following principles:
work string from the CT tool string in a controlled manner
should the need arise. The resulting fishing neck on the tool
- Spring (mechanical)
string in the well allows easy reconnection with an appropriate
fishing tool. Release joints are available with the following
- Compressed fluid (hydraulic)
methods of operation:
Compressed fluid tools are generally called intensifiers and
- Tension-activated release
are less common than spring-operated accelerators in CT
operations.
- Pressure-activated release
Most jar manufacturers offer accelerators or intensifiers to
- A combination of the above
match the jars. Jars and accelerators should be used as a
matched set, alleviating any problems associated with the
5.1 Tension-Activated Release Joints

Page 6 of 10
 COILED TUBING SERVICES MANUAL Section 240
DOWNHOLE TOOLS Rev A - 98

External fishing neck

Upper mandrel and Splined mandrel

seal assembly
Anvil

Hammer

Spring assembly

Spring assembly

Firing mechanism

Adjusting mechanism

Lower mandrel and Mandrel

bottom connector

Figure 5. Accelerator Figure 6. Jar

compatibility of the tools. The accelerator must have an

available stroke which is greater than that of the jar at the corresponding stop on the outer mandrel (anvil).
time of firing.
Most jars release (also called a trip, fire, hit or lick) in one
7 JARS direction only. However, some designs feature the ability to
jar up and down without resetting the tool.
A jar may be described as a device which delivers a sudden
shock (up or down) to the tool string. In coiled tubing An accelerator must be included in any CT bottomhole
applications, jar assemblies generally include a sliding assembly in which a jar is fitted. The accelerator is placed
mandrel arrangement which allows the brief and sudden in the tool string above the jar assembly in order to store the
acceleration of the tool string above the jar. Travel of the energy that will be released when the jar fires.
mandrel is limited by a stop (hammer) which strikes a Jars commonly used in CT operations operate on one of the

Page 7 of 10
 Section 240
COILED TUBING SERVICES MANUAL
Rev A - 98 DOWNHOLE TOOLS

following principles:
Top connector/fishing neck
- Mechanical

- Hydraulic

- Fluid powered (e.g. impact drill)

All three jar types operate on the upstroke; however, only jars
operating on the mechanical and fluid-powered principles are Catch spring
capable of downstroke or dual operation. The ability to jar
down is an important feature which may be required on many
fishing and STIFFLINE* operations. The release of many
overshots, spears and pulling tools often requires a downward
blow at the tool.

8 OVERSHOTS
Catch/release mechanism
Overshots are commonly used on a wide variety of coiled
tubing fishing operations. Overshots are designed to engage
over the fish to be retrieved, gripping on the OD surface of the
fishing neck.

Once latched on the fish, the grip exerted by the overshot

grapple increases as the tool string tension is increased. In
the event the fish or tool to be retrieved is immovable, a release
mechanism can be activated to retrieve the CT and tool string.
This release may be incorporated into the design of the Adjustable stop
overshot (releasable overshot) or may require the operation of
a separate CT release joint (non-releasable overshot). Grapple

It is recommended that only releasable overshots be used in Bowl

CT applications. Non-releasable overshots should be avoided
and only run where the implication of their use is fully
understood.

The design and operation of releasable overshots vary slightly Figure 7. Overshot
among manufacturers. However, the principal features and
components are similar and include the following:

- A catch/release mechanism, usually controlled by a ratchet and completion restrictions.

mechanism, which cycles each time weight is set on the
tool. - A circulation facility which enables the circulation of fluid
and offers significant advantage over alternative fishing
- A bowl/grapple assembly which should be selected only methods.
after consideration of the fishing neck profile, overshot reach
9 SPEARS

* Service mark of Schlumberger

Page 8 of 10
 COILED TUBING SERVICES MANUAL Section 240
DOWNHOLE TOOLS Rev A - 98

Spears of various designs are commonly used on fishing

operations. Spears are designed to engage the fish by Top connection/fishing neck
gripping on the ID surface. Although the preferred method
of engaging a fish is by overshot, the spear provides a useful
alternative when retrieving a fish with a suitable bore.

In the event that the fish or tool to be retrieved is immovable,

a release mechanism can be activated to retrieve the coiled
tubing and tool string. This release mechanism may be
incorporated into the design of the spear (releasable spear)
or, in some cases, may require the operation of a separate
CT release joint (nonreleasable spear). It is recommended Catch/release mechanism
that only releasable spears be used in CT applications.

The design and operation of releasable spears vary slightly

among manufacturers. However, the principal features and
components are similar and include the following:

- A catch/release mechanism, usually controlled by a

ratchet mechanism, which cycles each time weight is Catch spring
set down on the tool (e.g. set down on the fish to catch,
set down again to release).

- A cone grapple assembly which should be made after

considering the fishing neck profile and the completion
restrictions.
Adjustable stop
- A circulating facility which enables fluid circulation and
offers a significant advantage over alternative fishing
methods. Grapple
Nose cone

Figure 8. Spear

Page 9 of 10
 Section 240
COILED TUBING SERVICES MANUAL
Rev A - 98 DOWNHOLE TOOLS

10 DEPTH CONTROL Downhole locating tools have been developed to identify

known reference points within the wellbore or tubing string.
Depth sensitive applications, such as perforating, zonal Tubing end locators and tubing nipple locators are mechani-
isolation and selective treatments have always presented a cal tools designed with a precise geometry and which
challenge for CT operations. Several factors influence the provide a surface indication (increase in CT string tension)
shape and condition of the CT string within the wellbore: as thet are retrieved through the target tubing nipples or
tubing end. This enables a reference point to be identified
- Pressure and temperature with reasonable accuracy for a range of applications.
- Stretch However, any subsequent tubing movement will again
- Helical and sinusoidal buckling induce a depth or location error that may in some circum-
- Plastic deformation stances be unacceptable if the treatment zone is far from
the nearest reference point.
Since the depth measurement system of standard CT units
measure the CT string before it enters the wellbore, the Depth correlation against the original base well log is
effect of the above factors will create a variation from the generally accepted as being the most accurate means of
depth measured. While in some cases this induced error applying a wellbore treatment. In recent years this has only
may be relatively insignificant, in depth sensitive applica- been possible by the use of casing collar locator tools run
tions even minor variations in depth may compromise the on wireline, or in CT strings equipped with an installed
accuracy and efficiency of the treatment. logging cable.

The DepthLOG* depth correlation system provides real-

time surface data from a casing collar locator tool via
pressure pulses induced in the fluid circulated within the CT
Pressure pulses
string. This system enables highly accurate treatments to
through CT string
be performed using standard CT equipment.

Sender

Processor
Sensor

Pressure pulses
processed to
provide log

Figure 9. DepthLOG system components.

* Service mark of Schlumberger

Page 10 of 10
 Section 245
COILED TUBING SERVICES MANUAL
Rev A - 98

HIGH-PRESSURE JETTING

Contents Page

Introduction ................................................................................................... 2
1 BLASTER SERVICES .................................................................................. 2
1.1 J e t Blaster .................................................................................................. 3
1.2 Bead Blaster ................................................................................................ 4
1.3 Bridge Blaster .............................................................................................. 5

Page 1 of 6
 Section 245
COILED TUBING SERVICES MANUAL
Rev A - 98 HIGH-PRESSURE JETTING

INTRODUCTION

The buildup of solid deposits in wellbore tubulars is a

significant problem in many wells. The deposits result in a
reduced flow area and in severe cases can impact the
productivity if the well. Additionally, the deposits can
interfere with the running, retrieval and operation of downhole
tools and equipment. The composition of wellbore deposits
may be organic, inorganic or a combination of both. Inor-
ganic deposits in the form of scale are precipitated mineral Thread protector
solids. They typically occur due to temperature and pres-
sure changes or the mixing of incompatible waters, for
example formation water and injection water. Scale is most
commonly encountered in wells where water injection is
used to maintain reservoir pressure.

Conventional scale removal techniques include:

- Chemical treatments using low pressure wash tools

- Drilling with downhole motor and mill assemblies

- Mechanical removal using impact hammer Blaster tool body

incorporating brake and
1 BLASTER SERVICES bearing assemblies

The introduction of Blaster* Services has extended scale

and wellbore deposit removal options to include a reliable
high-pressure jetting technique that can be adapted for a
range of applications. The Blaster tool string is based on a
high-pressure rotating jet that provides reliable one-pass
cleaning (Figure 1). To ensure that the treatment param-
eters and fluid design process delivers the optimum hydrau-
lic horse-power in the jet, an Advisor software package has
been developed to assist the job design process. Lower bearing assembly

The addition of specifically designed solid beads to the fluid

enhances the cleaning efficiency of the system and enables
extremely hard scales to be removed from tubing or profiled
completion components without a minimal danger of dam-
aging or eroding the component material. Drift ring

Blaster Services are categorized in three distinct groups. Rotating head

- Jet Blaster*

- Bead Blaster*

- Bridge Blaster* Figure 1. Jet blaster tool - general assembly.

* Mark of Schlumberger

Page 2 of 6
 COILED TUBING SERVICES MANUAL Section 245
HIGH-PRESSURE JETTING Rev A - 98

1.1 Jet Blaster The system can be used to deliver chemical dissolvers to
remove soluble scale or other obstructions. Jetting the
The Jet Blaster system has been developed from a compre- dissolver into the target generates turbulence at the chemi-
hensive research study of the physics behind the jetting cal contact surface increasing the efficiency of the dissolver
process. The system replaces traditional jetting and wash system. With this process we can reduce acid consump-
tools which are good at cleaning out loose fill, but are tion by up to 10 times or remove obstructions that could not
inefficient and limited in applicability. Jet Blaster also be removed by simply pumping.
replaces the more aggressive mill/motor or impact hammer
combinations, which are not suited to removing consoli- Positive, one-pass cleaning is ensured by a drift ring (patent
dated fill and are damaging to the tubulars and jewelry. pending) on the tool assembly that prevents penetration of
the head until the deposit is removed to the diameter of the
The Jet Blaster jetting head and nozzles are selected to ring. In this way, the risk of CT string fatigue problems
optimize the hydraulics of the entire system, maximizing caused by multi-pass cleaning is minimized.
the hydraulic horse-power delivered to the jetting nozzles
and minimizing the hydraulic losses in the remainder of the Reliable circulation of cuttings is enhanced since the drift
system (Figure 2). ring traps and re-cuts large cuttings. This minimizes BHA
sticking due to the fall-back of cuttings that cannot be
The nozzles are profiled to generate coherent jets with a circulated to surface.
minimal energy dispersion maintaining the performance
right into the target. As with all jetting systems selection of nozzle sizes and
flow rates is a critical factor in the success of a job. The Jet
The rotating head uses two radial jets to clean the wall of the Advisor computer program was developed to optimize the
tubing. For the application of fill or bridged material removal jetting process and select the proper nozzle size based on
a third jet is added to the head to drill a hole ahead of the tool. well conditions to maximize head penetration rate (ROP).

Blaster tool body

Drift ring
High-energy jet

Figure 2. Jet Blaster Tool Profile

Page 3 of 6
 Section 245
COILED TUBING SERVICES MANUAL
Rev A - 98 HIGH-PRESSURE JETTING

1.2 Bead Blaster

Bead Blaster techniques further enhance the efficiency of

jetting by using a gelled water system containing Sterling
Beads, a specially engineered solid particle suited to a wide 0.75 mm
range of treatments (Figure 3). The action of this particle
laden fluid will economically remove hard, inert deposits
such as barium sulfate without the use of costly, and often
ineffective dissolvers.

Unlike any other abrasive material, Sterling Beads readily

remove the hardest scales while minimizing the risk of
tubular damage in the event that the head stalls and
prolonged contact is made on one spot. These unique
properties were achieved by carefully controlling and select-
ing the hardness, shape, size, density, and fracture tough-
ness of the Sterling Beads.

Full-scale tests under downhole conditions showed that Figure 3. Microscopic view of Sterling Beads.
glass beads were 11 times and sand 28 times more
damaging to steel components than the Sterling Beads.
The results also showed that the beads cut barium sulfate
at the same rate as sand but cause virtually no damage to
steel even with a stationary jet. The tests were conducted
at flow rate of 1 bpm, 2500 psi nozzle pressure, and 3000
psi hydrostatic pressure.

Tubing sample before Bead

Blaster treatment Blaster treatment

Figure 4. Tubing samples recovered before and after treatment.

Page 4 of 6
 COILED TUBING SERVICES MANUAL Section 245
HIGH-PRESSURE JETTING Rev A - 98

1.3 Bridge Blaster Between the mill and motor is a radial jetting head adapted
from the Bead Blaster technology to clean back to the
The Bridge Blaster service combines the benefits of a tubing wall or wellbore jewelry. The nozzles are specially
motor/mill system with the safe and effective Sterling Bead designed to minimize loss of jet efficiency due to turbu-
abrasive jetting system. The system can drill through lence, drag, and fluid swirl.
medium and hard scale or cement plugs while efficiently
cleaning to the tubing or completion component without risk Rotation of the mill and jetting assembly is achieved by a
of damage to the component material or associated pro- specially modified PDM designed to safely handle the
files. In addition the system can be used through tubing to Sterling Bead abrasive system.
drill and under-ream a plug in the larger casing below.
The jetting system allows the tool to under-ream larger
The system uses a 1-5/8-in. PDC mill to drill a pilot hole in holes through tubing without the mechanical complexity, or
the bridge. The mill is sized so that it will not contact the unreliability, of expanding cutters. The jetting system is
tubulars or wellbore jewelry, removing the possibility of enhanced by use of the Sterling Beads abrasive system
damage. that will economically remove hard, inert deposits such as
barium sulfate without the use of costly, and often ineffective
dissolvers.

Figure 5. Bridgeblaster tool used to clean tubing with little or no drift diameter .

Page 5 of 6
 Section 245
COILED TUBING SERVICES MANUAL
Rev A - 98 HIGH-PRESSURE JETTING

THIS PAGE INTENTIONALLY LEFT BLANK

Page 6 of 6
 Section 247
COILED TUBING SERVICES MANUAL
Rev A - 98

MULTI-LATERAL WELL ACCESS

Contents Page

Introduction ................................................................................................... 2
1 Discovery MLT System ................................................................................. 2

Page 1 of 4
 Section 247
COILED TUBING SERVICES MANUAL
Rev A - 98 MULTI-LATERAL WELL ACCESS

INTRODUCTION 1 DISCOVERY MLT SYSTEM

Multi-lateral wells provide significant production advantages The Discovery MLT* system is designed to re-enter multi-
and are increasingly popular choice for efficient reservoir lateral wells with a CT tool string. All tools are flow-operated
drainage in several regions. However, conventional well and monitored, thereby eliminating the need for electrical
servicing and workover techniques are not generally com- tools or connectivity with surface monitoring equipment
patible with the wellbore configurations encountered in (Figure 2).
multi-lateral wells (Figure 1). This makes the execution of
even relatively simple stimulation or remedial treatments The system comprises several tools to enable the function-
difficult, if not impossible. The flexibility and versatility of CT ality and contingency operation required for safe and
conveyed treatments provide obvious benefits in the major- reliable service in potentially complex wellbore conditions.
ity of well service activities. Combined with a reliable means The key tool of the Discovery MLT system is the Control-
of accessing the lateral wellbores, CT now provides a unique lable Bent Sub (CBS). This has two functions, to detect the
solution to the treatment of multi-lateral wellbores. window of a wellbore lateral and then, if required, guide the
BHA into the lateral. A knuckle joint assembly within the
CBS allows the necessary degree of flexibility in the lower
assembly, which is normally straight but is actuated to the
bent position when fluid circulation commences.

Figure 1. Multi-lateral well classification - World Oil, January 1999.

* Mark of Schlumberger

Page 2 of 4

Figure 1. CoilFRAC equipment rigged up at the wellsite.

 COILED TUBING SERVICES MANUAL Section 247
MULTI-LATERAL WELL ACCESS Rev A - 98

Disconnect

Circulating
valve

Orienting tool

Controllable
bent sub

Figure 2. Discovery MLT primary system components.

The orientation of the tool string is controlled and adjusted aperture, a pressure signal is sent to surface. The surface
by the orienting tool (OT). The orienting tool rotates in 30 pressure-monitoring devices provide data to custom de-
degree increments enabling the CBS to be navigated into signed software that plots the circulating pressure against
the desired lateral branch when it has been located. depth of the tool string (Figure 3). Multiple upward passes
are made across the known lateral window depth, a process
Additional tools in the tool string include a release joint or known as window profiling. After each pass, fluid flow-rate
disconnect to enable retrival of the running string in the event cycles are applied to activate the orienting tool which
that the toolstring becomes stuck, a downhole filter to rotates to enable a window profile log to be produced.
protect the flow actuated components from debris and a
circulating valve that enables higher circulation rates for When the initial lateral is found and entered, the monitoring
specific treatments. software is setup to follow subsequent orienting tool cycles,
thereby assisting the engineer and CT unit operator navi-
The action of the toolstring is monitored by pressure pulses gate further laterals or subsequent re-entry of the same
induced in the fluid circulated through the CT string. When lateral without the requirement for multiple passes (Figure
the lower assembly of the CBS kicks into the window 4).

Page 3 of 4
 Section 247
COILED TUBING SERVICES MANUAL
Rev A - 98 MULTI-LATERAL WELL ACCESS

Figure 3. Window profiling log produced from depth and pressure plots.

Figure 4. System displayonce set to known lateral entry.

Page 4 of 4
 Section 310
COILED TUBING SERVICES MANUAL
Rev A - 98

DESIGN METHODOLOGY

Contents Page

Introduction .................................................................................................... 2
1 DESIGN METHODOLOGY ............................................................................. 2
1.1 Job Design Data .................................................................................. 2
1.2 Design Software .................................................................................. 4
1.2.1 Tubing Forces ...................................................................................... 4
1.2.2 Fatigue Tracking Software .................................................................... 4
1.2.3 Operating Limit Software ..................................................................... 4
1.2.4 Wellbore Simulator .............................................................................. 4
1.2.5 Friction Pressure ................................................................................. 6
1.2.6 Foam Cleanout .................................................................................... 6
1.3 Operating Limits And Procedures ........................................................ 7

Page 1 of 7
 Section 310
COILED TUBING SERVICES MANUAL
Rev A - 98 DESIGN METHODOLOGY

Introduction Databases within the design software are used to track the
history, and more importantly the fatigue to which CT
As coiled tubing operations become more complex, a workstrings may be subjected.
thorough and methodical job design process becomes
essential. Although the majority of the job design process Figure 1 shows a generalized CT job design sequence. In
is performed away from the wellsite, many potential execu- complex or sensitive applications, several iterations of
tion problems or hazards can be identified. With timely each stage may be required to ensure the desired results.
identification, operational problems or hazards may be Conversely, the design of routine treatments is often driven
resolved without risk to the client’s interests, or the safety and tuned by experience.
of personnel and equipment. Therefore, the job design
process must be regarded as an investigation and prepa- The evaluation phase is necessary to complete the CT
ration procedure for all aspects of the intended operation - operation and assess the design efficiency.
not simply the selection of an appropriate treatment,
toolstring or equipment configuration. 1.1 Job Design Data

1 DESIGN METHODOLOGY The data required to enable the job design process to be
completed varies with the type of application and its
Fundamental to any job design process is a full understand- complexity. Most sections of this manual contain a sum-
ing of the operation objectives. The ultimate success of the mary and brief description of the typical data required for
operation will be gauged by the client against these each application. The principal areas of investigation are
objectives, therefore, a clear understanding is essential. In shown below and are grouped in three categories: data
some instances, the objectives may be economically or obtained from well records, information relating to product
operationally misguided. A review of influencing factors and service availability, and the requirements of regulatory
should be conducted, along with suggested alternatives agencies.
which will provide improved return on investment or greater
operational success. Operator company sourced:

In almost all CT applications, the workstring functions as • Reservoir parameters

a conveyance method for treatment fluids or toolstrings.
Therefore, to complete a treatment design some knowl- • Wellbore conditions
edge and understanding of the associated service is
required (e.g. matrix stimulation or squeeze cementing). In • Surface or location limitations
many cases a number of alternative treatments or means
of application may be identified. While some may be Service company sourced:
quickly dismissed due to economic or availability reasons,
it is prudent to assess all options to ensure that the • Product availability/compatibility
selected treatment is optimal in terms of efficiency and
economics. • Equipment and tool availability

A major component in the design of CT operations is the Regulatory requirements:

use of computer software. Such software provides design
support for a wide range of CT applications through vali- • Operational requirements or limitations
dated models which are used to simulate conditions antici-
pated during the operation. The resulting outputs are used The output of representative plots and values from com-
to confirm the operation can be safely completed under the puter models is greatly dependent on the input of accurate
given conditions. data. Consequently, some effort should be made to ensure
the accuracy of job design data. While acquiring this data,
the operation objectives should be confirmed by investigat-
ing the desired changes in wellbore or reservoir conditions.

Page 2 of 7
 COILED TUBING SERVICES MANUAL Section 310
DESIGN METHODOLOGY Rev A - 98

Determine operation objectives

Acquire job design data

Define operating limits
deternined by reservoir or
wellbore conditions Identify possible treatments
based on availability of
products, tools and equipment

Select treatment type

Identify the applicable
requirements of regulatory
agencies
Apply relevant CADE design
processes

Prepare fluid pumping schedule

• To simulate the workstring loads
Define operating limits and stresses anticipated during
determined by treatment Select CT equipment the job
selection
• To predict fluid rates and
Apply CT software design pressures during the anticipated
process operation

• To ensure the anticipated

Define operating limits treatment can be safely
deternined by CT and pressure completed within the useful life
control equipment selection of the workstring
and configuration
Confirm the selected treatment
and equipment are capable of
achieving clients objectives

Prepare/provide graphical
outputs and plots for
comparison during the operation

Prepare detailed job procedure

Execute job and evaluate

results

Figure 1. Generalized coiled tubing job design methodology

Page 3 of 7
 Section 310
COILED TUBING SERVICES MANUAL
Rev A - 98 DESIGN METHODOLOGY

The design methodology adopted for each job is dependent the effect of wellhead pressure. The module can predict
on the application or operation to be completed, and in weight indicator readings, the point of helical buckling and
many cases prior experience is the best guide. However, lock-up. The principal functions and outputs are:
several factors apply to all CT operations and must be
considered during all phases of the job design and execu- • Confirming that the selected workstring and tool assembly
tion: can be run to the desired position in the wellbore.

• Well security - it is essential that adequate well security • Verifying that the selected toolstring will pass any doglegs
is maintained to guard against the exposure of personnel, or wellbore anomalies.
equipment and the environment to wellbore pressure and
fluids. • Providing a predicted weight indicator reading vs. depth
plot for running in and pulling out of the wellbore. This plot
• Personnel safety - performing the necessary tasks using enables the operator to compare predicted and actual
the required safety equipment, or with equipment on values, allowing anomalies to be detected (Figure 2 ).
standby for immediate use as required.
1.2.2 Fatigue Tracking Software
• Operating limits - the operating and safety limits of all
equipment and tools must be known by relevant opera- This module predicts the remaining useful life of a workstring.
tors. The operation must be designed and executed within It operates in conjunction with a database, which is main-
such limits. tained for each CT reel. The reel length (including changes),
pressure cycle history and acid exposure history is up-
• Operating standards - the operation must be executed, as dated for each operation. In addition, it may calculate the
designed, by trained and competent personnel in accor- fatigue damage imposed on the tubing due to the sequence
dance with applicable operating practices, regulations of pressure and bending cycles.
and safety standards.
The principal functions and outputs include:
1.2 Design Software
• Predicting the life remaining in each workstring element.
Design software which allows modifications and additions This information is presented in a plot of life remaining (%)
to be easily made is essential. The software should include vs. distance from the downhole end of the string (ft)
the following principal job design modules: (Figure 3).

• Tubing forces • Details of the anticipated operation can be input to ensure

that the operation can be completed safely.
• Fatigue tracking software
• Minimizing the risk of tubing failure during an operation.
• Operating limit software
1.2.3 Operating Limit Software
• Wellbore simulator
This module determines the pressure and tension limits for
• Friction pressure a workstring under the anticipated wellbore conditions. The
effect of workstring ovality is also considered when calcu-
• Foam cleanout lating the collapse pressure limit.

1.2.1 Tubing Forces The principal functions and outputs are:

The tubing forces module analyzes the loads applied to the • Graphically depicting the safe pressure and tension limits
CT. These include buoyancy, frictional drag, stripper fric- for the workstring in a given wellbore (Figure 4).
tion, reel back tension, workstring and toolstring weight and

Page 4 of 7
 COILED TUBING SERVICES MANUAL Section 310

W EIG HT IND IC ATO R R EA DING (lbf) DESIGN METHODOLOGY Rev A - 98

9000 Measured
RIH (model)
PO OH (m odel)

4500

500

4,000 8,00 0

M EA SU RED DEP TH O F S TR ING (ft)

Figure 2. Tubing forces graphical output of weight indicator load versus measured depth of toolstring
PR EDIC TED LIFE R EM A ININ G (% )

60 We ld Location
Previous Life
50 Current Life

40

30

20

10

2,000 4,000 6,000 8,000 10,000

D ISTA NC E FRO M D O W N H O LE EN D O F STRIN G (ft)

Figure 3. Output plot of coiled tubing versus distance from downhole end of coiled tubing

Page 5 of 7
 Section 310
COILED TUBING SERVICES MANUAL
Rev A - 98 DESIGN METHODOLOGY

1.2.4 Wellbore Simulator 1.2.5 Friction Pressure

The wellbore simulator models the transient, multi-phase The friction pressure module determines friction pressure
fluid flow and particle transport in a wellbore environment. gradients for Power Law, Newtonian, Bingham Plastic and
It also determines circulation rates and pressures and foam rheological models. It is also used to select fluids,
models the mixing and flow of all solids, liquids and gasses rate and pressures for input to the wellbore simulator.
in the annular flow stream.
The principal functions and outputs are:
The principal functions and outputs are:
• Providing fluid friction, pressure and rate data for use in
• Determining treatment feasibility and enabling equipment other software modules.
and product selection (including quantity) for a treatment.
• Providing graphical output of friction pressures for various
• Predicting the rate of gas, liquid and solid returns, allowing fluids in a given CT workstring and annular configuration.
efficient operations to be conducted at the wellsite.

• Quantifying return fluid composition, allowing appropriate

disposal arrangements to be made.

M aximum A llowable M aximum Allowable

Pressure (P ma x ) Tension (T max )

12
10
PRE SSU RE (psi x1000)

8
6
4
2
0
-2
-4
-6
-8
-10
-12

-10 -5 0 5 10 15 20 25 30 35

C O M PR E SSIO N/TEN SIO N (lbf x1000)

Figure 4. Output plot showing safe pressure and tension limits

Page 6 of 7
 COILED TUBING SERVICES MANUAL Section 310
DESIGN METHODOLOGY Rev A - 98

1.2.6 Foam Cleanout

The foam modules calculate the rates and volumes of liquid

and gas required to achieve a desired bottomhole pressure
and foam quality.

The principal functions and outputs are:

• Detailing the pump rates and volumes of liquid and gas

required to maintain the specified bottomhole foam qual-
ity.

• Surface choke pressures required to maintain desired

wellbore conditions.

1.3 Operating Limits And Procedures

Operating procedures should be prepared to ensure correct

execution of the intended operation, as designed and in a
safe manner. These must be prepared for every CT
operation. The operating limits of the CT workstring and
applicable components of the toolstring should be consid-
ered during the preparation of the job procedure. In addition,
workstring and toolstring operating limits should be docu-
mented - either within the job procedure or as an appendix.

• Contingency Plans

Contingency plans should be prepared for use should

unplanned conditions be encountered during an opera-
tion. These may include emergency procedures to main-
tain control of well pressure or surface equipment. CTU
operators must be fully familiar with these procedures.

• Emergency Procedures

Emergency procedures may be defined as an immediate

response to conditions which threaten well security, or
personnel safety. Such responses are enacted as a result
of detailed training, familiarity with equipment and ex-
ecuted with the knowledge and awareness of the wellbore
and operational conditions.

Page 7 of 7
This page left blank
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98

WELLBORE MAINTENANCE

Contents Page
Introduction .................................................................................................... 3
1 FLUID CIRCULATION AND WELL KILL .......................................................... 3
1.1 Design ................................................................................................. 3
1.1.1 Remedial Fluids ................................................................................... 3
1.1.2 Well Control Fluids .............................................................................. 4
1.1.3 Fluid Density ....................................................................................... 4
1.1.4 Fluid Type ............................................................................................ 5
1.1.5 Fluid Placement .................................................................................. 5
1.1.6 Well Control Techniques ...................................................................... 5
1.1.7 Wait and Weight Method ...................................................................... 7
1.2 Execution ............................................................................................ 8
1.2.1 Execution Precautions ........................................................................ 8
1.3 Equipment Requirements .................................................................... 8
1.4 Well Kill Execution .............................................................................. 9
2 WELLBORE FILL REMOVAL ........................................................................ 10
2.1 Design ............................................................................................... 10
2.1.2 Wellbore and Completion Geometry ................................................... 12
2.1.3 Logistical Constraints ........................................................................ 13
2.1.4 Fill Characteristics ............................................................................. 13
2.1.5 Fluid Performance ............................................................................. 14
2.1.5 Deviated Wells .................................................................................. 15
2.1.6 Fluid Selection .................................................................................. 16
2.1.7 Downhole Tools .................................................................................. 18
2.1.8 Junk Removal ................................................................................... 19
2.1.9 Computer Modeling ........................................................................... 20
2.1.10 Fill Removal Operations .................................................................... 21
2.2 Execution .......................................................................................... 21
2.2.1 Execution Precautions ...................................................................... 21
2.2.2 Equipment Requirements .................................................................. 21
2.2.3 Coiled Tubing Equipment ................................................................... 21
2.2.4 Pressure Control Equipment .............................................................. 21
2.2.5 Downhole Tools and Equipment ......................................................... 21
2.2.6 Auxiliary Equipment .......................................................................... 22
2.2.7 Treatment Execution .......................................................................... 22
2.3 Fill Removal Evaluation ..................................................................... 22
2.4 Sand Removal Using Concentric Coiled Tubing .................................. 23
3 SCALE AND ASPHALT REMOVAL .............................................................. 25
3.1 Design ............................................................................................... 25
3.1.1 Design Data ...................................................................................... 25
3.1.2 Scale/Deposit Characteristics ........................................................... 25
3.1.3 Wellbore/Completion Geometry ......................................................... 27
3.1.4 Logistical Constraints ........................................................................ 27

Page 1 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

WELLBORE MAINTENANCE

Contents Page

3.1.5 Chemical treatments ......................................................................... 28

3.1.6 Jetting ............................................................................................... 28
3.1.7 Low Pressure Jetting ......................................................................... 29
3.1.8 High Pressure Jetting ........................................................................ 29
3.1.9 Rotational Drilling/Underreaming ........................................................ 29
3.1.10 Impact Drilling ................................................................................... 30
3.1.11 Scale Inhibition .................................................................................. 31
3.2 Execution .......................................................................................... 31
3.2.1 Execution Precautions ...................................................................... 31
3.2.2 Equipment Requirements .................................................................. 31
3.2.3 Coiled Tubing Equipment ................................................................... 31
3.2.4 Pressure Control Equipment .............................................................. 32
3.2.5 Downhole Tools and Equipment ......................................................... 32
3.2.6 Auxiliary Equipment .......................................................................... 32
3.2.7 Treatment Execution .......................................................................... 32
3.3 Evaluation ......................................................................................... 33

Page 2 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

Introduction company standards. Therefore, all such requirements

must be known before the operation commences.
This manual section outlines the equipment and processes
commonly used in resolving wellbore conditions which may The configuration of CT equipment enables well control and
inhibit productivity or prevent wellbore access. Wellbore kill operations to be more easily undertaken than is generally
maintenance activities are frequently conducted prior to possible using a rig or snubbing unit. The CT stripper
other matrix or reservoir treatments to ensure that fill or provides the great advantage of being able to run or retrieve
materials are not relocated into the producing formation. tubing under pressure. In addition, the reel swivel allows
fluids to be pumped continuously while running into, and out
1 FLUID CIRCULATION AND WELL KILL of the wellbore.

Many types of fluid are commonly circulated through CT Additional factors which must be considered when designing
workstrings. Fluid characteristics depend on the intended CT conveyed operations include the following.
application. Most fluids may be classed as:
• Friction Pressure
• Remedial fluid
Due to the relatively small diameter (ID) of the CT, high
• Well control fluid friction pressures and the corresponding reduced pump
rates must be considered.
In addition, function, fluids may be pumped to prevent
collapse of the workstring while in the wellbore. • Tubing Length

Conventional workover activities performed using a rig In conventional drillpipe and tubing conveyed operations,
require a column of kill-weight fluid as a primary well control the tubing length is equal to the depth of circulation. On
barrier. Consequently, the most important aspect of workover the CT conveyed operations, the CT workstring length,
well safety is the placement and maintenance of the fluid- and therefore volume remains constant regardless of
column barrier. To enable this to be achieved reliably and depth.
safely, a number of industry accepted well-kill and pressure
control procedures have been developed. • Check Valve

On CT conveyed services, the stripper(s) serves as the Because the majority of CT operations are performed with
primary pressure-control barrier, thereby allowing operations downhole check valves fitted, special procedures are
to be performed safely on live wells. The check valves, required to determine the tubing shut in pressure used in
generally fitted to the downhole end of the CT prevent well control calculations.
migration of wellbore fluids inside the workstring and should
also be regarded as pressure control equipment. This The design and use of remedial and well kill fluids is
configuration provides a high level of protection but principally determined by the intended application and
complicates the application of established well control/well availability/cost. To achieve the necessary fluid properties,
kill procedures. additives are commonly used.

Regardless of the application or type of fluid, the density 1.1.1 Remedial Fluids
and volume of fluids pumped on all CT operations must be
closely monitored and recorded. Remedial fluids may be water-based, oil-based or gaseous,
and may be further categorized as treatment fluids, power
1.1 Design fluids or kick-off fluids.

The placement and maintenance of a fluid column barrier

against reservoir pressure is often conducted to
specifications set by regulatory authorities and/or operating

Page 3 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

• Treatment fluids
The relative efficiency of fluids when compared to substi-
These may be injected into the formation, or circulated tute fluids of lesser cost should be considered.
around the wellbore. Treatment fluid characteristics are
designed to suite the intended treatment and conditions • Safety and Environment
under which it will be applied.
Remedial fluids are frequently corrosive or toxic. Conse-
• Power fluids quently the handling, preparation and disposal of such
fluids must be performed with regard for the safety of
Used to power hydraulically actuated downhole tools (e.g. personnel and the environment.
motors, impact hammers or orientation devices). Power
fluids are designed to be compatible with the tool require- 1.1.2 Well Control Fluids
ments, workstring/toolstring configuration and cutting
carrying ability. In addition, they should be compatible Well control fluids used in CT operations are used to kill the
with the wellbore fluids production facilities as required. well and provide a well control barrier, generally to allow
subsequent operations to be completed safely. The fluid
• Kick-off fluids characteristics are designed or modified to suit the reservoir
and wellbore conditions. In the majority of cases,
Circulated to restore or initiate production. Kick-off fluids characteristics similar to those shown for remedial fluids
are designed to suite the reservoir and completion condi- are required.
tions. In addition, they should be compatible with down-
stream production facilities. In most cases, the objective of the operation will be to
render the well in a balanced condition i.e., no formation
The desired characteristics or features of the above fluid fluid can enter the wellbore, and wellbore fluid is not lost to
groups can include the following. the formation. Fluid loss to the reservoir is undesirable for
reasons of economy (i.e., the cost of the product lost) and
• Stability the potential of near-wellbore damage.

Stability and a predictable performance over the range of 1.1.3 Fluid Density
conditions under which the fluid may be used. The effects
of pressure, temperature and extended time should be Kill-weight fluid denotes the density of fluid required to
considered, e.g. fluids containing suspended solids such balance the bottom hole hydrostatic pressure with the
as weighting agents, or the risk of brine crystallization at reservoir pressure in the producing formation. In reality, a
surface conditions. slightly higher hydrostatic pressure is maintained for safety,
with provision being made to avoid losses.
• Compatibility
If the reservoir pressure is known (e.g., wireline conveyed
Fluids must be compatible with other fluids and materials shut-in pressure survey) the required kill-fluid density is
which it may contact during the treatment/operation. The easily calculated.
use of spacer fluids is a common technique of overcom-
ing compatibility or contamination conflicts. Additives, If no reservoir data is available, it is necessary to assess
such as inhibitors, may be used to increase compatibility the bottom hole conditions. Conventional well control
with wellbore equipment or materials. techniques use the shut in drill pipe pressure (SIDPP) to
help assess the bottom hole pressure (BHP). However, the
• Solids content check valve fitted on most CT operations can prevent the
pressure indicated at the reel from indicating a true shut-in
Some applications require clean fluids, i.e., fluids which tubing pressure.
have been filtered to remove damaging solids.
A true shut-in tubing pressure can be determined through
• Cost

Page 4 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

the following procedure.

Loss of kill fluid to the formation is undesirable for reasons
a. With the annular choke closed, start the pump at a slow of economy and potential damage to the formation. Lost
rate and observe the pressure build up in the reel. The circulation materials are commonly included in the fluid
pressure will gradually rise then level off as the check design of well kill operations. The requirement for such
valves open, thus indicating an approximate tubing shut materials are determined by the formation characteristics
in pressure. and wellbore conditions. Appropriate materials can be
dispersed in the kill fluid or spotted separately as a fluid-
b. If the pressure does not level off, continue to pump until loss control pill.
the annular pressure increases slightly (50-100 psi)
then shut down the pump. • Surface Equipment

c. Slowly bleed the increased pressure until the formation In addition to the normal CT and well control equipment,
pressure closes the check valve. The pressure indi- several other key items of equipment may be required. A
cated at the reel is the approximate shut in tubing surface choke must be used to control wellbore pressure,
pressure. thereby enabling static conditions to be maintained at the
formation face.
1.1.4 Fluid Type
The capacities of the mixing, storage and pumping
Well control fluids used in wells which are to be returned to equipment must be sufficient to allow the operation to be
production are generally solids-free and water-based (e.g. completed as designed.
filtered brines). Such fluids are generally readily available,
easier to mix or handle and are formulated to minimize 1.1.6 Well Control Techniques
damage to producing formations. The fluids must be
compatible with the formation fluids and wellbore/completion Several well control techniques have been developed,
equipment. principally for conventional rig equipment. Since no specific
procedures have been developed for CT operations an
1.1.5 Fluid Placement understanding of the conventional techniques is
recommended.
To successfully place a column of fluid in a wellbore
several factors should be considered. Key to the success of well control operations is preventing
further influx of reservoir fluids into the wellbore as the
• Contamination operation progresses. Since conventional well kill methods
are intended for drilling operations, they typically rely on
Contamination of the fluid column can reduce the density, increasing the density of an existing fluid column. In such
and therefore the efficiency of a well control fluid. The conditions, circulation in excess of one wellbore volume is
contamination can be due to the commingling of wellbore generally required due to fluid slippage and bypassing.
fluids with the kill fluid, or continued influx of reservoir
fluids during the kill- fluid placement process. In the majority of cases, CT well kill operations are
performed in producing wellbores which have completion
Using CT to place the fluid column overcomes many of tubulars in place. The completion tubulars reduce the
the difficulties associated with bullheading kill fluids. wellbore volume and also make placement easier since the
Circulation of a denser fluid into the wellbore through CT smaller fluid interface reduces the likelihood of
can normally be achieved with a small fluid interface and contamination. However, since the returned fluid cannot
minimal contamination. In all cases consideration must generally be treated and reused, more than one wellbore
be given to controlling the wellbore returns and bottomhole volume of prepared fluid is generally required.
pressure during placement.
Most well control techniques derive the BHP from the
• Fluid Losses

Page 5 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

WELLBORE GEOMETRY
Measured depth (MD) (ft) Kickoff point (ft)
True vertical depth (TVD) (ft) Deviation (deg)
Casing Top (ft) Bottom (ft) Size (in.) Weight (lb/ft)
Capacity (bbl/ft) CT annular capacity (bbl/ft)
Liner Top (ft) Bottom (ft) Size (in.) Weight (lb/ft)
Capacity (bbl/ft) CT annular capacity (bbl/ft)
Production tubing Top (ft) Bottom (ft) Size (in.) Weight (lb/ft)
Capacity (bbl/ft) CT annular capacity (bbl/ft)
Production tubing Top (ft) Bottom (ft) Size (in.) Weight (lb/ft)
Capacity (bbl/ft) CT annular capacity (bbl/ft)

BOTTOMHOLE CONDITIONS
Bottomhole pressure (BHP) (psi) Bottomhole temperature (BHT) ( F)
Fracture gradient (FG) (psi/ft)Pore pressure Pp (psi)
Reservoir fluid Hydrogen sulfide (H2S)
Current wellbore fluid Density (lbm/gal)

COILED TUBING AND PRESSURE CONTROL EQUIPMENT

Workstring size (in.) Length (ft) Capacity (bbl/ft)
Total volume Displacement volume (bbl/ft)
Maximum allowable wellhead pressure (MAWP) (psi)

PUMPING EQUIPMENT
Available hydraulic horsepower (HHP) Maximum pressure (psi) Pit/tank volume (bbl)

KILL FLUID REQUIREMENTS

Overbalance required1 (psi) Required density (lbm/gal)
Type of fluid Volume required (bbl)

1
A safety factor should be included in the hydraulic calculations to ensure that the kill-fluid hydrostatic pressure exceeds
the reservoir pressure. This overbalance pressure is typically specified by the client

Figure 1. Job design data for wait and weight well kill method.

Page 6 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

surface tubing pressure. This requires consideration of the the preferred method of killing a well. The drillers method
friction pressure induced while pumping through the requires two wellbore volumes to be circulated.
drillstring. Typically, on conventional operations, the
circulation pressures (kill rate pump pressure) is noted at 1.1.7 Wait and Weight Method
a predetermined pump rate (kill rate). On CT operations the
friction pressures are considerably higher, and are generally So called because the well is shut in (wait) while sufficient
modelled or calculated. fluid of the correct density (weight) is prepared. In
conventional operations, the kill fluid is circulated into
Two common well kill techniques are: place with the annular back-pressure adjusted to follow a
predetermined graph which gives the tubing circulating
• Wait and weight method pressure for the volume pumped. The required adjustments
are carried out at the annulus choke, thus ensuring a
• Driller's method constant BHP.

The wait and weight method is more applicable to CT A modified version of this method is recommended for well
applications since only one wellbore volume circulation is kill operations performed through CT. The basic procedure
required. Also, sufficient fluid, of the correct density, is is:
prepared before the well kill operation begins. It is generally
a. Determine the BHP and fluid density necessary to

BOP kill port

Pumping Tee or well-
head production facil-
ity used for fluid circu-
lation

Production tubing
Process/recirculation
Coiled tubing
Process/disposal

Figure 2. Typical equipment configuration for well kill or fluid circulation operations.

Page 7 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

control the producing formation. sable wellbore condition must be confirmed by performing
necessary flow checks before the well can be regarded as
b. Prepare a sufficient volume of kill fluid (wellbore volume, dead.
from point of circulation + CT workstring volume +
safety factor for contamination or fluid slippage). Equipment

c. Fill the CT workstring with kill fluid while running in to the All treating and monitoring equipment must be spotted and
lowest circulating point. operated in accordance with the requirements of the relevant
Standards of Operation. In addition, equipment certified for
d. Select an appropriate pump rate which can be constantly use in hazardous areas, must be operated and maintained
maintained throughout the operation (kill rate). in accordance with the operating zone requirements (e.g.
Zone II equipment).
e. With the CT nozzle at depth, start pumping at the kill rate
and establish the circulating (pump) pressure. This 1.3 Equipment Requirements
circulating pressure must be maintained for the duration
of the operation. Control of the circulating pressure is Coiled Tubing Equipment
achieved by adjusting the surface choke .
One of the essential parameters to be monitored is tubing
1.2 Execution surface pressure (pump pressure at the reel manifold). A
high degree of accuracy and reliability is required. If
The principal objective during well kill operations is to possible/practical, two gauge readings should be made at
maintain a constant bottomhole pressure, sufficient to the reel manifold.
prevent the influx of reservoir fluids into the wellbore. To
achieve this safely and efficiently, accurate monitoring and Pressure Control Equipment
recording of key parameters (weight, depth and pumped
fluids) is essential during all phases of the operation. The configuration of CT pressure control equipment allows
well control operations to be completed safely and efficiently
1.2.1 Execution Precautions with a high degree of flexibility. Presure control equipment
should be configured to allow easy and safe flow checks to
Execution precautions to be observed during CT circulation be performed.
or well kill operations principally relate to the maintenance
of adequate barriers against well pressure and fluids. The Auxiliary Equipment
consequences of incorrectly assuming a well is dead can
be severe, therefore, adequate checks must be conducted The fluid mixing, handling and pumping equipment must
to ensure the stable condition of the well before pressure be:
control equipment is removed from the wellhead
• Of adequate capacity.
Personnel
• Configured to provide the necessary volume of fluid at the
All personnel involved in the design or execution of CT well required density. Density variation throughout the treat-
kill operations must be familiar with requirements detailed ment volume is undesirable.
in the relevant Standards of Operation.
A choke and gauge array is required to control and monitor
Well Security wellbore fluid returns from the annulus. Typically, a manifold
independent of the production equipment is used, although
The control of well pressure and fluids must meet the in some cases the production choke may be used.
requirements of relevant Standards of Operation. In addition
the requirements of the operating company and applicable Returned fluids are generally routed to normal production
regulatory authorities must be known. Well security, or a facilities. If returned fluids are to be stored on surface,

Page 8 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

precautions must be taken to ensure safe and provision must be made to keep the wellbore full of kill
environmentally compatible handling and storage practises. fluid while the CT is being removed. Failure to do so may
result in swabbing reservoir fluids into the wellbore or
1.4 Well Kill Execution reducing the fluid column below a safe hydrostatic pres-
sure.
The steps required to successfully kill a well depend on the
conditions encountered. The following is a rough guide. Flow Check

Wellbore Preparation • Confirmation that the well is in a balanced and stable

condition should be made before rigging down the coiled
• Operations associated with the well kill should be re- tubing and pressure control equipment . Generally, this is
viewed to determine the most appropriate sequence of achieved by observing the fluid level at surface.
events. For example, the production capability of the well
may assist in fill removal or scale removal operations. Flow check conditions specified by the operating com-
pany or regulatory authority must be used when determin-
• In many cases, prior to placing a column of kill fluid in the ing the condition of a well which has been killed.
wellbore, it is necessary to spot a lost circulation pill
across the producing formation. Circulation Kick-off Execution

• In low pressure or sensitive formations, it may be Well kick-offs initiated by circulating lightweight fluids can
necessary to circulate the wellbore to a known fluid be regarded as reverse well kill operations. A similar
density before attempting to load the wellbore. equipment configuration is required to maintain balanced
conditions at the producing interval while the fluid column
Fluid Mixing and Pumping is placed. This is often necessary to reduce the loss of
costly brines or well control fluid to the production system.
• Wellkill fluids must be thoroughly mixed to provide an
accurate and consistent density over the entire volume. Fluid pumped, and fluid returned volumes must be closely
Recirculation lines or agitators should be used to prevent monitored to help ensure the premature production of
stratification of different density fluids. reservoir fluids.

• Dense fluids should be placed in wellbores from the

bottom up to minimize channeling or contamination. This
generally easily achieved using CT.

• The progress of the kill fluid through the CT reel and around
the wellbore should be monitored by observing pressures
and volumes.

• Continuous monitoring of fluid volume in vs. fluid volume

out is vital.

• Pumping of kill fluid should normally be continued until a

satisfactory, uncontaminated sample is returned at sur-
face.

• A clear line of communication must exist between CTU

operator, pump operator and choke manifold operator.

• If the kill fluid is placed with the CT string in the wellbore,

Page 9 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

2 WELLBORE FILL REMOVAL ously circulate through CT while maintaining a high level of
well control enables fill removal to be completed efficiently
The removal of fill material from producing wells is histori- with minimum disruption to production.
cally the most common application of CT services. The
process is commonly known by several names, including, In most cases, fill is removed by circulating a fluid through
sand washing, sand jetting and wellbore or fill cleanouts. the CT while slowly penetrating the fill with an appropriate
The aims of fill removal are to: jetting nozzle. The fill material is entrained in the fluid flow
and is circulated out of the wellbore through the CT/
• Restore the production capability of the well. production tubing annulus. It is crucial that the annular fluid
velocity is greater than the settling velocity of the fill
• Permit the free passage of wireline or service tools. material in the fluid.

• Ensure the proper operation of downhole flow control Chemical or mechanical techniques can be used to assist
devices. removal. Chemical removal of fill may not be a viable
method due to the low solubility of common fill materials.
• Maintain a sump (space) below the perforated interval to Mechanical removal may simply involve jetting and circu-
allow complete passage of tools or as a contingency tool lation. Where consolidated fill is present, the assistance of
drop area. a drill motor or impact drill and bit may be required.

• Remove material which may interfere with subsequent A technique has been developed using concentric coiled
well service or completion operations. tubing to remove sand from horizontal wells.

When designing a fill removal treatment, the source of the 2.1 Design
fill material should be thoroughly investigated. This helps to
determine the most appropriate removal technique, and The initial steps for designing an appropriate fill removal
may indicate that a secondary treatment at the source will technique require thorough investigation of the following:
prevent further production of fill material.
• Wellbore and completion geometry
Common types of fill material include:
• Reservoir parameters
• Formation sand or fines
• Surface equipment/logistical constraints
• Produced proppant or fracturing operation screenout
• Fill characteristics
• Gravel-pack failure
A summary of data required is shown in Figure 3.
• Workover debris (e.g. scale particles)
2.1.1 Reservoir Parameters
For the purpose of fill removal operations, fill materials can
be broadly divided into three categories: The following reservoir parameters affect the choice of fill
removal technique:
• Sludge or very fine particulates
Reservoir Pressure
• Unconsolidated particulates
This is the most important consideration when determining
• Consolidated particulates an appropriate fill removal technique. Accurate bottomhole
pressure (BHP) data is needed to design a pumping
In most cases, CT provides the only viable means of schedule to carry the fill material to the surface without
removing fill material from a wellbore. The ability to continu- incurring losses. Under ideal conditions, the annular fluid

Page 10 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

FILL REMOVAL DESIGN DATA

Completion

- Production casing/liner and tubing details, e.g. size, weight, grade, depths, deviation, nipples
or restrictions, material/alloy, etc.
- Perforation details, depth, interval, shot density, etc.
- Completion or wellbore fluid details, e.g. type, density, losses, etc.

Reservoir

- Reservoir temperature and pressure

- Porosity and permeability
- Formation sensitivity
- Gas/oil contact, water/oil contact

Production and Surface Equipment

- Production logs/history
- Configuration of production and surface equipment
- Storage and disposal facilities/limitations

Fill Characteristics

- Particle size and geometry

- Material density
- Solubility
- Consolidation
- Estimated volume of fill material
- Presence of viscous material

Figure 3.

Reservoir Temperature

column hydrostatic pressure plus friction pressure should Due to the relatively low circulation rates associated with
balance the BHP. CT, the bottomhole static temperature (BHST) should be
used when designing treatments.
Additional system pressure can be applied by adjusting a
surface choke located on the fluid returns line. If the Accurate reservoir temperature data are essential for the
reservoir pressure is insufficient to support a full liquid design of treatments containing foam or nitrogen slugs. In
column, fluids such as foam, nitrified fluids or nitrogen and addition, the rheology and density of many fluids are
liquid slugs should be considered. affected by temperature.

Page 11 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

Formation Sensitivity Restrictions

The potential to damage the producing formation must be Nipples and other internal restrictions in the completion
minimized during any treatment. The sensitivity of the tubulars should be regarded as possible bridging points and
formation may preclude the use of some fluids, requiring areas of possible localized erosion.
the use of compatible fluids or fluids with a low fluid loss.
In completions where fill is to be circulated through a small
2.1.2 Wellbore and Completion Geometry annulus or restriction, it may not be possible to maintain
adequate annular velocities without overpressuring the
Tubular Size reservoir.

The tubular, or minimum restriction size, will determine the Deviation

maximum OD of CT string that can be safely used. Using
a CT work string with the largest possible OD increases the The ability of fluids to successfully carry and remove fill
annular velocity and available treatment fluid pump rate. from the wellbore decreases as the deviation increases.
Highly deviated and horizontal applications require special
Fill removal in larger tubulars is complicated by two factors design and execution considerations.

• Pump rates required to achieve efficient fill removal are

increased

• Larger tubing can potentially contain higher volumes of fill

material

Production packer

Nitrogen from destabilized

foam

Production packer Foam

Figure 4. Conventional and uphole packer completions.

Page 12 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

Completion Packer STANDARD MESH/PARTICLE SIZE

The oil contained in an uphole completion packer can US Standard Particle
destabilize foams. Design and execution techniques must Mesh Size diameter (in.)
take account of this.
3 0.2500
4 0.1870
2.1.3 Logistical Constraints
5 0.1320
Logistical constraints include the use or placement of
8 0.0937
equipment, and the disposal of the fill or carrier fluid.
10 0.0787
12 0.0661
Equipment
16 0.0469
Generally, complex job designs require more equipment. If
20 0.0331
space at the wellsite is a constraint (e.g. offshore), some
30 0.0232
job design options may be precluded. An additional space
constraint can be included if the returned fill/fluid is not to
35 0.0197
be processed by normal production facilities, and additional
40 0.0165
surface equipment is required.
50 0,0117
Disposal
60 0.0098
100 0.0059
Disposal of the resulting fill material/carrier fluid must be
200 0.0029
considered. Straightforward circulation treatments can be
designed to reduce the volumes required and minimize
270 0.0021
subsequent disposal. However, more complex job designs
325 0.0017
can result in large volumes of fluid for disposal.

Certain types of fill or scale are classed as low specific Figure 5. Standard mesh sizes.
activity (LSA) radiation sources (e.g. strontium and barium
sulfates). Appropriate monitoring and protection measures
must be taken to ensure safe operations. The local or
national requirements or regulations associated with the estimated using particle size and density data, fluid prop-
processing and disposal of LSA solids must be adhered to. erties and completion and work-string geometry (Figure 5
through Figure 7). By comparing the settling rate with the
2.1.4 Fill Characteristics minimum annular velocity anticipated during the operation,
the design feasibility can be checked.
To ensure the greatest efficiency of any fill removal
operation, the physical properties of the fill material must be Particle size and density are generally determined by
known. A sample of material should be obtained for laboratory analyses or estimated from well/field historical
physical and chemical analyses. The fill characteristics data. The size range of particles in a recovered sample can
required for the job design include the particle size and be extensive. To design for total removal of all fill material,
density, solubility, and compressive strength. the particle settling velocity of the largest particles should
be used for annular fluid velocity design calculations.
Particle Size and Density
Particle Solubility
To enable a fluid to carry fill particles in a vertical wellbore,
the velocity of the fluid must exceed the settling rate of a Fill removal operations can be simplified if the fill can be
particle in the carrying fluid. The particle settling rate can be chemically dissolved by acid or solvents. However, totally

Page 13 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

TYPICAL WELLBORE FILL MATERIAL PARTICLE

SIZE AND DENSITY
Drag Buoyancy
Fill US Standard Density
Material Mesh Size Range (SG)
Proppants

Sand 12 to 70 2.65
Resin-Coated Sand 12 to 40 2.56
ISP 12 to 40 3.20 Weight
Sintered Bauxite 16 to 70 3.70
Zirconium Oxide 20 to 40 3.15
Figure 7. Forces acting on particles during removal.
Drilling/Workover Fluid Solids

Barite - 4.33
Bentonite - 2.65
Calcium Chloride - 1.75
Sodium Chloride - 2.16
Calcium Carbonate - 2.71
Since obtaining samples of such compacted fill material is
often impractical, determining the level of mechanical
Wellbore debris
assistance required is generally based on experience or
availability of tools.
Steel - 7.90
Brass - 8.50
2.1.5 Fluid Performance
Common Elastomers - 1.20
In considering various fluids for removal of a fill material,
Formation Materials
several mathematical models may be used depending on
the fluid type. The fluid types commonly encountered are
Sand and Fines 100 to 350 2.65
Newtonian, non-Newtonian and foam. Additionally, nitro-
gen and a liquid (Newtonian or non-Newtonian) can be
Figure 6.
pumped in alternate slugs.

These models, if used correctly, can provide an approxima-

tion of the fluid (or particle) performance. They provide an
soluble fills are uncommon and are generally the result of understanding of the factors which affect fluid or particle
plugs or pills placed during previous workover operations. performance in fill removal operations.

Nonetheless, some chemical action can be beneficial in the Newtonian/Non-Newtonian Fluids

removal of compacted fills by jetting special fluids. Since
obtaining samples of such compacted fill materials is often Newtonian fluids have a constant viscosity, and a shear
impractical, the formulation of treatment fluids is com- rate proportional to the shear stress. Water, brines and light
monly based on local experience and well history. oils are Newtonian fluids. Such fluids have a low viscosity
and are relatively easy to place in turbulent flow.
Compressive Strength
Non-Newtonian fluids have a nonlinear shear rate - shear
Heavily compacted or consolidated fill often requires some stress relationship. Gelled water- and oil-base fluids are
mechanical means of breaking or loosening of the material. commonly used non-Newtonian fluids.

Page 14 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

52% 85% 96%

Nitrified Liquid (Slugs) Wet Foam Dry Foam Mist
Foam Viscosity

Stable foam range

suitable for fill removal
operations 80 to 92% FQ.

Liquid
Viscosity Gas
Viscosity

25 50 75 100
Foam Quality (%)

Figure 8. Foam quality versus foam viscosity.

Liquid and Nitrogen Stages

Fill removal operations should be conducted with an annu-
lar fluid velocity at least twice (x2) the settling velocity of A common fill removal technique involves pumping liquid
the particles. and nitrogen in alternating stages, rather than simulta-
neously when generating foam. The principal advantage of
Foam this technique is increased annular velocities caused by
the expansion of the gaseous nitrogen. In addition the
Foams are formed by combining nitrogen gas with a base hydrostatic pressure of the fluid column is significantly
fluid and a foaming agent. In fill removal operations, the reduced.
base fluid can have a water or oil base. Higher viscosity
foams can be generated by foaming a gelled base fluid. The particle carrying ability of the fluid system is based
solely on the carrying ability of the base fluid.
Two factors influence the properties of the foam — the base
fluid composition and the proportion of gas added to the 2.1.5 Deviated Wells
liquid.
Fill removal techniques in highly deviated and horizontal
The types of fluid/foam generated in various foam quality wellbores require several special design and execution
ranges are shown in Figure 8. Fill removal operations considerations.
should be designed with foam in the 80 to 92% FQ range.
During production or attempted fill removal operations,
Foam quality is highly dependent on pressure and tempera- material can rapidly accumulate on the low side of the
ture. For this reason the foam returns to the surface must wellbore. Once the fill has settled, it is difficult to re-
be choked to maintain the annular fluid below 92% FQ. establish particle transport.

Page 15 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

Dunes formed as fill

material drops from
the circulated fluid Wellbore fill to be
removed

Figure 9. Particle behaviour in horizontal wellbores.

In some cases, the fluid velocity may be sufficient to carry 2.1.6 Fluid Selection
the fill along the horizontal section, but insufficient to lift it
through the build angle into the vertical wellbore (Figure 9). Fluids used in the removal of wellbore fill material are
This is due to the gravitational effects which cause the selected following consideration of the following criteria:
particles to accumulate and slide down the low side of the
tubular. Such effects are most evident at inclinations of 30 • Bottomhole pressure
to 60°.
• Particle carrying ability
Studies have shown that hole cleaning in a horizontal
wellbore is optimized when the fluid is in turbulent flow. • Friction pressure
However, in many cases, turbulent flow is not possible due
to the flow and pressure restrictions imposed by the CT • Logistical constraints
work string, or the relative size of the completion tubular.
• Disposal
To compensate, the rheology of the fluid must be modified.
Alternatively, in some cases, the annular velocity can be • Compatibility
maintained above the critical rate by pumping slugs of
nitrogen and liquid. In such cases, the liquid selected • Cost.
should be capable of achieving turbulent flow at relatively
low rates (i.e. Newtonian fluids).

Page 16 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

A software tool (hydraulics/wellbore simulator) should be Compatibility problems with oil-base fluid systems are
used to determine the ideal fluid for a particular operation, likely to be less restrictive than those of water-base
and to establish an estimated flow rate which provides the systems. However, compatibility should never be as-
necessary transport of fill. sumed, and basic laboratory compatibility tests should be
performed when possible.
Water/Brine
Disposal of the carrier fluid is generally handled by normal
The general availability, low cost and generally straightfor- production facilities. However, separation of the fill material
ward handling requirements of water and light brines make may require that fluids are rerouted to temporary separa-
them popular as a basic fluid used in most workover tion/production facilities. Separation and recirculation of
operations. flammable fluids are generally impractical for safety rea-
sons. Consequently, larger volumes of fluid than would be
Water and light brines are commonly used as fill removal necessary on recirculated water-base systems are re-
fluids in applications where the BHP is greater than the quired.
hydrostatic pressure exerted by the fluid column, and the
annular space is small enough to ensure the high annular Similar to water/brine, light oils exhibit no particle suspen-
velocities required by such fluids. sion properties under static conditions. Therefore, it is vital
that an adequate annular fluid velocity is maintained for the
Newtonian fluids can be easily placed in turbulent flow duration of the operation.
which provides a useful scouring action. In addition,
Newtonian fluids generally provide the best jetting action if Gelled Fluids
compacted fill is to be removed.
Water-base gels are the most common fill removal fluid
Formation sensitivity and compatibility with wellbore fluids used in applications which require improved particle carry-
should be checked prior to introducing aqueous-base fluid ing and suspension ability.
into the wellbore. Compatibility problems can generally be
overcome by the use of stimulation fluid additives. The viscosity of gelled fluids is dependent on formulation
and temperature. Therefore, it is important that the fluid
Under static conditions these fluids exhibit no particle design accurately reflects the anticipated wellbore tem-
suspension capabilities. Therefore, it is vital that an ad- peratures, and the field mixing procedures closely follow
equate annular fluid velocity is maintained throughout the the designed formulation.
operation.
The high viscosity of gels results in increased friction
Oil/Diesel pressures, which can restrict the pump rate. However, the
improved particle carrying ability of gelled fluids adequately
Light oils used in fill removal operations possess Newtonian compensates for the reduction in annular velocity.
fluid characteristics similar to those discussed for water/
brine. The most significant advantages of light oil are Formulations and rheology data for most gel types are
improved compatibility and the reduction in fluid density, shown in the Stimulation Manuals. However, laboratory
extending its suitability for operations in wells with a lower tests should be run to obtain rheology data for the designed
BHP. gel at the applicable temperature.

Operations involving such flammable fluids require safety, Liquid and Nitrogen Stages
logistical and environmental concerns to be addressed.
Personnel involved with the design or execution of flam- Staged treatments are effective in several applications
mable fluid operations must be familiar with the require- where conventional fluid treatments are at the limit of their
ments of the applicable Standards of Operation. effectiveness:

Page 17 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

• The CT/tubular annulus size is at the extreme range of the Nitrogen Gas
fluid’s capability.
Fill removal operations using only gas as a transport
• The length of the CT work string limits the desired pump medium are applicable in low BHP or liquid-sensitive gas
rate due to friction pressure. wells. Such applications generally use the production
capability of the gas well to assist the nitrogen achieve the
• The hydrostatic pressure exerted by a conventional fluid critical annular velocity required to initiate solids transport.
column is too great. In such applications, erosion of the CT or completion
equipment is a concern due to the high annular velocities
• Foam is not a practical alternative. required. An additional concern exists in that pumping
operations must be uninterrupted.
The pumping schedule should ensure that the fill is pen-
etrated only when liquids are at the nozzle. When N2 is at 2.1.7 Downhole Tools
the nozzle, the CT should be stationary or withdrawn.
The downhole tools referred to here are those required over
Foam and above the primary CT downhole tools normally required
(e.g. check valve/connector).
A good quality stable foam provides the best particle
carrying capability of any fluid. Provided a high degree of Small fill particles that are not compacted can usually be
backpressure control is exercised on annular returns, foam successfully removed by fluid action alone. However, in
may be used on a wide range of BHP conditions. Although some cases, it is desirable to use a tool string equipped to
foam treatments are closely associated with low and very provide some mechanical assistance as a contingency
low BHP treatments, the technique can be successfully measure. This can be provided by jetting tools, drill motors
applied to fill removal in very large tubulars. or impact drills. Additional tools may also be required to
support the operation (or provide contingency release) of
However, foam treatments are subject to more logistical the tool string.
and operational constraints than most other fill removal
techniques. Also, foam is a poor jetting fluid and is Removal of very large particles or workover debris con-
unsuitable for many applications where the fill is com- tained within the fill may require the use of specialized
pacted and requires some jetting action to ensure complete fishing tools.
removal.
The following are some basic requirements of tools to be
Water-base foams are destroyed by hydrocarbons, conse- used in association with fill removal operations:
quently, treatments must be performed without reservoir
fluids entering the wellbore. • The flow rate through the tool string should not be
restricted below that required to provide the desired
Stable foams can only exist in the foam qualities shown in annular velocity.
Fig. 6. An approximate measure of foam stability is foam
half-life. The foam half-life is defined as the time required • Tools must be capable of operating in the high-solids-
for 50% of the foam liquid to separate. However, such tests content annular fluid.
have poor reproducibility and the results cannot be extrapo-
lated to conditions other than those under test. • The operation and components of the tool must be
compatible with treatment fluids.
To improve the stability of a foam, it is necessary to
increase the strength of the bubble walls. This is achieved • The OD profile of the tool string should be as slim as
by increasing the viscosity of the base liquid. practical. In addition, the profile must not contain sudden
or large changes in OD which can induce sticking.

Page 18 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

Jetting 2.1.8 Junk Removal

Jetting provides a simple and effective aid in removing Wellbore fill that contains workover debris or large solids
slightly compacted fill. Most applications are treated with (e.g. cement lumps) can require special fishing equipment.
low-pressure jetting through fixed nozzles or jetting subs. A variety of magnetic tools, junk baskets and custom-
Low-pressure jetting can generally be conducted with a designed tools are used in such applications.
minimal effect on annular velocity. High-pressure jetting
can be effective in removing compacted material; however, If a wellbore is known or suspected of containing junk or
the high-pressure drop at the nozzle can effectively reduce particles which cannot be removed by circulation, the BHA
the flow rate below that required for a suitable annular must be carefully chosen to reduce the risk of sticking. In
velocity. addition, an appropriate release tool must be included in the
tool string. The risk of sticking the CT in such applications
The jetting sub should be designed to provide good jetting can be high.
action and sufficient coverage of the tubular wall. Swirl or
rotating nozzles can improve coverage and optimize re- Tubing Movement
moval.
Fluid requirements are dependent on time in the wellbore,
All forms of jetting have two main disadvantages - full bore and time in the wellbore is determined by tubing movement.
cleaning cannot be assured, and large cuttings can be Tubing movement must be closely aligned to the pumping
produced which cannot be transported by the annular fluid. schedule.

Drill Motor Tagging Fill

Motors, bits and underreamers can be effective in the In many cases the top of the fill will be known as a result
complete removal of compacted fill materials. However, of a wireline survey. In this case, the CT can progress to the
the use of motors can be constrained by temperature, fluid fill quickly.
type and cost.
When the top of the fill is not known, an assumed top of fill
Impact Drill point must be identified.

Impact drills are suited to a wide variety of fill removal Penetrating Fill
operations, which include the following advantages:
The rate of fill penetration must never exceed the rate at
• The impact drill does not operate until resistance is met which the maximum fluid loading occurs (Fig. 10).
by the bit, allowing full circulation while running in the hole.

• A wide range of fluids may be used to power impact drills. RECOMMENDED MAXIMUM FLUID LOADING
Fluid Type Maximum weight of
• Impact drill assemblies are relatively short, facilitating rig
fill material per gallon
up and deployment.
of fluid (lbm)
• Impact drills are capable of operation at higher tempera- Water 1
tures than conventional motors.
Gelled Fluid 3
A significant disadvantage of impact drills is their inability
to underream below a restriction. Foam 5

Figure 10.

Page 19 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

During staged treatments (i.e. nitrogen/gelled fluid), pen- With a given set of conditions, the WBS uses the equations
etration should only be attempted when the fluids designed for conservation of mass and momentum to determine the
to carry the fill material are exiting the CT nozzle or tool. distribution of the fluids, continuous and dispersed fluid
velocities, and pressures encountered when those condi-
2.1.9 Computer Modeling tions are met in the field.

Wellbore simulator (WBS) software models the flow of The user inputs information about the well, tubulars, reser-
fluids in a wellbore environment. Although it has been voir and fluids as well as a pump schedule, and allows the
developed to design, execute and evaluate fluid circulation simulator to determine the effectiveness of that schedule.
procedures performed via CT, it may be applicable to a
general set of pumping conditions.

Nitrogen/foam
generation
package

BOP kill port

Pumping tee below

pressure control
equipment

Sample point

Production tubing

Choke
Process and CT nozzle/tools
manifold
recirculate

Disposal

Figure 11. Typical foam equipment configuration for fill removal.

Page 20 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

2.1.10 Fill Removal Operations 2.2.3 Coiled Tubing Equipment

In removing fill from the wellbore, it is necessary to ensure Fill removal operations frequently require the tool string to
that materials are transported to an appropriate point for be repeatedly cycled over a localized area. In this event,
separation/disposal. It is important to ensure that fill consideration must be given to the effects of inducing
materials are not displaced into areas which may interfere fatigue in the corresponding localized area of the work
with the operation of the wellhead, production or pressure string as it passes the reel and gooseneck. In addition, the
control equipment. In addition, it is important to ensure that effect of fatigue while conducting high-pressure jetting
wellbore conditions are maintained in conditions which operations must be accurately predicted.
avoid formation damage by the introduction of the fill
material. 2.2.4 Pressure Control Equipment

2.2 Execution The configuration of CT pressure control equipment allows

fill removal operations to be completed safely and effi-
2.2.1 Execution Precautions ciently under live well conditions. The equipment must be
configured to avoid circulating corrosive or solids-laden
Personnel annular return fluid through the BOP. However, in certain
cases, it may be necessary to return fluids through a shear/
All personnel involved in the design or execution of CT well seal BOP installed above the tree. Returns should then be
kill operations must be familiar with requirements detailed taken through a pump-in tee installed in the riser.
in the relevant Standards of Operation. In addition, the
requirements for the handling and disposal of LSA materi- 2.2.5 Downhole Tools and Equipment
als must be known.
Jetting Assemblies
Well Security
Jetting tools should be configured to maximize the avail-
The control of well pressure and fluids must meet the able fluid rate and pressure. In addition to improving the
requirements of relevant Standards of Operation. In addi- efficiency of consolidated fill removal, this will ensure the
tion the requirements of the operating company and appli- circulation rate is maximized to aid fill dispersion and
cable regulatory authorities must be known. removal of solids from the wellbore.

Equipment Drill Motor Assemblies

All treating and monitoring equipment must be spotted and Drill motor assemblies should be function tested before
operated in accordance with the requirements of the rel- running in the hole. Typically, this is achieved after the
evant Standards of Operation. In addition, equipment assembly has been made up to the work string and is
certified for use in hazardous area must be operated and hanging inside the lubricator/riser. This should be consid-
maintained in accordance with the operating zone require- ered a basic operational check. More comprehensive
ments (e.g. Zone II equipment). checks, including the motor torque, must be completed
prior to rigging up.
2.2.2 Equipment Requirements
Impact Drill Assemblies
Operations that involve the circulation of particulate mate-
rial from the wellbore must be carefully planned and Impact drill assemblies should be function tested before
executed. The consequences of stopping or losing circula- running in the hole. Impact drills do not operate until the tool
tion while the annular fluid is laden with solids can be is pushed into the collapsed position; therefore, the toolstring
severe. A typical equipment schematic for fill removal has to be manipulated during the test procedure.
operations is shown in Figure 11.

Page 21 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

Typically, the function test is performed after the tool string • It may be necessary to kill the well for safety, fluid
has been assembled and attached to the work string, and compatibility or production reasons. It is clearly undesir-
circulation has been established. The tool is collapsed and able to risk damaging the near wellbore area by bullheading
tested by placing the bit on a firm wooden surface by the wellbore fluid.
carefully controlling injector head.
Treatment and Tool Operation
2.2.6 Auxiliary Equipment
• The volume and density of all fluids pumped into the
The fluid mixing, handling and pumping equipment must be wellbore must be monitored and recorded.
of adequate capacity and be configured to minimize cross
contamination of the fluid stages. • Since full bore cleaning cannot be assured, a number of
passes should be made over any consolidated fill area.
Live well operations may require the use of a choke The procedure will be determined by experience in similar
manifold to control annular returns. In this event, a clear line conditions and fill material characteristics.
of communication must exist between the CTU, pump and
choke manifold operators. • Use the largest feasible size of work string to allow higher
circulation rates and higher annular velocity.
2.2.7 Treatment Execution
• The operational efficiency of impact drills is greatly
The steps required to successfully complete a fill removal dependent on applying the appropriate weight at the tool.
operation will depend on the particular conditions encoun- The use of a suitable accelerator can simplify the pro-
tered in each case. cess; however, a high degree of injector-head control is
necessary.
Wellbore fill removal treatments are frequently designed
and conducted on a regular basis within a field or area. 2.3 Fill Removal Evaluation
Consequently, procedures are often tuned to meet local
conditions. Whenever possible, previous case histories for The requirements of the operator will ultimately determine
similar applications should be referenced. the extent to which the fill material must be removed and
what means are to be used to evaluate the success of the
Execution of wellbore fill and scale removal treatments are operation.
accomplished in two basic steps:
Solids removal operations are generally evaluated by
• Wellbore preparation performing a drift run. Typically, a slick-line gauge-cutter
tool will be run, although CT conveyed methods may also
• Treatment and tool operation be used.

Wellbore Preparation

• The recovery of wellbore samples for analysis can be

completed by CT conveyed tools in conjunction with
preparatory work. Typically, slick-line methods are used;
however, in deviated or logistically difficult conditions, CT
may be used.

• If it is desired to remove completion equipment compo-

nents such as gas-lift valves or safety valves, the use of
CT conveyed methods should be considered.

Figure 12. Concentric coiled tubing.

Page 22 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

2.4 Sand Removal Using Concentric Coiled Tubing A number of different liquids are suitable for powering the
jet pump. Formation water is best suited, as it has the
Sand production is often a serious problem. When sus- following properties:
pended in the produced flow, sand can cause destructive
abrasion of pumping equipment. At the surface, the opera- • Low cost
tor must deal with separation, handling and disposal of the
sand. The most serious consequence occurs when sand is • Non-damaging
deposited in the completion. This impedes fluid flow and
therefore production. The problem is exacerbated in hori- • Low viscosity, high turbulence
zontal wells, where settling is more likely to occur.
• Allows rapid sand settling in the surface equipment
A number of techniques exist for the removal of sand from
vertical wells, but difficulties occur when attempting to use The pump is configured to optimize both intake rates and
these in horizontal completions. Bailing techniques are drive pressures, based on the fluid rates available through
hampered by hole orientation and horizontal reach. Cleanout the internal CT string. Front and rear facing jets provide
circulation operations (such as with conventional coiled turbulent energy to fluidize the settled sand before it is
tubing) are limited by low formation pressures and the drawn into the intake ports. In the CCT annulus, liquid
minimum velocities required to prevent particle re-settling. velocities are sufficiently high to ensure that particle re-
settling does not occur. (See Figures 14 and 15).
A technique has been developed using concentric coiled
tubing (CCT) to remove sand from horizontal wells. Con- The entire cleaning operation is performed with a steady,
centric coiled tubing comprises two CT strings, with one balanced pressure. The use of CCT also allows the opera-
permanently installed within the other (Figure 12). tion to be continuous - both running in and pulling out.

The technique involves the use of a jet pump, which is The pump has no internal moving parts, which could be
powered by pumping fluid through the internal CT string. affected by abrasion. The affects of abrasion are therefore
"Spent" power fluid, wellbore fluid and sand are returned to limited to the nozzle and throat assembly.
surface through the CCT annulus (Figure 13).

Fluids Returns

Energy Fluid

Sand

Downhole

Figure 13. Concentric coiled tubing flow.

Page 23 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

Concentric CT Jet Pump Reverse Jetting

Intake Ports Fluidized Sand

Figure 14. Sand cleaning - running in.

Concentric CT Reverse Jetting Jet Pump

Fluidized Sand Intake Ports

Figure 15. Sand cleaning - pulling out.

Page 24 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

3 SCALE AND ASPHALT REMOVAL When the wellbore scale and/or deposits have been removed,
the possibility of conducting an inhibition treatment should
The buildup of solid deposits in wellbore tubulars and be considered. In the right conditions, scale inhibitors may
wellbore production equipment is a significant problem in be placed through the CT workstring and injected into the
many wells fields or areas. Deposition of solid materials in formation. Conducting the injection treatment through the
the tubular results in a reduced flow area and in severe workstring provides the benefits of reduced contamination
cases reduces the production capability of the well. In and the ability to place the treatment fluid over the entire
addition, scale and similar deposits can interfere with the interval.
running and operation of downhole tools and equipment.
Disposal of the returned treatment fluid or scale cuttings
The composition of wellbore deposits may be organic, circulated from the wellbore must be undertaken with due
inorganic or a combination of both. Inorganic deposits in the regard for the safety of personnel and the environment.
form of scale are precipitated mineral solids. They typically
occur due to temperature and pressure reduction. The most 3.1 Design
common scale, CaCO3, is formed at high temperatures.
However, scale can also occur when incompatible waters 3.1.1 Design Data
mix (e.g. formation water and either a fluid filtrate or
injection water). Scales are prevelant in wellbores within The presence of scale or wellbore deposits is generally
reservoirs where water injection is used to maintain the identified by a gauge survey or by the failure of a tool to
reservoir pressure. enter or pass through the tubing or nipple. While this
condition is easily detectable it is often not the primary
Organic deposits such as paraffin and asphalt deposits cause of reduced production. Deposition of similar material
occur with certain types of crude oil, as a result of reduced within the formation matrix can result in severe skin
temperature and pressure in or near the wellbore during damage. In this event, matrix treatments may be required
production. after the wellbore deposits have been removed.

Conventional methods of removing scale and deposits In wells and fields with a known, or potential scale problem,
from wellbores include removal and replacement of the routine monitoring and scale inhibition schedules should be
completion, chemical treatments and wireline conveyed recommended.
tools. Each of these methods suffer some disadvantage in
cost, efficiency or risk of damaging the producing formation. The removal of scale, asphalt and fill materials from the
wellbore is frequently conducted prior to a matrix injection
Several CT conveyed scale removal techniques have been treatment.
developed to take advantage of thru-tubing well service
operations. 3.1.2 Scale/Deposit Characteristics

• Chemical treatment The following types of organic and inorganic deposits are
commonly encountered in oil or gas wellbores.
• Jetting
Organic
• Rotational drilling
• Paraffins (wax) and Asphalt
• Impact drilling
Heavy hydrocarbons in the reservoir fluid tend to crystal-
In determining the most appropriate scale removal method, lize as the temperature and pressure is reduced during
the characteristics of the reservoir, wellbore tubulars and production. Such deposits are generally resolubilized by
the deposit must be studied. organic solvents which can be tailored to suite particular
conditions.

Page 25 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

SCALE AND ASPHALT REMOVAL DESIGN DATA

Completion

- Production casing/liner and tubing details, e.g., size, weight, grade, depths,
deviation, nipples or restrictions, material/alloy etc.
- Perforation details, depth, interval, shot density etc.
- Completion or wellbore fluid details, e.g., type, density, losses etc.

Reservoir

- Reservoir temperature and pressure

- Porosity and permeability
- Formation sensitivity
- Gas-oil contact, water-oil contact
- Compatibility of acid with formation and formation fluids
- Water samples for scaling tendency tests

Production and Surface Equipment

- Production logs/history.
- Configuration of production and surface equipment
- Storage and disposal facilities/limitations

Scale or Fill Characteristics

- Solubility
- Estimated volume of fill material
- Particle size and geometry
- Material density
- Compressive strength or consolidation of material
- Presence of viscous material

Figure 16. Scale and asphalt removal design data.

Inorganic • Sulfate Scales ( CaSO4 , BaSO4 and SrSO4)

• Carbonate Scales (CaCO3 and FeCO3) Sulfate scales occur mainly as gypsum (CaSO4 ,H2O) or
anhydrite (CaSO4 ). The less common barytine or
Carbonate scales are the most common type of scale strontianite are more difficult to remove, but their occur-
which occurs in reservoirs rich in calcium and carbon- rence is more predictable. Calcium sulfate can be easily
ates. Hydrochloric acid will readily dissolve all carbonate dissolved by EDTA. Barium and strontium sulfates can
scales. also be dissolved with EDTA if the temperature is high
enough and the contact time is sufficient. However, due
to slow reaction rates, mechanical removal methods are
more commonly used on barium and strontium scales.

Page 26 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

• Chloride Scales flakes that can be problematic in wellbores having tight

clearance with CT toolstrings.
Chloride scales such as sodium chloride are easily
dissolved in fresh water or very weak acidic solutions. Tubular Size

• Iron Scales (Fe S and Fe2O3) The tubular, or minimum restriction size, will determine the
maximum OD of CT string which can be safely used. Using
Iron sulfide and oxide scales can be dissolved with a CT work string with the largest possible OD, can provide
hydrochloric acid. A sequestrant and iron reducing agent the combined benefits of reducing the annular space,
should be included to prevent the reprecipitation of thereby increasing the annular velocity, and increasing the
damaging byproducts. available fluid flow rate.

• Silica Scales Removal of scale from the inside of larger tubulars is

complicated by two factors; the pumprates required to
These generally occur as very finely crystallized deposits achieve efficient scale removal are increased, and larger
of chalcedony or as amorphous opal. Hydrofluoric acid tubing can potentially contain a higher volume of scale
readily dissolves silica scales. material.

• Hydroxide Scales Restrictions

These are magnesium (Mg(OH)2) or calcium (Ca(OH)2) Scale, or deposits formed in nipples and other internal
hydroxides. Hydrochloric acid is generally used to dis- profiles in the production tubing are often the principal
solve such deposits. reason for the scale removal operation. Even comparatively
small amounts of scale can hamper the operation of
Mixed Deposits downhole flow control devices. Restrictions determine the
maximum OD of the toolstring.
Three damage mechanisms are commonly identified in
mixed wellbore deposits. Scale, waxes or asphaltenes and Deviation
migrating formation fines. If possible a qualitative and
quantitative analyses should be performed to aid the design The ability of fluids to successfully carry and remove fill
of a successful treatment. from the wellbore deceases as the deviation increases.
Highly deviated and horizontal applications require special
Mixed deposits generally require a dual- or multi-solvent design and execution considerations.
system for efficient removal. Typically a dispersion of
aromatic hydrocarbon solvent in acid is used as a base In highly deviated and horizontal wellbores, deviation
fluid, with appropriate additives used to control or treat survey data is required, in addition to completion geometry,
specific conditions. In most cases, it is helpful if an actual as input for the CoilCADE Tubing Forces Model (TFM). The
sample of scale is available for analyses. If a chemical TFM may then be used to determine how far the CT may be
treatment is to be considered, such analyses and compat- pushed into the wellbore. In addition, the anticipated forces
ibility testing is essential. while running and retrieving the CT are calculated.

3.1.3 Wellbore/Completion Geometry 3.1.4 Logistical Constraints

A key factor in determining the suitability of CT in any Logistical constraints effecting the design or execution of
operation is the ability to safely run and retrieve the CT into fill removal operations can be summarized as those applied
and out of the wellbore. The size of completion tubulars and to the use or placement of equipment, and constraints
placement of restrictions, will initially determine what size applied to the disposal of the fill or carrier fluid.
of workstring and toolstring can be used. Jetting and
mechanical removal methods can produce large cuttings or

Page 27 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

Equipment • Composition of the scale or deposit

In general terms, complex job designs require more Material samples must be obtained for analyses and to
equipment. If space and/or crane capacity at the wellsite is allow design of the most appropriate treatment fluid.
a constraint (e.g. offshore) some job design options may be
precluded. An additional space constraint can be included • Wellbore parameters
if the returned scale/fluid is not to be processed by normal
production facilities, and additional surface equipment is The wellbore temperature and pressure effects the reac-
required. tion rate of most treatments to some extent. Generally,
reactions rates and dissolution capacities increase as the
Disposal temperature increases, thereby aiding removal. How-
ever, consideration must be given to the protection of
Disposal of the resulting scale material/carrier fluid must be wellbore tubulars and equipment from corrosive fluids. A
considered. Circulation treatments using motors or impact knowledge of the tubular metallurgy is important since
hammers and inert fluids can be designed to separate and different inhibitors must be used with different steel
recirculated the carrier fluid to reduce the volumes required chemistry.
and minimize subsequent disposal. However, more complex
job designs including gelled fluids, foams and nitrogen/gel • Volume of material to be removed
slugs can result in large volumes of fluid for disposal.
The volume of treatment fluid is influenced directly by the
Certain types of scale are classed as a low specific activity volume of scale or deposit to be removed (i.e., thicker
(LSA) radiation sources (e.g. strontium and barium sulfates). scale deposits will require more treatment fluid to ensure
Appropriate monitoring and protection measures must be efficient removal.
taken to ensure safe operations. The local or national
requirements or regulations associated with the processing To ensure adequate contact with an uncontaminated
and disposal of LSA solids must be known to personnel treatment fluid, some agitation may be required. Treat-
designing and executing the operation. ments conveyed through CT can be precisely spotted, or
jetted into place.
3.1.5 Chemical treatments
• Treatment fluid compatibility
Chemical treatments of scale and wellbore deposits are
only effective when the material is readily soluble in The treatment fluid must be compatible with any fluids,
treatment fluids such as acid or solvent formulations. The materials or equipment which is likely to contact during
uncontaminated treatment fluid must be allowed to contact the operation. If there is potential contact with the reser-
the scale for sufficient time to dissolve the bulk of the voir, compatibility with reservoir mineralogy should be
scale. In applications where a rapid reaction occurs (e.g. verified. The fluid density and volume must be carefully
the dissolution of carbonate scale with hydrochloric acid) a noted.
properly applied chemical treatment is often most
appropriate. However, some types of scale require contact 3.1.6 Jetting
times which are impractical under normal circumstances,
and are often of questionable efficiency (e.g. the dissolution Jetting is one of the most straightforward methods of
rate for barium sulfate in EDTA may require a contact time removing scale or fill from wellbore tubulars. For basic
of approximately 24 hours). Even then the dissolution rates operations, no special tools or treatment fluids are required.
may be very poor due to the surface area to bulk ratios However, the efficiency of jetting operations is often
encountered in tubular environments. questionable, and it is generally difficult to verify.

Selection of a suitable chemical treatment should be made Jetting may be categorized as a low- or high-pressure
after considering several factors: treatment. Low-pressure jetting operations generally require
less complex tools and equipment. In many cases the

Page 28 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

downhole jetting nozzles will be designed and manufactured Nozzle Design

locally. High-pressure jetting tools and equipment are more
specialized and require more detailed job design and The design and configuration of an appropriate jetting
execution procedures. High-pressure jetting may be defined nozzle is dependent on the following factors:
as requiring surface pressures greater than 5,000 psi.
• The size and number of ports must be compatible with the
In applications such as jetting scale from localized areas available flow rate and pressure at the downhole end of
of the completion tubulars, a high degree of fatigue may be the workstring.
induced in a relatively short interval of the workstring.
Personnel involved in the design and execution of the • The position and direction of the jets should suit the
service should be aware of this potential, and the limitations intended application. For example, side facing jets for
it may impose. Accurate tracking of workstring pressure perforation washing or combination down and side facing
and cycles is obviously vital. jets for severe scale removal.

3.1.7 Low Pressure Jetting 3.1.8 High Pressure Jetting

Low-pressure jetting can be an effective method of removing High-pressure jetting can provide the cutting action to
soft scales and paraffins. Relatively large jet nozzles remove even the hardest scales. However, it has several
provide good coverage of the wellbore target area, allowing operational disadvantages:
relatively high circulation rates which help ensure removal
of cuttings and dislodged material. • The high circulating pressure and cycling associated with
the service is severely detrimental to the useful life of the
Selection of a suitable jetting nozzle and fluid combination workstring.
should be made after considering several factors.
• The relatively uncontrolled cutting action of a high
Jetting fluid pressure jet can produce large cuttings which may inter-
fere with circulation or downstream facilities.
A variety of low-pressure jetting fluids are commonly used,
from simple, readily available fluids such as water or brine, • Removal of cuttings from the wellbore can be difficult
to complex chemical treatment fluids. Relatively inert since relatively low circulation rates result from this
fluids such as water or light brines remove the wellbore treatment.
scale or deposit by mechanical action only. In addition, the
fluid must be capable of carrying or circulating the deposits • Fullbore cleaning cannot be assured.
from the wellbore.
• Since the jetting nozzles are small-diameter, the jetting
Chemical treatment fluids are jetted to improve the process fluid must be carefully filtered to avoid plugging the tool.
in a number of ways:
3.1.9 Rotational Drilling/Underreaming
• Jetting increases turbulence which generally aids the rate
of dissolution. Rotational drilling has been a common method of removing
hard wellbore deposits. A downhole motor fitted with the
• The induced turbulence reduces the treatment fluid/ appropriate bit can ensure near fullbore cleaning down to
wellbore fluid interface and reduces the likelihood of the first restriction. However, below the restriction, an
contamination. underreamer is required to ensure efficient cleaning. Bottom
hole assemblies fitted with underreamers are also commonly
• The penetration and treatment of internal profiles in the used to remove hard scale from production tubing and the
completion equipment is improved by jetting. casing/liner below the tailpipe.

• Perforation washing action is improved by jetting.

Page 29 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

The configuration and use of a drilling/underreaming BHA useful when selecting equipment.
is dependent on the following factors.
3.1.10 Impact Drilling
Power/Circulating Fluid(s)
Impact drills provide an efficient means of removing hard
A prerequisite for motor/underreamer power fluids is that deposits. They are typically less costly than drilling motors
they must be clean, preferably filtered to prevent motor and are suitable for use in higher temperatures. However,
component wear or plugging of the small diameter ports in a significant disadvantage exists in that they cannot be
the underreamer. used with underreamers.

Typically, a friction reducer is used to allow higher circulation Impact drills provide rotation, impact and a pressure pulse
rates. In addition, friction reducers generally improve the at the bit with each blow. The impact drill can be operated
motor efficiency and the solids carrying capability of the with a variety of fluids including nitrogen, foam, water- or oil-
returned annular fluid. If well production is to be used to based fluids and solvents such as xylene or diesel. By
assist the annular flow, circulated fluids should be checked powering the impact drill with an appropriate fluid, chemical
for compatibility with the reservoir fluid. and mechanical treatments can be combined to remove
wellbore deposits.
Hole Cleaning
The impact drill does not operate unless sufficient resistance
To ensure a successful operation, all cuttings must be is met to collapse the tool. This allows circulation to
removed from the wellbore. This requires that the solids are continue as the tool is run and retrieved without damaging
suspended in a fluid which has a higher annular velocity completion tubulars or equipment.
than the settling rate of the solid particles.
The tool stroke frequency is dependent on the weight set
In some circumstances, production from the well can be on the tool and the fluid rate. The tool components are self
used to help achieve a high enough annular velocity. This tightening and will not store reverse torque in the event of
also prevents potential damage through plugging of the a stall. This feature eliminates pump shutdowns and similar
perforations by wellbore debris. interruptions associated with conventional motors.

It is generally recommended that a ball operated circulating An impact drill toolstring is generally significantly shorter
sub be included in the tool assembly. This allows a high than a comparable drill motor string.
viscosity pill to be circulated at increased rate prior to
retrieving the toolstring. The following points should be considered when impact
drilling operations are designed or performed:
In highly deviated wellbores, a high viscosity pill should be
pumped through the underreamer as it is run in through the Power/Circulating Fluid(s)
completed interval.
Impact drill power fluids must be clean, preferably filtered
Toolstring Length to prevent component wear or plugging of the small diameter
ports in the tool.
Consideration must be given to the toolstring length and the
corresponding requirement for surface pressure control Typically, a friction reducer is used to allow higher circulation
equipment. rates. In addition, friction reducers generally improve the
impact drill efficiency and the solids carrying capability of
Bit Selection the returned annular fluid.

The selection of an appropriate bit, mill and/or underreamer If well production is to be used to assist the annular flow,
blade is vital to the timely completion of a successful circulated fluids should be checked for compatibility with
operation. Previous experience and trial/test results are the reservoir fluid.

Page 30 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

Hole Cleaning 3.2 Execution

To ensure a successful operation, all cuttings must be 3.2.1 Execution Precautions

removed from the wellbore. This requires that the solids are
suspended in a fluid which has a higher annular velocity Execution precautions to be observed during scale removal
than the settling rate of the solid particles. operations principally relate to the handling of treatment
fluids and the returned scale or wellbore deposit. The
In some circumstances, production from the well can be potentially toxic, corrosive and LSA nature of the fluid or
used to help achieve a high enough annular velocity. This scale requires that special monitoring and protection
also prevents potential damage through plugging of the methods are used to ensure the safety of personnel,
perforations by wellbore debris. equipment and the environment.

The ability to operate with nitrogen or foamed fluids Personnel

significantly improves, and allows flexibility in, the removal
of debris from the wellbore. All personnel involved in the design or execution of CT
scale removal operations must be familiar with requirements
Bit Selection detailed in the relevant operational standards. In addition,
the requirements for the handling and disposal of LSA
The selection of an appropriate bit or mill is vital to the materials must be known. Monitoring and protection criteria
timely completion of a successful operation. Previous should be defined in association with the operating company
experience and trial/test results are useful when selecting or designated third party.
equipment.
Equipment
3.1.11 Scale Inhibition
All treating and monitoring equipment must be spotted and
The squeeze technique of applying scale inhibition is a operated in accordance with the requirements of the relevant
widely used technique for the prevention of scale deposits. standards. In addition, equipment certified for use in
The technique is also suitable for corrosion and microbial hazardous areas, must be operated and maintained in
protection of downhole tubulars and equipment. accordance with the operating zone requirements (e.g.
Zone II equipment).
A concentrated solution of the scale inhibitor is injected into
the producing formation. The well is then shut in for a 3.2.2 Equipment Requirements
predetermined period, generally 12 to 24 hours, during
which time the inhibitor absorbs onto the reservoir rock. Operations that involve the circulation of particulate material
When production is resumed, the inhibitor is slowly absorbed from the wellbore must be carefully planned and executed.
by the the produced fluid in a concentration sufficient to The consequences of stopping or losing circulation while
prevent the deposition of scale. the annular fluid is laden with solids can be severe.
Therefore, adequate precautions must be taken to ensure
Generally, wells which have had scale removed and wells that the operation proceeds as planned.
which are at risk of forming scale are treated in this manner
(e.g. wells suffering injection water breakthrough). The 3.2.3 Coiled Tubing Equipment
scale inhibitor treatment design is well specific and is
dependent on the porosity, perforated interval, net/gross Scale removal operations frequently require the toolstring
permeability and the treatment depth. to be repeatedly cycled over a localized area. In this event,
consideration must be given to the effects of inducing
Although basically inefficient in terms of chemical use, the fatigue in the corresponding localized area of the workstring
technique is cost effective and generally accepted as as it passes the reel and gooseneck. In addition, the effect
preferable to downhole injection of inhibitor through an of fatigue while conducting high pressure jetting operations
injection capillary or line. must be accurately predicted. Cycling the workstring under

Page 31 of 33
 Section 320
COILED TUBING SERVICES MANUAL
Rev A - 98 WELLBORE MAINTENANCE

high internal pressures drastically reduces the useful life of Live well operations may require the use of a choke
the workstring. manifold to control annular returns. In this event, a clear line
of communication must exist between the CTU, pump and
3.2.4 Pressure Control Equipment choke manifold operators.

The configuration of CT pressure control equipment allows 3.2.7 Treatment Execution

scale removal operations to be completed safely and
efficiently under live well conditions. The equipment must The steps required to complete a scale or wellbore deposit
be configured to avoid circulating corrosive or solids-laden operation depend on the conditions encountered. Whenever
annular return fluid through the BOP. However, in certain possible, previous case histories for similar applications
cases it may be necessary to return fluids through a shear/ should be referenced.
seal BOP installed above the tree. Returns should then be
taken through a riser flow /pump-in Tee. Execution of scale or deposit treatments are accomplished
in two basic steps:
3.2.5 Downhole Tools and Equipment
• Wellbore preparation
Jetting Assemblies
• Treatment and tool operation
Jetting tools should be configured to maximize the available
fluid rate and pressure. In addition to improving the efficiency Wellbore Preparation
of scale removal, this will ensure the circulation rate is
maximized to aid removal of solids from the wellbore. • The recovery of wellbore samples for analysis can be
completed by CT conveyed tools in conjunction with
Drill Motor Assemblies preparatory work. Water sample analysis may also prove
useful in determining the nature of the scale. Typically
Drill motor assemblies should be function tested before slickline methods are used. However, in deviated or
running in hole. Typically, this is achieved after the assembly logistically difficult conditions CT may be used.
has been made up to the workstring and is hanging inside
the lubricator/riser. • If it is desired to remove completion equipment compo-
nents such as gas lift valves or safety valves, consider
Impact Drill Assemblies the use of CT conveyed methods. In many cases, the
scale or condition to be treated will hamper retrieval.
Impact drill assemblies should be function tested before Tools and techniques used in CT conveyed methods will
running in hole. Impact drills do not operate until the tool is allow the circulation of treatment fluids to facilitate re-
pushed into the collapsed position. Therefore, the toolstring moval. In addition, the forces which may be exerted by CT
has to be manipulated during the test procedure. are greater than commonly used wireline equipment.

Typically the function test is performed after the toolstring • It may be necessary to kill the well for safety, fluid
is assembled, attached to the workstring and circulation compatibility or production reasons. In wellbores with
has been established. The tool is collapsed and tested by known deposits and damage, it is clearly undesirable to
placing the bit on a firm wooden surface by carefully control risk damaging the near wellbore area by bullheading the
of the injector head. wellbore fluid. Coiled tubing well kill techniques can be
used to minimize the potential of damage during the well
3.2.6 Auxiliary Equipment kill process.

The fluid mixing, handling and pumping equipment must be

of adequate capacity and be configured to minimize cross
contamination of fluid stages.

Page 32 of 33
 COILED TUBING SERVICES MANUAL Section 320
WELLBORE MAINTENANCE Rev A - 98

Treatment and Tool Operation

Chemical Treatment

• The volume and density of all fluids pumped into the

wellbore must be monitored and recorded.

Jetting Treatment

• Since full bore cleaning cannot be assured a number of

passes should be made over the scale area. The proce-
dure will be determined by experience in similar condi-
tions and scale characteristics.

Drill Motor Underreamer

• Use the largest feasible size of workstring to allow higher

circulation rates and higher annular velocity.

• A fullbore underreamer is preferred for liner cleanouts. On

deviated wells a pilot bit will tend to walk to the low side
of the wellbore.

Impact Drill

• The efficiency of impact drills depends greatly on applying

the appropriate weight at the tool. The use of a suitable
accelerator can simplify the process. However, a high
degree of injector-head control is necessary.

3.3 Evaluation

The requirements of the operator will ultimately determine

the extent to which scale must be removed and what means
are to be used to evaluate the success of the operation.

Fullbore removal techniques, such as drill motor or impact

drills, ensure complete removal of scale which is effec-
tively evaluated by the free passage of the tool.

Evaluation of scale or tubing solids removal operations

performed above restrictions or the tubing end can gener-
ally be achieved by a drift run. Typically, a slickline gauge-
cutter tool will be run, although CT conveyed methods may
also be used.

In operations performed below restrictions, or in the casing/

liner, confirmation of complete scale removal can be more
difficult.

Page 33 of 33
This page left blank
 Section 330
COILED TUBING SERVICES MANUAL
Rev A - 98

MATRIX TREATMENT

Contents Page

Introduction .................................................................................................... 2
1 MATRIX STIMULATION ................................................................................. 2
1.1 Design ................................................................................................. 2
1.1.1 Candidate Selection ............................................................................ 4
1.1.2 Treatment Fluid .................................................................................... 5
1.1.3 Fluid Additives .................................................................................... 6
1.1.4 Injection Pressure and Rate ................................................................ 7
1.1.5 Treatment Volume ................................................................................ 7
1.1.6 Diversion ............................................................................................. 7
1.1.7 Downhole Tools .................................................................................... 8
1.1.8 Pumping Schedule .............................................................................. 9
1.1.9 Horizontal Wellbores .......................................................................... 10
1.2 Matrix Stimulation Operations ........................................................... 10
1.2.1 Execution Precautions ...................................................................... 10
1.2.2 Equipment Requirements .................................................................. 10
1.2.3 Coiled Tubing Equipment ................................................................... 10
1.2.4 Pressure Control Equipment .............................................................. 11
1.2.5 Pumping Equipment .......................................................................... 11
1.2.6 Monitoring and Recording Equipment ................................................ 12
1.2.7 Downhole Equipment ......................................................................... 12
1.2.8 Fluid Preparation ............................................................................... 12
1.3 Evaluation of Matrix Stimulation ........................................................ 12

Page 1 of 12
 Section 330
COILED TUBING SERVICES MANUAL
Rev A - 98 MATRIX TREATMENT

Introduction • Spotting the treatment fluid with CT will help ensure

complete coverage of the interval. This in conjunction
When a well does not, or can no longer, produce at the rates with an appropriate diversion technique will help ensure
expected, it is possible that the formation is “damaged.” By uniform injection of fluid into the target zone. Spotting the
carefully evaluating the wellbore and reservoir parameters, treatment fluid also avoids the need to bullhead wellbore
the type and degree of damage can be identified. If the fluids into the formation ahead of the treatment.
reservoir permeability is low, the well may be a candidate
for hydraulic fracturing. However, if near-wellbore damage • Long intervals can be more effectively treated using
is found to be reducing well productivity, matrix stimulation techniques and tools that have been developed for use
may be appropriate. In addition to offering economic with CT, e.g. a selective treatment system using straddle-
advantages over hydraulic fracturing, matrix treatments pack isolation tools. This is particularly important in
are preferred when fracturing may result in the undesirable horizontal wellbores.
production of gas or water.
By recognizing the limitations of the CT and associated
1 MATRIX STIMULATION equipment, treatments can be designed to achieve the
maximum benefit to the zone while operating within safe
Various types of damage exist, several of which may limits and approved techniques. For example, the relatively
coexist, because almost every operation performed on a high friction pressures and low pump rates associated with
well (drilling, completion, production, workover and stimu- CT can extend the duration of large volume treatments
lation) is a potential source of damage. The most common beyond viable limits. In many cases, a lower volume
form of damage is plugging of the formation around the treatment selectively applied will achieve similar, or better,
wellbore. results.

Stimulation treatments must either remove the damage (in 1.1 Design
sandstones) or create channels to bypass the damaged
zone (in carbonates). Such matrix stimulation treatments The following general guidelines outline the principal con-
are designed to restore the natural permeability of the siderations when designing and executing matrix treat-
formation by injecting treatment fluids at a pressure less ments. While most of the points listed will apply to any
than the formation fracture pressure. matrix treatment, some emphasis is made on consider-
ations which apply to operations performed through CT:
Coiled tubing is commonly used to perform matrix treat-
ments, and in many cases will offer several advantages • Ensure that the well is a candidate for matrix stimulation
over conventional treatment techniques: by confirming the presence of damage.

• The CT pressure control equipment configuration allows • Identify the location, composition and origin of the
the treatment to be performed on a live well. This avoids damage.
potential formation damage associated with well killing
operations. • Gather and compile the wellbore and completion informa-
tion required for job design and evaluation of treatment
• Associated operations can be performed as part of an options.
integrated service, e.g. wellbore fill can be removed prior
to the matrix treatment and nitrogen or artificial lift • Select an appropriate treatment fluid, including additives
services may be applied to restore production following and associated treatments. Conduct compatibility tests
the treatment if required. to ensure there are no adverse reactions between fluids.

• Performing the treatment through CT avoids exposing the • Determine the maximum injection rate and pressure.
wellhead or completion tubulars to direct contact with
corrosive treatment fluids. • Determine the treatment volume.

Page 2 of 12
 COILED TUBING SERVICES MANUAL Section 330
MATRIX TREATMENT Rev A - 98

• Consider the use of diverting agents to help ensure treatments cannot be understated. This is necessary for
complete coverage. several reasons:

• Consider the use of selective treatment tools. • By confirming the composition, location and degree of
damage, the selection of an appropriate treatment fluid is
• Prepare a complete pumping schedule, including shut-in possible.
and flowback requirements.
• The maximum cost effectiveness of the treatment can
• Forecast the economic viability of the treatment. only be ensured if all aspects of the treatment are
optimized.
The importance of obtaining adequate, and accurate,
wellbore and reservoir data prior to designing stimulation

MATRIX TREATMENT DESIGN DATA

Drilling - Drilling mud details over zone of interest, e.g. type, density, losses, unuaual conditions,
etc.
- Casing/liner cementing deatils for zone of interest, e.g. type, density, losses, evaluation,
unusual conditions, etc.

Completion - Production casing/liner and tubing details, e.g. size, weight, grade, depths, deviation,
nipples or restrictions, material/alloy, etc.
- Perforation details, depth, interval, shot density, etc.
- Completion fluid details, e.g. type, density, losses, etc.

Reservoir - Formation analyses

- Reservoir temperature and pressure
- Porosity and permeability
- Gas/oil contact, water/oil contact

Production - Production test results, e.g. skin, effective permeability, production rates, etc.
- Production logs/history
- Results of NODAL analyses

Workover - Details of previous stimulation or remedial treatments

Laboratory Analyses - Acid solubility

- Formation water analyses
- Emulsion and sludge testing
- Iron content testing
- Permeability and porosity
- Flow test (ARC)
- SEM/Edax studies
- Petrographic studies
- Determine paraffin/asphaltine content

Figure 1.

Page 3 of 12
 Section 330
COILED TUBING SERVICES MANUAL
Rev A - 98 MATRIX TREATMENT

• By conducting pre- and posttreatment tests and compari- The presence and amount of damage are calculated from
sons, the efficiency of the treatment may be quantified. data obtained by conducting a pressure transient analysis,
i.e. by pressure buildup or drawdown tests. Such tests
In addition to reservoir and wellbore parameters, the selec- provide invaluable information to optimize the treatment
tion of an appropriate treatment may be dependent on the and evaluate the results.
well or field production objectives and economics.
The type, location and origin of the damage are determined
1.1.1 Candidate Selection by reviewing the results of the pressure transient analyses
in conjunction with the information outlined in Figure 1.
When a well has been identified as a possible candidate for
matrix treatment, it is necessary to gather and compile data Damage can be characterized by two important parameters
for analyses and design purposes. Figure 1 summarizes - its composition and location. The locations of various
the typical fields of data required for matrix treatment damage types are summarized in Figure 2.
design. This should be regarded as a basic guide list which
may require additional input for complex job designs or Wellbore and Completion Characteristics
procedures.
A key factor in determining the suitability of CT in any
Formation Damage operation is the ability to safely run and retrieve the CT into
and out of the wellbore. The size of completion tubulars and
The objective of a matrix treatment is to remove the placement of restrictions will initially determine if CT can be
damage which impairs the productivity of the well, i.e. used to convey the treatment fluid or tools.
decrease skin. Therefore, it is essential to know the type,
amount, location and origin of the damage.

TYPE AND LOCATION OF COMMON FORMATION DAMAGE

Damage Location

Tubing Gravel Pack Perforations Formation

Type of Damage

Scales x x x x

Organic Deposits x x x x

Silicates, Aluminosilicates x x x

Emulsion x x x

Water Block x

Wettability Change x

Bacteria x x x x

Figure 2.

Page 4 of 12
 COILED TUBING SERVICES MANUAL Section 330
MATRIX TREATMENT Rev A - 98

In highly deviated and horizontal wellbores, deviation The following list summarizes the criteria considered when
survey data are required, in addition to completion geom- selecting treatment fluids for use with CT:
etry, as input for tubing forces model software. The soft-
ware may then be used to determine how far the CT may be • Physical characteristics of the damage. These will often
pushed into the wellbore. In addition, the anticipated forces determine the nature of the base treatment fluid (e.g. acid-
are calculated for running and retrieving the CT. or solvent-base treatment).

Well Preparation • Reaction of the treatment fluid with the formation. Adverse
reactions between the formation and treating fluid can
There are several options available when selecting a create new damage and compound existing productivity
treatment technique. The entire treatment, or only part of problems. Such potential reactions are controlled by
the treatment, may be performed through CT. Regardless additives in the treatment fluid and by preflush and
of the technique employed, it is undesirable to inject overflush treatments.
damaging fluids, scales or other wellbore solids into the
formation. Design consideration must be given to the • Prevention of excessive corrosion, both to CT and
removal of the following potential damage sources before completion equipment (see subsection Corrosion Inhibi-
conducting the main treatment: tor).

• Wellbore fill material near the treatment zone • Use of friction reducers to optimize the treatment rate (see
subsection Friction Reducer).
• Scale, asphalt or solids in the production tubing/liner
• Compatibility of treatment fluid with wellbore and reservoir
• Rust and scale deposits inside the CT work string fluids. Fluid additives are used to prevent sludge or
emulsions, disperse paraffins and prevent precipitation of
A typical treatment uses a fluid containing inhibited acid, reaction products.
solvents, iron reducing agents and solids suspending
agents to clean tubulars before stimulation and sand • Compatibility of treatment fluid with diverting agent (see
control treatments. In addition to removing damaging subsection Diversion).
solids, the treatment prevents the main treating fluid from
carrying high concentrations of dissolved iron into the • Cleanup and flowback. Using CT to perform a matrix
formation. treatment provides the means to quickly initiate produc-
tion following treatment. If the reservoir pressure cannot
1.1.2 Treatment Fluid overcome the hydrostatic pressure exerted by the spent
treatment fluid, nitrogen kickoff techniques may be per-
Selection of an appropriate treatment fluid is determined by formed. As an alternative, energizing the treatment fluid
the type of damage and its location. The location of the may be appropriate.
damage is a significant consideration because the treat-
ment fluid may contact several other substrates before Preflush/Overflush
contacting the damaged zone, e.g. rust or scale on well
tubulars or carbonate cementing materials. The fluid must Some treatments, especially in sandstone reservoirs,
then provide an effective treatment on contact with the require preflush and overflush fluids to prevent adverse
damaged zone. secondary reactions and the creation of precipitates from
the treatment fluid.
In most cases, the exact type of damage cannot be
identified with absolute certainty. In addition, there is often The preflush provides separation between the connate
more than one type of damage present. Therefore, many water and treatment fluid and, in sandstone treatments,
stimulation treatments incorporate fluids to remove more reacts with carbonate minerals in the formation to prevent
than one type of damage. their reaction with the hydrofluoric acid (HF). Brine, solvent
or hydrochloric acid (HCl) can be use as preflush fluids.

Page 5 of 12
 Section 330
COILED TUBING SERVICES MANUAL
Rev A - 98 MATRIX TREATMENT

The primary purpose of an overflush is to displace poten- • Surfactants have several functions and uses which may
tially damaging precipitates deep into the reservoir, away be summarized as aiding the penetration of fluids through
from the wellbore. Special overflushes can be formulated to the formation during treatment and flowback.
facilitate diverter cleanup. Ammonium chloride brine, HCl
(3 to 10%) and light hydrocarbons (e.g., diesel) are com- Many of the additives commonly used in stimulation
monly used as overflush fluids. treatments will present a hazard to personnel and the
environment if handled incorrectly. Consideration must be
The volume of preflush or overflush required is calculated given to the safe handling, mixing, cleanup and disposal of
on the basis of the radial displacement required. treatment fluids and additives.

1.1.3 Fluid Additives Corrosion Inhibitors

While the base treatment fluid is designed to remove the When selecting a corrosion inhibitor, the following condi-
damage, most treatments require the use of additives to tions must be considered:
improve reactions and control potential damage to the
formation, completion tubulars or CT work string. The • Type and concentration of acid
following types of additive are commonly used on matrix
stimulation treatments: • Maximum temperature

• Acid corrosion inhibitors are required on all jobs to reduce • Duration of acid contact
the rate of corrosion on treating and completion equip-
ment to an acceptable level. • Type of tubular/completion goods which will be exposed

• Alcohol is often used in gas wells to lower surface/ • Presence of H2S

interfacial tension, increase vapor pressure and improve
cleanup. The effective range of corrosion inhibitors can be extended
and improved by using inhibitor aids.
• Antifoam agents prevent excess foam from being formed
when mixing fluids on the surface. H2S Protection

• Clay stabilizers are used to prevent damage from the The presence of H2S affects the design and execution of
dispersion, migration or swelling of clay particles. matrix stimulation jobs in several ways:

• Diverting agents help ensure complete coverage of the • Because H2S is frequently liberated as an acid reaction
zone to be treated. product, the well condition must be considered sour
following treatment and during cleanup. Personnel and
• Formation cleaner will kill and remove bacteria and equipment safety requirements must be observed during
polymer residues. these periods.

• Iron stabilizers are used to prevent the precipitation of • Wells with a sour status must be treated using CT
gelatinous ferric iron in the formation. downhole tools and equipment that can be positively
identified as suitable for H2S service.
• Mutual solvents serve as a wetting agent, demulsifiers
and surface/interfacial tension reducer. • The efficiency of some additives, especially corrosion
inhibitors, can be significantly reduced in the presence of
• Organic dispersants and inhibitors are used to remove and H2S.
inhibit the deposition of organic materials.

Page 6 of 12
 COILED TUBING SERVICES MANUAL Section 330
MATRIX TREATMENT Rev A - 98

Protection against the effects of H2S can be achieved by 1.1.5 Treatment Volume
using a scavenger. In most cases, H2S protection should be
applied to the exterior surface of the CT as well as included The treatment volume (gal/ft of perforated interval) is most
in the treatment fluid. commonly determined by field experience, although labo-
ratory tests can be conducted if no history exists. The
Friction Reducers amount of acid required to remove formation damage is
dependent on many factors relating to the characteristics
A friction reducing agent can significantly increase the rate of the damage, formation and treatment fluid.
at which fluids may be pumped. In addition to improving
treatment efficiency, this reduces job time, which may be 1.1.6 Diversion
an important consideration in large volume treatments.
Successful matrix treatments depend on the uniform distri-
1.1.4 Injection Pressure and Rate bution of the treating fluid over the entire production (or
injection) interval. When fluids are pumped into a well, they
The design of matrix acid treatments should not only naturally tend to flow into the zones with the highest
specify the volumes and types of fluid to be injected, but permeability and least damage. By diverting the flow of
also the maximum permissible injection rate and treating treatment fluid to the areas of lesser permeability, a more
pressure, to avoid fracturing the formation. effective treatment will be achieved. Production log data
can be used to identify high-permeability zones or thief
Downhole Sensors zones, enabling the design of an efficient placement/
diversion technique.
Downhole sensors provide a real-time downhole data acqui-
sition system which can be used to monitor temperature, The criteria for selection of a diversion technique or agent
pressure and casing collar data. Real-time bottomhole include the following:
pressure (BHP) and temperature (BHT) data acquired
during a matrix treatment can be used to determine the • The diverting agent must provide uniform distribution of
efficiency of the stimulation as it progresses. This capabil- treating fluid into zones of widely different permeability.
ity provides several benefits contributing to the optimiza-
tion of the treatment: • The diverter must not cause permanent damage to the
formation.
• Provides accurate BHP and BHT data for any well profile.
This includes vertical, inclined and horizontal wellbores, • A rapid and complete cleanup must be possible to avoid
cased and open hole. secondary damage from precipitates.

• Evaluate-Treat-Evaluate – Well test data collected by the • The diversion agent must be compatible with the treating
sensors can be processed on location to allow for last fluid, additives and overflush or displacement fluids.
minute changes in a treatment design.
• The diverter must be effective at the applicable treatment
• Optimized diversion – Data from the sensors allows for temperature.
changes to be made to the treatment schedule as the job
is being pumped. For example, while a foam diversion Diverting techniques can be classified as mechanical,
stage is being pumped, the BHP continues to decrease chemical or foam. In addition, although not a true diversion
instead of increase; the foam stage can be continued until technique, reciprocating the CT nozzle over the treatment
the BHP sufficiently increases to indicate that diversion zone during the treatment can be beneficial in some
is taking place. operations.

Page 7 of 12
 Section 330
COILED TUBING SERVICES MANUAL
Rev A - 98 MATRIX TREATMENT

Mechanical Diversion greater than that of the tightest zone, little or no diversion
will occur.
Mechanical diversion methods applicable to CT matrix
treatments are limited to techniques incorporating bridge • Invasion – Deep invasion of diverter into a producing
plugs, packers and straddle packers. Conventional meth- formation is undesirable. The efficiency of diversion and
ods of diversion using ball sealers are not compatible with subsequent cleanup is increased by reducing invasion.
CT conveyed treatments because of the restricted internal
diameter and low pump rates associated with CT. • Dispersion – To ensure a satisfactory buildup of diverter,
the particles of diverting agent must be properly dis-
The use of packers and plugs to isolate and selectively persed in the carrier fluid.
treat zones can be desirable because the treatment is
effectively conducted on a shorter zone. The distance • Compatibility – Diverting agents must be compatible with
between the two packers is adjustable, using a range of the base treating fluid, additives and overflush/displace-
spacers, when the tool is assembled. ment fluids. They must be inert toward the carrier fluid at
the well treating temperature.
The following points must be considered when designing a
matrix treatment in conjunction with a packer tool string: • Cleanup – The diverting agent must be soluble in the
production (or injection) fluid to enable a rapid and
• The maximum spacer length (i.e. treatment interval) is complete cleanup.
limited by the maximum tool length that can be safely
deployed into and out of the well. Foam Diversion

• The maximum injection pressure is determined by the Foam can be an effective diverter in many matrix stimula-
specifications and expansion of the packers. tion treatments, particularly those performed in horizontal
wellbores. Unlike a particulate diverter that requires fluid
• All fluids must be free of particulate solid which could contact to assist cleanup, foam will break or be produced
block restricted passages within the tool string. to allow a rapid and efficient cleanup.

• Circulation through the work string while the toolstring is A typical foam diversion treatment generates and main-
being run and retrieved is not possible. Pumped fluids will tains a stable foam in the formation (thief zone) during the
cause the packer elements to inflate, thereby increasing treatment. By diverting the treatment fluid from the thief
the risk of damaging the packer or surging or swabbing the zone to the damaged zone, a complete and effective
wellbore. treatment is achieved.

Chemical Diversion The foam diversion treatment would typically follow a

pumping schedule such as outlined in Figure 3.
Most chemical diverters function by forming a bridge or
cake of lower permeability on the formation face to create 1.1.7 Downhole Tools
an artificial skin. This soluble cake is dissolved and
removed during cleanup and subsequent production (or A number of tool strings and bottomhole assemblies
injection). The efficiency of chemical diversion techniques (BHAs) are used in conjunction with matrix stimulation
is improved with higher injection or treating rates. treatments. The string composition and configuration will
depend on the tool-string function; however, the following
An appropriate chemical diverting agent must meet several criteria will apply to all tool strings used on matrix treat-
physical and chemical requirements: ments:

• Permeability – The bridge or cake formed on the formation • The material from which the tool is manufactured must be
face should be as impermeable as possible to achieve resistant to inhibited treatment fluid.
maximum diversion. If the permeability of the cake is

Page 8 of 12
 COILED TUBING SERVICES MANUAL Section 330
MATRIX TREATMENT Rev A - 98

• The tool seals and components must be compatible with • Fluids used to clean the completion tubulars
the treatment fluid and additives.
• Preflush and injectivity test fluids
• The tool seals or O-rings should be located to protect
threaded connections or components from corrosive • Main treatment fluid (including diverter stages)
treatment fluids.
• Overflush fluids
1.1.8 Pumping Schedule
Cleanup and Flowback
A pumping schedule detailing each fluid stage of the
treatment should be prepared. The schedule should include In most cases, flowback of spent fluids should be accom-
anticipated pump rates and times, and can be regarded as plished as soon as possible. Detrimental reaction products
a summary of the total operation. The volume and density and precipitates can be formed within the formation if some
of each fluid stage should be noted. Each fluid should be spent-acid products remain for an extended time. There-
listed, including: fore, a rapid flowback is generally desirable. However, in
some cases (notably following clay damage treatments),
• Fluids circulated while running in the hole (RIH) with the the production rate should be gradually increased to mini-
CT mize the migration of fines.

• Fluids used to circulate out wellbore fluids or fill material The pH of wellbore fluids should be monitored during the
that could be damaging to the formation cleanup period.

FOAM DIVERSION PRINCIPLES

A foam diversion process generally consists of five distinct and orderly steps.

1. Clean the near wellbore region (except dry gas wells).

Brine with mutual solvent or similar is injected to remove oil from the near wellbore region (oil destroys
foam) and to water wet the formation.

2. Saturate the near wellbore area with foamer.

Inject HCl or brine containing a foaming agent to displace the mutual solvent (solvents are detrimental
to foam), to minimize the adsorbtion of the foaming agent from the foam and ensure a stable foam is
generated in the matrix.

3. Foam injection.
A 55 to 75% quality foam fluid is injected into the matrix to generate a stable viscous foam,
resulting in an increased bottom hole treating pressure.

4. Shut-in (recommended).
A ten minute optional shut-in period decreases the time required to reach maximum diversion.

5. Inject treating fluids containing surfractant.

The treating fluid containing foaming agent is injected at a low rate. Omission of the foaming
agent at this step will reduce the foam stability and consequently reduce the diversion efficiency.

Figure 3. Foam diversion principles.

Page 9 of 12
 Section 330
COILED TUBING SERVICES MANUAL
Rev A - 98 MATRIX TREATMENT

1.1.9 Horizontal Wellbores addition, the requirements of the operating company and
applicable regulatory authorities must be known.
Attempts to bullhead acid treatments into horizontal
wellbores have generally proved ineffective. Techniques Equipment
that improve fluid placement and treatment efficiency have
been developed using CT. The work string is placed at the All treating and monitoring equipment must be spotted and
end of the wellbore and is slowly retrieved toward the operated in accordance with the requirements of the rel-
vertical section. Reactive fluids are pumped through the CT evant Standards of Operation. In addition, equipment
while an inert fluid is pumped down the CT annulus. This certified for use in hazardous areas must be operated and
technique assumes that the acid will react laterally with the maintained in accordance with the operating zone require-
formation exactly where the CT nozzle is located. Obvi- ments.
ously this is not always possible, especially in carbonate
reservoirs where thief zones can prevent the desired fluid Posttreatment
placement. Thus, horizontal wellbores are generally treated
in discrete intervals with stages of chemical diverters used Following any acid treatment, it is possible that H2S may be
to separate the treatment intervals. liberated. Therefore, appropriate precautions should be
taken during posttreatment work. Additionally, corrosive
1.2 Matrix Stimulation Operations treatment fluids may be produced to surface.

1.2.1 Execution Precautions 1.2.2 Equipment Requirements

Execution precautions to be observed during matrix stimu- Treatments, such as matrix stimulation, which require the
lation treatments are generally based on the corrosive and preparation and pumping of corrosive fluids must be care-
toxic nature of the chemical products used. However, there fully planned and executed. The treatment fluid and spent-
are several other important considerations which must be fluid returns should be routed to minimize exposure to
understood and accounted for in the execution procedure. personnel and equipment.
In addition, personnel involved in service activity or flowback
operations following the treatment, should be informed of 1.2.3 Coiled Tubing Equipment
the treatment and potentially hazardous conditions which
may exist on completion of the treatment. It is recommended that the CT workstring internal surface
be pickled with a low-concentration inhibited acid before
Personnel and Environment performing the matrix treatment. Such a treatment provides
the following benefits:
All personnel involved in the design or execution of matrix
stimulation or CT services must be familiar with require- • Rust and scale deposits that can be damaging to the
ments detailed in the relevant safety standards. formation if injected are removed.

The corrosive and toxic nature of most stimulation fluids • Inhibition from the main treatment fluid is more effective
and additives demands that care and attention are required if the inhibitor is adsorbed onto a clean surface.
during all phases of the operation. The handling, mixing
application, cleanup and disposal of stimulation fluids must The pickling process can be performed before or after the
be completed with due consideration for personnel and equipment arrives at the job site. A significant consider-
environmental safety. ation in determining the place of treatment is the disposal
of the fluids following the pickling treatment. In many cases
Well Security the most convenient disposal method is to use the wellsite
production or disposal facility.
The control of well pressure and fluids must meet the
requirements of the relevant Standards of Operation. In

Page 10 of 12
 COILED TUBING SERVICES MANUAL Section 330
MATRIX TREATMENT Rev A - 98

1.2.4 Pressure Control Equipment

Because significant quantities of H2S may be liberated

during an acid treatment, only H2S service pressure control
equipment should be used.

In treatments when acid is to be pumped through the

production tubing as well as the CT work string, the acid
injection point must be below the CT pressure control
equipment. Similarly, when flowing spent treating fluids,
avoid flowing through the CT pressure control equipment
(Figure 4). The extent of postjob flushing and neutralizing
of fluids in the CT pressure control equipment will depend
on the likelihood of corrosive fluid contact. However, due to BOP kill port
the nature of the equipment, acid contact should be Pump-in Tee
assumed and equipment internally cleaned and inspected
following every operation. Wing valve
1.2.5 Pumping Equipment
Casing valve
All fluid mixing pumping and storage equipment must be
clean and free from solids. If cementing equipment is to be
used, a pickling/acid treatment must be performed on the Production tubing
equipment and lines to ensure no solid particles are
released during the treatment. All tanks should have
accurate volume markers or strap charts to ensure correct
treatment volumes. Coiled tubing

All surface mixing, storage and pumping equipment must

be clean and free from damaging solids. The equipment and
lines should be flushed with clean water to remove poten-
tially damaging solids or liquids.

Pressure and rate limits for every stage of the operation

must be defined and noted on the pumping schedule.

Operations that require the manipulation or movement of

the CT string during the treatment must be conducted with
a good line of communication between the fluid pump
Figure 4. Pressure control equipment
operator and the CTU operator. In most cases radio
configuration.
headsets will be required.

The maximum pump rate achievable under the given

pressure limitations should be used to reduce the exposure
time of equipment to corrosive fluids and also to achieve
the maximum diversion effect.

Page 11 of 12
 Section 330
COILED TUBING SERVICES MANUAL
Rev A - 98 MATRIX TREATMENT

The volume and type of displacement fluid used during the 1.3 Evaluation of Matrix Stimulation
treatment will determine the amount of postjob flushing and
neutralizing that is required. The evaluation of matrix acidizing treatments is based on
the analyses of the reservoir response to the injection of the
1.2.6 Monitoring and Recording Equipment stimulation fluid. In particular, the change (improvement) in
reservoir flow characteristics is of interest.
Monitoring and recording equipment must be capable of
operating with all treating and displacement fluids at the By modeling and comparing the response of an ideal
rates anticipated during the treatment. reservoir with that of the actual reservoir, the degree of
damage is assessed. Injection pressures measured and
Wellbore, fluid and reservoir parameters required by record- recorded during the stimulation treatment can be inter-
ing and process software for real-time analyses should be preted to provide an indication of the efficiency of the
accurately input. damage removal.

Departures from the planned pumping schedule must be

noted for postjob reporting purposes.

1.2.7 Downhole Equipment

Prior to the installation of any tool in a CT tool string, the

following checks must be made:

• A note of the tool dimensions and profile must be made

for use in the BHA fishing diagram. Minimum require-
ments are length, OD, ID and connection size and type.

• Operating specifications for the tool must be noted, to

ensure that the operating conditions for the tool are not
exceeded. The following information should typically be
included — tension, compression and pressure limita-
tions, temperature ranges, H2S service and fluid compat-
ibility.

• All downhole tools which have been exposed to corrosive

fluids should be serviced as soon as possible following
retrieval. As a minimum requirement, the tools should be
broken at all service breaks and flushed clean.

1.2.8 Fluid Preparation

Fluids should be prepared to the design specification

following the standards set in the Standards of Operation.

Samples of all raw and mixed fluids should be taken and

kept until the job is completed and has been fully evaluated.
In addition, the pH and specific gravity (SG) of all fluids
should be checked and noted.

Page 12 of 12
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98

ZONAL ISOLATION

Contents Page

Introduction .................................................................................................... 2
1 SQUEEZE CEMENTING ................................................................................ 2
1.1 Laboratory Testing ............................................................................... 4
1.2 Thickening Time .................................................................................. 4
1.3 Fluid Loss ........................................................................................... 4
1.4 Rheology ............................................................................................. 4
1.5 Design ................................................................................................. 4
1.5.1 Slurry Volume ...................................................................................... 4
1.5.2 Slurry Placement ................................................................................. 6
1.5.3 Depth Correlation ................................................................................. 6
1.5.4 Protection Against Contamination ....................................................... 6
1.5.4 Cement Column Stability ..................................................................... 7
1.5.5 Tool Selection ...................................................................................... 7
1.6 Squeeze Cementing Operations .......................................................... 9
1.6.1 Execution Precautions ........................................................................ 9
1.6.2 Equipment Requirements .................................................................... 9
1.6.3 Treatment Execution .......................................................................... 11
1.6.4 Welbore Preparation .......................................................................... 14
1.6.5 Slurry Mixing and Pumping ................................................................ 14
1.6.6 Squeeze ............................................................................................ 15
1.6.7 Removal of Excess Cement .............................................................. 15
1.7 Evaluation of Squeeze ...................................................................... 16
1.8 Squeeze Cementing Procedures ....................................................... 16
1.8.1 Scab Liner ......................................................................................... 16

Page 1 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

Introduction • Water or gas channeling as a result of an incomplete

primary cementing job.
Squeeze cementing is the process of forcing cement
slurry, under pressure, through perforations or holes in the • Injection water or gas breakthrough.
casing or liner. This is done to permanently block the
intrusion of undesirable fluids to the wellbore. In oil wells, • Gas or water coning caused by production or reservoir
this is frequently required to reduce excessive water or gas characteristics.
production, which limits downstream separation or process
capacity. The cement providing the block to production • Isolation of unwanted or depleted perforated intervals.
must remain effective under the highest differential pres-
sure anticipated when production is resumed. • Losses to a thief zone or inefficient injection profile on an
injection well.
1 SQUEEZE CEMENTING
In treating these conditions, CT squeeze cementing tech-
When the cement slurry is forced against a permeable niques offer several advantages over conventional workover
formation, some of the fluid enters the formation matrix rig practices.
filtering out the slurry solids on the formation face.
• The CT pressure control equipment configuration allows
In performing a CT squeeze, the pressure is gradually the treatment to be performed through the completion
increased in predefined increments (hesitation squeeze). tubulars without the need for a rig. In addition, the well can
With a properly designed slurry and squeeze procedure, a be safely killed with relatively low volumes of fluid.
firm filter cake will fill the opening(s) allowing the final
squeeze pressure to exceed the formation fracture pres- • Associated operations can be performed as part of a
sure. packaged service, e.g. wellbore fill can be removed or
artificial lift services may be applied to restore production
The firm filter cake, in the form of nodes, allows cleaning of following the treatment.
the wellbore by circulation immediately after completing the
squeeze procedure. Therefore, subsequent drilling or • Placing the slurries and fluids through CT avoids contami-
underreaming operations to clean the wellbore are avoided. nation from wellbore and displacement fluids. The mobile
injection point improves the placement efficiency and
Squeeze cementing operations conducted through CT accuracy.
have been developed and improved in recent years. Oper-
ating procedures have evolved to suit well/production • Low treatment volumes are required and wellbore cleaning
conditions, and slurry design has been refined. of excess slurry is easily performed.

This means that significant cost savings can benefit • Experience has shown that significant time, product and
operators performing through-tubing workovers. Conven- cost savings can be realized.
tional methods of cement placement required the use of a
workover rig. However, most of the time and expense CT cementing requires more stringent design and control
associated with mobilization of equipment, well killing and considerations than conventional cementing operations.
completion handling can be avoided when using CT con- Only by exercising a high degree of control and verification
veyed services. In addition, the operational features of CT on all aspects of the operation can the desired result be
and associated pressure control equipment provide several reliably achieved. Since the consequences of an improp-
technical and economic benefits. erly applied squeeze cement treatment may be severely
damaging to the reservoir, wellbore or completion, correct
The following conditions are treated with a high degree of assessment of the well and reservoir conditions must be
reliability using CT squeeze cementing techniques: confirmed before the treatment design is finalized.

Page 2 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

TYPICAL COILED TUBING CEMENT SLURRY TEST SEQUENCES

Squeeze Slurries

• Mixing

Two hours at surface temperature and atmospheric pressure to simulate batch mixing and
surface operations.

• Placement

Two times the placement time (calculated from slurry and displacement volumes using
anticipated pump rates for the CT size to be used). Apply a constant gradient increase to
bottomhole pressure (BHP) and temperature (BHST).

• Squeeze

A 30-min period during which the temperature is kept constant and the pressure is increased
to the bottomhole squeeze pressure.

• Postsqueeze

Five hours during which temperature is kept constant at BHST and the pressure is decreased
from squeeze pressure back to BHP + 500 psi.

Plug Slurries

• Mixing

Two hours at surface temperature and atmospheric pressure to simulate batch mixing and
surface operations.

• Placement

Two times the placement time (calculated from slurry and displacement volumes using
anticipated pump rates for the CT size to be used). Apply a constant gradient increase to
bottomhole pressure (BHP) and temperature (BHST).

• Curing

Five hours during which temperature is kept constant at BHST and the pressure is decreased
from squeeze pressure back to BHP.

Figure. 1.

Page 3 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

1.1 Laboratory Testing The recommended thickening time is typically based on the
predicted job time plus a safety factor of 40-50%.
A variety of additives are commonly used to control the
characteristics of a squeeze slurry. The proportions used 1.3 Fluid Loss
in laboratory testing of cement slurries must be clearly
communicated to allow field operations to replicate the Additives are required to control fluid loss. These ensure
slurry and desired characteristics. the creation of good quality filter cake on permeable
surfaces in and around the perforation tunnel. Ultimately,
The mixing energy and manner in which it is applied affect this filter cake should cure to provide an impermeable
slurry properties. This causes a higher consumption, and cement node with sufficient compressive strength to re-
therefore requirement of additives by the cement slurry. As main secure at the anticipated differential pressure.
a result, slurries designed for use with CT must undergo
special laboratory test procedures which more accurately Excessive fluid loss can result in bridging of the well bore
simulate actual conditions. tubulars with dehydrated cement (Figure 2). Slurries with
too little fluid loss can result in an insufficient buildup of filter
The principal characteristics of a squeeze cement slurry cake on the formation surface.
are:
Three tests are commonly run on the resulting filtercake to
• Thickening time allow comparison or appraisal of the slurry— filter-cake
thickness, quality and temperature sensitivity. Filter-cake
• Filter-cake properties/fluid loss quality is assessed by penetrating the filter-cake with a
steel rod.
• Rheology
1.4 Rheology
A cement slurry only becomes stable when sufficient shear
energy is imparted to it (by mixing and pumping through the Cement slurries have a higher viscosity than most types of
CT). The shear energy imparted in the laboratory and in the workover fluid. This significantly reduces the maximum
field must be sufficient to achieve stable slurry character- pump rate achievable within operating pressure limits.
istics.
Typical squeeze slurry composition and characteristics are
1.2 Thickening Time shown in Fig. 3.

API testing schedules have been developed to test the Rheology and stability tests are commonly performed at
thickening time of squeeze cementing slurries. These surface mixing temperatures and at BHST. In general
schedules have been developed for use with drillpipe or stable slurries provide good rheology characteristics which
tubing placement. To more accurately reflect the actual are easily reproducible.
conditions encountered during a CT cement squeeze,
modified versions of the API schedules are used. A typical 1.5 Design
modified test schedule for CT operations is shown in Figure
1. 1.5.1 Slurry Volume

Bottomhole static temperature (BHST) should be used The volume of slurry to be prepared for a CT cement
when conducting test procedures. Conventional API test squeeze depends on several factors. In most cases,
schedules use bottomhole circulating temperature (BHCT). previous squeeze experience in similar reservoirs will
provide the best guidelines.
Because the mixing energy imparted to the slurry also
influences the thickening time, the test procedure should
closely simulate the anticipated mixing and pumping proce-
dure.

Page 4 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

Casing Formation

Node with minimal

intrusion into wellbore

Primary cement sheath

Figure 2. Cement node buildup.

SQUEEZE CEMENTING SLURRY SELECTION BY APPLICATION AND INJECTIVITY TEST RESULTS

Conventional Latex Thixotropic Foamed PERMABLOK
Application Cement Cement Cement Cement Treatment

Channels High Low-High - - Very Low

Poor Primary Cement High Low-High - - Very Low

Casing Liner/Repair - Low-High - - -

Gas Shut-Off Low-High Low-High - - Very Low

Water Shut-Off Low-High Low-High - - -

Injection Modification Low-High Low-High High Very High -

Figure 3.

Page 5 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

The following factors influence the required slurry volume: There are three methods of acquiring a depth reference: log
correlation, tagging bottom or tagging completion restric-
• Length of perforated interval and capacity of liner/casing. tions. However log correlation is incompatible with squeeze
cementing operations.
• Void areas behind the perforations resulting from the
erosion of friable and unconsolidated formations or from Tagging bottom can be significantly inaccurate in wells
stimulation treatments. containing fill. In addition, buckling of the CT occurs in
deviated wells or large completions, thereby inducing an
• The force applied to the tubing, i.e. in deep applications, error. However, in certain conditions it is a viable method
the additional tension resulting from the cement inside the which is often used.
CT may exceed operating limits.
Locating restrictions in the completion tubulars using a
• The configuration of surface mixing and pumping equip- tubing end locator (TEL) or tubing nipple locators (TNL) is
ment i.e. reducing the volume of surface lines (especially the most practical method of depth control in critical
large-diameter lines) reduces the likelihood of slurry squeeze cementing operations.
contamination.
1.5.4 Protection Against Contamination
• Use of cement plugs, pigs or darts to ensure separation
of slurry in the CT string reduces the excess slurry Contamination will result in unpredictable slurry character-
volume necessary to account for contamination. In addi- istics, a reduction in the compressive strength of the set
tion, plugs provide positive indication of slurry location. cement and incorrect placement due to the change in slurry
volume. Therefore care must be taken to avoid contamina-
1.5.2 Slurry Placement tion wherever possible.

The success of any cement squeeze is dependent on the It is recommended that spacer fluids are pumped ahead of
accurate placement of an uncontaminated slurry which has and behind the cement slurry. The most commonly used
the desired characteristics. The following factors are of and generally most appropriate spacer fluid is fresh water.
importance during slurry placement:
A great potential for contamination exists in the surface
• Depth control lines and pumping equipment. However, the following
precautions should be taken to ensure clean fluid interfaces
• Contamination protection and eliminate contamination.

• Cement column stability A reel manifold sampling point and flush line can be rigged
to allow the surface lines to be flushed each time a new fluid
• Isolation of adjacent zones is pumped (Figure 4). After isolating the CT reel and opening
the flush line at a sample point, the new fluid is pumped until
• Tubing movement uncontaminated fluid is observed at the sample point.
Pumping recommences downhole after the manifold valves
1.5.3 Depth Correlation have been realigned and a fluid volume reference is taken.

Depth-sensitive applications such as cement squeezing Mechanical separation of the cement slurry can be achieved
generally require the CT nozzle to be positioned and using CT plugs (darts or pigs). Such plugs operate in the
controlled using a higher degree of accuracy than can be same manner as the casing plugs used in primary cement-
achieved using surface measuring equipment. The effects ing operations. Plugs are fitted with rupture disks or land in
of stretch, buckling and residual bend can be variable and a plug catcher, providing a positive indication of plug
considerable. For this reason a downhole reference point is location.
generally required to achieve the necessary accuracy of
placement.

Page 6 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

To reel core and CT through

reel isolation valve

Circulating pressure sensor

From pump unit Flush line to

disposal

Sample point

Reel manifold valves

Figure 4. Reel manifold sampling point and flush line.

Plug launching equipment fitted to the reel allows several Using similar techniques to those above, adjacent perfora-
plugs to be preloaded and then launched in sequence tions below the zone to be squeezed can be isolated.
without affecting the pressure integrity of the reel or However, it is common for all perforations around the
manifold. squeeze zone to be cemented.

1.5.4 Cement Column Stability 1.5.5 Tool Selection

It is not possible to place a stable cement column off- Tool strings used in conjunction with cement squeezes
bottom, over a less dense fluid (Figure 5). To ensure correct should generally be kept to a minimum. However, there are
cement placement, a retaining platform must be used. The a number of functions which may be required depending on
following platforms have been successfully used: the application.

• Excess cement slurry • Connector

• Weighted gel Required on all jobs. Simple connectors are less sensi-
tive to accidental cement invasion than the grapple.
• Sand
• Check Valves
• Calcium carbonate
Cannot be used when procedures call for reverse circula-
• Through-tubing bridge plug tion of excess cement from the wellbore. When fitted,
only full-bore flapper check valves should be used.
The nature and size of an appropriate platform should be
determined for each case. Under some conditions it may be • Depth Correlation
appropriate to place the cement column from the bottom of
the rat hole. Tubing end or nipple locators are commonly used to
confirm depth; however, many treatments are performed
using TD as a reference point.

Page 7 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

Stable cement column

placed over the platform
Cement slurry falls through
less dense fluids resulting
in contamination and Cement platform consisting of
improper placement of the a high density fluid, sand or
cement column over the similar particulates, or a
treatment zone. through tubing bridge plug

Figure 5. Cement placement with and without a retaining platform.

Pins to retain ball within

the nozzle.

Multiple small-diameter
radial ports provide im-
proved jetting pattern.
Multiple small-diameter radial
ports provide improved ce-
ment placement and jetting
pattern.

Large diameter ports

Large-diameter port open during re- open during cement
verse circulation and closed when placement and closed
jetting or placing cement. by the drop ball when
jetting and circulating
out the excess cement.
Reverse circulating nozzle Improved jetting/circulation nozzle

Figure 6. Cementing nozzle features.

Page 8 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

• Plug Catcher Equipment

For use with plugs ahead or behind the cement slurry. All treating and monitoring equipment must be spotted and
Essentially to catch and retrieve the plugs. operated in accordance with the requirements of the rel-
evant Standards of Operation. In addition, equipment
• Nozzles certified for use in hazardous areas must be operated and
maintained in accordance with the operating zone require-
A variety of jetting nozzles have been developed to ments.
improve the slurry placement. Some configurations re-
quire more than one nozzle/jet configuration. Combina- 1.6.2 Equipment Requirements
tion nozzles (Figure 6) are designed to provide improved
reverse circulating and jetting capabilities. A schematic diagram of typical equipment layout is shown
in Figure 7.
1.6 Squeeze Cementing Operations
Coiled Tubing Equipment
In many cementing operations, the cement setting process
provokes a sense of urgency which can affect the normal Some operating companies require that the work-string
decision-making ability of personnel. It is essential that volume be checked by inserting and displacing a plug or
clear and precise procedures be prepared for the entire foam pig. Such checks can be combined with the displace-
cementing operation. This should include details of normal, ment of pickling treatments where required.
contingency and emergency operating procedures.
To minimize contamination, a flushing/sampling manifold
1.6.1 Execution Precautions should be rigged up on the CT reel.

Execution precautions for squeeze cement treatments Pressure Control Equipment

relate to the safety in handling of cement and chemicals.
They should ensure the correct placement of a slurry with All manifolds and valves should be flushed to ensure that
the desired characteristics. When a CT cement squeeze is all traces of cement are removed.
actually being pumped, it is critical that the position of the
cement/wellbore fluid interface be known at all times Pumping Equipment
(Figures 9 through 18). To facilitate this, a pumping sched-
ule should be developed and used. This schedule should All fluid mixing, pumping and storage equipment must be
show the position of the interface and the nozzle as a clean and configured to avoid contamination or dilution of
function of barrels pumped. the cement slurry.

Personnel Pressure and rate limits for every stage of the operation
must be defined and noted on the pumping schedule.
All personnel involved in the design or execution of squeeze
cementing or CT services must be familiar with require- All manifolds and valves should be flushed to ensure that
ments detailed in the relevant Standards of Operation. all traces of cement are removed.

Well Security Monitoring and Recording

The control of well pressure and fluids must meet the Accurate monitoring and recording of the job parameters is
requirements of the relevant Standards of Operation. In essential to allow complete control of the job and prepara-
addition, the requirements of the operating company and tion of postjob reporting and analyses. The schematic
applicable regulatory authorities must be known. diagram in Figure 8 identifies typical job parameters and
their point of measurement/recording.

Page 9 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

Coiled tubing
Sample BOP
point Riser pump-
in tee

Flowline
Flush
line Squeeze manifold
Triplex
pump

Bleedoff

Choke
Cement
manifold

Fresh water/
spacer

Displacement Sample point

fluid
Gauge tank

Displacement
fluid
To degasser

Figure 7. Typical squeeze cementing equipment configuration.

Page 10 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

Coiled tubing
• Monitor and record pressure ,
rate/volume, string weight,
depth and tubing OD and tub-
ing cycles.

Pump unit
• Monitor and record pressure,
density and pump rate/volume.

Slurry batch mixer

• Monitor density and volume.

Other tankage
• Monitor density and volume.
Annulus
• Monitor volume and density of
all fluids returned and pumped
through the annulus.
• Record pressure.

Figure 8. Squeeze cementing parameters to be monitored and recorded.

Downhole Equipment 1.6.3 Treatment Execution

A complete fishing diagram must be prepared to include all Cementing operations are frequently conducted in multiple
downhole equipment. In addition, the operation of all tools well campaigns within a field or area. Consequently, proce-
must be fully understood. dures are often tuned to meet local conditions. Whenever
possible, previous case histories for similar applications
should be referenced.

Page 11 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

Slurry pumped at
maximum rate
Choke open

Wellbore
pack fluid
Nozzle pulled up
Spacer/
50 ft below cement
fresh water
Filtered sea- interface
water or similar Cement
at high rate slurry
Choke open

Figure 10. Laying in cement slurry.

Slurry pumped at
maximum rate/
pressure allowed
Choke closed, if the
wellbore is not fluid
packed, pump
Wellbore clean
slowly down annu-
and packed
lus to prevent U-
tubing
Figure 9. Wellbore preparation.

Wellbore
pack fluid
Nozzle placed
above thief
Cement
zone
slurry
Wellbore
pack fluid

Figure 11. Placing thixotropic slurries.

Page 12 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

Low rate continuous Contaminant pumped

pumping or hesitation at maximum rate/
Choke back pressure Returns choked
returns moni- to maintain
toring pressure pressure on
and volumes squeezed zone

Wellbore
pack fluid Nozzle pulled Nozzle penetrates
Spacer/ up >50 ft slurry at a rate
fresh water above cement Contaminated which provides a
interface slurry 50% mix of con-
Cement slurry taminant

Cement
slurry

Figure 12. Commencing squeeze. Figure 14. Contaminating excess slurry.

Fluid pumped at
Displacement fluid maximum rate/
pumped at maximum pressure for allow-
rate/pressure allowed able differential
Choke back Open returns
returns increas- (1500 psi)
from CT
ing final squeeze
pressure
Nozzle penetrates
contaminated
slurry at a rate
which provides a
Wellbore Nozzle moved 50% mix of
pack fluid continuously or Wellbore contaminated
frequently pack fluid slurry and pack
Spacer/fresh fluid
water

Cement Contaminated
slurry slurry

Figure 13. Completing squeeze. Figure 15. Reverse circulating excess slurry.

Page 13 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

Execution of squeeze cementing operations is accom-

plished in four basic steps:
Fluid pumped at
maximum rate/ • Wellbore preparation
pressure for allow-
able differential • Slurry mixing and pumping
Open returns
(1500 psi) from CT
• Squeeze

• Removal of excess cement

See Figure 9 through Fig 17.

Nozzle penetrates 1.6.4 Wellbore Preparation

Wellbore slurry at a rate
pack fluid which provides a Wellbore preparation operations will generally include the
50% mix following:

• Slick-line work, e.g. fitting dummy gas-lift mandrels

Cement
slurry • Pressure test the production tubing annulus

Figure 16. Reverse circulating live slurry. • Establish hangup depth or TD using slick line

• Confirm and correlate depths with CT and flag the tubing

• Remove fill from the rathole below perforated interval

Fluid pumped at
• Perform pretreatment perforation wash or acidizing
maximum rate/
pressure
Returns choked to • Place a stable platform for the cement slurry
maintain pressure
on squeezed zone • Ensure that the wellbore is fully loaded with filtered water
(or equivalent)

1.6.5 Slurry Mixing and Pumping

Wellbore Before mixing and preparing the slurry, the wellbore should
pack fluid Nozzle reciprocated be fluid filled and a stable and adequate cementing platform
through treatment should be in place. In addition, placement depths should be
zone to TD confirmed and the CT flagged at critical points, e.g.
anticipated top and bottom of the placed cement column.

Differential pressure If a new cement blend is to be used, a yard test may be

maintained against useful after lab testing has been completed. In such a yard
squeezed zone test, the cement should be mixed in the service company's
yard using the same type of equipment that will be used on
Figure 17. Wellbore circulated clean. location. This test is necessary because cement blends
can act differently when mixed in a field blender than when

Page 14 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

mixed in a lab blender. The downhole generation of filter cake is aided by perform-
ing hesitation type squeezes (e.g., 10 min at 1000 psi, 15
Key points in the slurry mixing and pumping process min at 1500 psi, 20 min at 2000 psi....). As the fracture
include the following: pressure is exceeded during this process, the filter cake
prevents the formation from fracturing. A firm filter cake is
• Batch mix and shear the slurry ensuring that additive formed which contributes greatly to the success of the
proportions are accurately measured. Contingency plans squeeze operation.
should be made for dumping or disposal of slurry which
fails to meet the required specifications. 1.6.7 Removal of Excess Cement

• Conduct job-site quality control tests (filtercake, fluid An important feature of CT workovers is the ability to
loss, rheology). complete operations and restore the well to production in a
relatively short time. In the case of squeeze cementing
• Prepare contaminant and spacer fluids as required. operations, efficient removal of excess cement from the
wellbore is critical to the timely completion of the job.
• Confirm CT depth and coordinate tubing movement with Efficient removal of the slurry without jeopardizing the
pumped volumes. integrity of the cement nodes can be achieved using
several methods:
• Lay in cement slurry following the prepared pumping
schedule. • Reverse circulation of live cement

The following guidelines should be considered to reduce the • Circulation of contaminated cement
risks of operational failure when using thixotropic cements:
• Reverse circulation of contaminated cement
• Do not stop pumping while thixotropic cement is inside the
work string. Key points relating to the methods of removing excess
cement are detailed below.
• Place the CT nozzle above the thief zone and pump down
the production tubing/CT annulus while squeezing the Reverse Circulating of Live Cement
cement.
Reverse circulation of live cement slurry (uncontaminated
• Overdisplace thixotropic cement slurries out of the slurry) can be safely performed if the following conditions
wellbore. Once the slurry achieves a high initial gel are met:
strength, it may be impossible to clean the wellbore by
circulation (or reverse circulation). • The designed slurry thickening time (including safety
factor) should allow for completion of the reversing phase
1.6.6 Squeeze of the operation.

The effect of placing and squeezing cement slurry across • The CT penetration rate is controlled to effectively dilute
the treatment zone is often unknown. Squeeze pressure the slurry as it is removed (maximum density of reversed
may build quickly as the slurry contacts the formation face, fluid is 10 lb/gal).
or in formations with fractures or void spaces behind the
liner or casing, squeeze pressure may not be achieved. • Reversing is continued until clean returns are observed at
Consequently, prepared procedures must detail actions to the surface.
be taken for a number of events which may or may not
occur. Reverse Circulating Contaminated Cement

Contamination of the excess cement is often necessary to

extend the slurry thickening time, thereby allowing cleanout

Page 15 of 17
 Section 340
COILED TUBING SERVICES MANUAL
Rev A - 98 ZONAL ISOLATION

TYPICAL CEMENT SLURRY CONTAMINANT COMPOSITION

Borax/Bentonite
10 to 20 lb/bbl Bentonite
20 lb/bbl Borax
3 gal Cement Retarder D109 (case dependent)

Bio-Polymer Gel

1.5 lb/bbl Biozan gel

Figure 18.

operations to be completed safely. In addition, contaminat- Injection wells will typically be tested to the injection header
ing the excess slurry can allow cleanout operations to be maximum pressure. Wells to be reperforated and fractured
delayed until the cement nodes have increased the com- should be pressure tested to the maximum BHP antici-
pressive strength. Typical borax/bentonite and biopolymer pated during the fracturing treatment.
contaminant formulations are shown in Figure 18.
1.8 Squeeze Cementing Procedures
Circulation of Contaminated Cement
1.8.1 Scab Liner
If the operating conditions cannot safely support reverse
circulation of the excess slurry, conventional circulation A scab liner may be used to:
may be used. For example, operations performed through
1-1/4-in. work strings cannot employ reverse circulation • Shut off injection into thieving perforations.
techniques due to the excessive friction pressure encoun-
tered. • Establish injection in other (lower) perforations.

1.7 Evaluation of Squeeze The procedure used to create a scab liner includes the
following major steps:
The methods used to evaluate the efficiency of a cement
squeeze depend on the objectives of the treatment. How- 1. Rig up Slickline. Run in hole to gauge tubing and tag fill.
ever, the initial step in any evaluation process should be to Rig down Slickline.
confirm the condition of the wellbore in the treatment zone.
In the event that the wellbore is obstructed by large cement 2. Rig up CTU. Circulate in amount of sand required to
nodes or buildup, some drilling/underreaming may be create sand plug. Rig down CTU.
required. A wireline or CT conveyed drift run using tools of
an appropriate size is commonly used to check wellbore 3. Rig up Slickline. Proceed with squeeze/running scab
condition. liner if fill level within ±10 ft of desired level.

In addition a check should be made to ensure the rathole is 4. Load and pressure test the tubing by 9 5/8-in annulus to
debris or cement free. 2,000 psi. Rig down slickline.

The duration and differential pressure to which any cement 5. Rig up CTU. Run required length of jointed tubing.
squeeze treatment is tested will be at the discretion of the Cement liner in place with LARC cement (Liquid Latex
client. Acid Resistant) to 1,000 psi. Rig down CTU.

Page 16 of 17
 COILED TUBING SERVICES MANUAL Section 340
ZONAL ISOLATION Rev A - 98

6. Wait on cement for 48 hours. Rig up Slickline and tag

fill. Perform 2,000 psi pressure test on scab liner. Rig
down Slickline.

7. Rig up CTU and mill out cement in liner. Fullbore clean

out sand below the scab liner to below the perforations.

8. Open well to injection at RIR.

Page 17 of 17
This page left blank
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98

STIFFLINE

Contents Page
Introduction .................................................................................................... 2
1 DOWNHOLE FLOW CONTROL ...................................................................... 2
1.1 Design ................................................................................................. 4
1.1.1 Job Design Data .................................................................................. 4
1.1.2 Downhole Tools and Devices ............................................................... 4
1.1.3 Wellbore and Completion Geometry ..................................................... 8
1.1.4 Pressure Control Equipment ................................................................ 8
1.1.5 Toolstring Configuration ....................................................................... 9
1.1.6 Pumping Fluids ................................................................................. 10
1.2 Execution .......................................................................................... 11
1.2.1 Execution Precautions ...................................................................... 11
1.2.2 Equipment Requirements .................................................................. 12
1.2.3 Treatment Execution .......................................................................... 12
1.2.4 Contingency Plans ............................................................................ 13
1.3 Evaluation ......................................................................................... 13
2 FISHING WITH COILED TUBING ................................................................. 14
2.1 Design ............................................................................................... 14
2.1.1 Job Design Data ................................................................................ 16
2.1.2 Survey Tools ...................................................................................... 18
2.1.3 Primary Tools ..................................................................................... 18
2.1.4 Catch Tools ........................................................................................ 18
2.1.5 Support Tools .................................................................................... 20
2.1.6 Pumping Fluids ................................................................................. 22
2.2 Execution .......................................................................................... 22
2.2.1 Execution Precautions ...................................................................... 23
2.2.2 Equipment Requirements .................................................................. 23
2.2.3 Treatment Execution .......................................................................... 23
2.2.4 Contingency Plans ............................................................................ 27
2.3 Evaluation ......................................................................................... 27

Page 1 of 27
 Section 350
COILED TUBING SERVICES MANUAL Schlum berger
Rev A - 98 STIFFLINE

Introduction • Strength

Stiffline is the term used to describe CT operations which CT is considerably stronger than wireline allowing a
are adapted from conventional wireline or slickline applica- greater tension to be applied to the tool string.
tions. The ability to push the CT string in deviated and
horizontal wellbores plus the ability to exert higher forces • Rigidity
enables stiffline techniques and equipment to be used on
a wide variety of wellbores and applications. The rigidity of CT allows operations to be performed in
highly deviated and horizontal wells where wireline cannot
1 DOWNHOLE FLOW CONTROL operate.

Downhole flow control devices are used to selectively • Conduit

control production. The devices may be located in specific
landing nipples, tubing joints or on the tubing wall. Treatment fluids may be pumped through the CT to help
clean the operating environment of the tool or, in the case
These devices are commonly located, operated or re- of hydraulic tools, power the tool.
trieved by slickline. However, in certain applications, CT
can have several significant advantages over slickline and Many conventional wireline tools have been modified and
the heavier braided line services: redesigned for use with CT. In addition, several tools that

STIFFLINE AND DOWNHOLE FLOW CONTROL JOB DESIGN DATA

Tool/ Device
- Depth to tool or landing point.
- OD and ID.
- Length.
- Forces required to operate, retrieve or release.
- Circulation through tool?

Completion
- Acquire completion diagram, with special emphasis on points listed below.
- Smallest restriction.
- Location of all restrictions or possible hang-up points.
- Deviation and dogleg details.

Surface Equipment
- ID of pressure control equipment must be compatible with OD of fish and toolstring.
- Available length within the pressure control equipment must be compatible with the length
of fish and toolstring.

Fishing String
- A complete fishing diagram must be prepared for the fishing toolstring.
- OD and ID of the toolstring must be compatible with the ID of completion and surface
equipment, and the OD/ID of the fish.

Figure 1.

Page 2 of 27
 COILED TUBING SERVICES MANUAL Section 350
Schlum berger
STIFFLINE Rev A - 98

Wellhead landing nipple - designed to

allow temporary isolation of the wellbore

Subsurface safety valve

Gas lift mandrel

Selective landing nipple Flow coupling - installed to protect the tubing

from damaging turbulence caused by flow
control devices installed in the landing nipple

Circulation device - provides controlled

communication between tubing and
annulus for selective production

Production packer

Circulation device
(sliding sleeve)
Flow coupling
Selective landing nipple

Blast joint - hardened heavy-duty

tubulars placed over areas where
Polished nipple - short tubular with polished scouring or erosion is likely
bore which can accept a pack-off in the event
blast joint repairs are necessary Production packer

No-go landing nipple

Wireline entry guide

Figure 2. Common downhole flow control devices.

Page 3 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Schlum berger
Rev A - 98 STIFFLINE

incorporate a hydraulic function have been developed The majority of STIFFLINE tools or downhole flow control
specifically for use with CT. In many highly deviated or devices are manufactured by the following companies:
horizontal wellbores, CT is generally the only viable means
of running, operating or retrieving downhole flow control • Otis
equipment.
• Baker
This is one example of a STIFFLINE service. The designa-
tion STIFFLINE Services is given to CT services that are • Camco
generally conducted using non-electric wireline tool strings.
Such services may be categorized as follows: 1.1.1 Job Design Data

• Conveying retrievable flow control tools The initial steps for the design of an appropriate CT
conveyed fishing technique requires thorough investigation
A wide variety of flow control devices are commonly used of the following points:
to selectively control production.
• Type of tool or device
• Operating fixed completion equipment
• Wellbore and completion geometry
This principally involves the operation (opening and
closing) of sliding sleeves, or circulation devices located • Surface equipment
in the production tubing or uncemented production liner.
• Logistical constraints
• Conveying gauges or monitoring equipment
A summary of the typical data required is shown in Figure
Gauges and sampling or monitoring equipment can be 1. This should be used as a checklist when preparing to
conveyed by wireline or CT, and if necessary secured in design or execute a CT fishing operation.
a tubing nipple or similar locating device.
1.1.2 Downhole Tools and Devices
• Wellbore servicing
Figure 2 gives a brief description of common completion
A variety of well service operations are commonly per- devices, and shows a typical configuration for these
formed, generally as preparatory work before performing devices.
other services e.g. tubing drifting, depth (fill) check,
paraffin removal. Sliding Sleeves

• Fishing Sliding sleeves are an example of downhole flow control

devices. They are full opening devices installed in the
Wireline fishing operations can provide a rapid and eco- tubing string to allow communication and circulation be-
nomic solution to a variety of light fishing problems. tween the tubing and annulus. Since sliding sleeves are
non-retrievable mechanical devices which are part of the
1.1 Design completion, they should function efficiently for the lifetime
of the completion.
There are several manufacturers of tools and equipment
used for downhole flow control. Many of the tools are similar In certain types of completion (typically horizontal comple-
in operation but are incompatible. Therefore it is essential tions) an uncemented liner may be equipped with external
that full details of all tools, downhole devices and equip- casing packers and sliding sleeves to allow selective
ment be known before planning or designing a downhole production/treatment of the producing interval.
flow control operation.

Page 4 of 27
 COILED TUBING SERVICES MANUAL Section 350
Schlum berger
STIFFLINE Rev A - 98

In completions containing multiple sliding sleeves, selec- Landing Nipples

tive operation of the sleeves can achieved by using
different sizes of sleeve/tool or using a series of sleeves Landing nipples are made up as part of the permanent
with selective capability. In most cases (but with several completion. They provide known depth seats in which
exceptions) sliding sleeves are opened by upward jarring various types of flow control device can be easily and
and closed by downward jarring. reliably located. Nipples are configured as short tubulars
with tool joints machined top and bottom. Each nipple is
Deposits of scale or wellbore debris can give rise to internally machined and honed to provide a precise seal
operational problems with sliding sleeves. Accumulation of area and locking recess.
scale or debris can occur in the open or closed position and
can prevent further cycling of the sleeve. In either case, it The size and location of landing nipples in the completion
is essential that attempts to cycle the sleeve do not must be known for every CT operation since they are
jeopardize its efficiency in the completion (e.g. by applying generally the smallest restriction(s) in the wellbore.
too much force).
There are four basic types of landing nipple:
Placement of treatment fluids and operation of tools to
remove scale and debris from sliding sleeve mechanisms • Non-selective landing nipple
is a common CT application. In some cases, circulation of
fluid through a sleeve operating tool designed for CT may Normally used as a single nipple in the tubing string, or
be sufficient. In severe cases, a separate treatment or installed as the bottom nipple in a series to prevent loss
cleanout operation may be required. Jetting tools, brush of wireline equipment below the tubing end. In such
tools and tools designed to remove debris by suction have nipples a reduced internal diameter is machined to pro-
been developed to assist in the maintenance and operation vide a no-go of known dimension.
of sliding sleeve completions.
• Selective landing nipple

A series of selective landing nipples may be installed at

various depths in the completion string. Selection of the
desired landing nipple may be achieved by differences in
nipple/tool profiles, dimension or by special selective
running tool devices.
Seal bore
• Safety valve landing nipples

Locking recess Specially designed for locating retrievable subsurface

safety valves. In addition to one or two locking and
locating recesses, safety valve landing nipples also
No-go profile incorporate a port(s) for hydraulic operation of the safety
valve.

• Ported landing nipples

Ported landing nipples are designed to allow tubing-to-

casing/liner communication.

Selective landing nipples are designated by type and seal

bore diameter. However, non-selective, or no-go landing
nipples are identified by type, seal bore diameter and no-go
Figure 3. Landing nipple features. diameter (Figure 3).

Page 5 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Schlum berger
Rev A - 98 STIFFLINE

COMMON LANDING NIPPLE TYPES AND SIZES

Tubing Weight I.D Drift Typical Nipple Bores

Size (in.) (lb/ft) (in.) (in.) Seal Bore (in.) No-go ID (in.)

2 3.4 1.670 1.576 1.500 1.448

2-3/8 4.60 1.995 1.901 1.875 1.822

5.30 1.939 1.845 1.781 1.728
5.95 1.867 1.773 1.710 1.640
7.70 1.703 1.609 1.500 1.448

2-7/8 6.40 2.441 2.347 2.250 2.197

7.90 2.323 2.229 2.188 2.098
8.60 2.259 2.165 2.062 2.005
9.50 2.195 2.101 2.000 1.910
11.00 2.065 1.972 1.812 1.760

3-1/2 9.30 2.992 2.867 2.750 2.660

12.70 2.750 2.625 2.562 2.472
15.80 2.548 2.423 2.313 2.230
17.05 2.440 2.315 2.188 2.098

4 11.00 3.476 3.351 3.313 3.256

11.60 3.428 3.303 3.250 3.160
13.40 3.340 3.215 3.125 3.072
16.50 3.140 3.015 2.813 2.760

4-1/2 11.60 4.000 3.875 3.813 3.759

12.75 3.958 3.833 3.750 3.695
13.50 3.920 3.795 3.688 3.625
16.90 3.724 3.679 3.437 3.347
18.80 3.640 3.515 3.437 3.347
21.60 3.500 3.375 3.250 3.160

5 11.50 4.560 4.435 4.250 4.135

15.00 4.408 4.283 4.125 4.035
18.00 4.276 4.151 4.000 3.900
20.80 4.156 4.031 4.000 3.900
23.60 4.044 3.919 3.750 3.695

5-1/2 15.50 4.950 4.825 4.750 4.660

17.00 4.892 4.767 4.562 4.470
20.00 4.778 4.653 4.562 4.470
23.00 4.670 4.545 4.312 4.255
26.00 4.548 4.423 4.312 4.255
28.40 4.440 4.315 4.250 4.135

7 29.00 6.184 6.059 6.000 N/A

35.00 6.004 5.879 5.750 5.625

Figure 4. Common nipple dimensions.

Page 6 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

COMMON NIPPLE AND LOCK SYSTEMS

Nipple Lock Mandrel Running Tool Pulling Tool Remarks

OTIS

S (T)* S(T)* T R Nipple selective

N (Q)* N(Q)* T R No-Go version
X (R)* X(R) X GR, GS Running too selective
XN (RN)* XN (RN) X GR, GS No-Go version

CAMCO

W-1 M W-1, WC-1 JDC Running tool selective

D C D JDC No-Go version
DS CS D JDC Large bore version (4-1/2- to 7-in.)
A - - - Polished sub with no-go but
without no locking profile.

BAKER

F S C-1, E, G R** Running tool selective

F W C-1 R** Up-facing locks
R Z C-1 R** No-Go version W
F G C-1 R** Flow-through lock with external
fishing neck
F F M M Flow through lock with internal
fishing neck
R R C-1 R Bottom no-go version of G
R E M M Bottom no-go version of F

* Heavy wall version

** Generally, RB, SB, JUC, and JDC tools of various sizes can be used.

Figure 5. Common nipple and lock systems.

Common landing nipple types and sizes are summarized in There are four basic types of locking mandrel:
Figure 4.
• Tubing Set Mandrel
Locking Mandrel
Tubing set mandrels can be set anywhere in the tubing
Retrievable flow control devices, plugs, and a number of string. They are anchored by a slip assembly which acts
special application tools are generally assembled on a on the tubing wall. The pressure rating for such devices
locking mandrel. The locking mandrel, in conjunction with is generally low (±1500 psi) since the condition of the
the appropriate running/retrieving tool(s), provides the means tubular wall is unknown.
of running, setting, anchoring and retrieving the downhole
assembly.

Page 7 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

• Collar Set Mandrel Wellbore Servicing Tools

Collar set mandrels are located and locked in the recess Several well service operations are commonly completed
formed by the collar joint on certain types of tubing. They using special toolstrings conveyed on wireline. Modified
typically have a higher pressure rating (±5000 psi) but tools conveyed on CT can extend the utility of such
obviously cannot be used with internal flush tubing strings services by using the fluid circulating capability of the
such as VAM or Hydrill CS. workstring and tools. In addition, the higher forces which
can be applied by the CT workstring, both up and down, can
• Selective Mandrel be beneficial.

When combined with the appropriate landing nipple(s) or Basic wellbore servicing activities are frequently performed
running tool, selective mandrels can be selectively set in association with other services. In many cases the tools
within a series of nipples. used can be adapted to provide special or multiple func-
tions (gauge cutting, paraffin scratcher, swaging tools,
• No-go Mandrel sand bailers blind box, etc). Operations requiring place-
ment of fluid in conjunction with plug setting or retrieval may
The no-go mandrel must be used in conjunction with an be expedited by using a CT tool string. For example, a
appropriate no-go landing nipple. temporary tubing plug may be set and a kill weight column
of fluid circulated into place in one combined operation.
A summary of common mandrels and associated landing
nipples is shown in Figure 5. Also shown are the fishing Some tools and systems have been redesigned to use the
neck configurations. Tools and equipment equipped with hydraulic capability of the CT string. In horizontal applica-
internal fishing necks have the potential for a larger through- tions, the actual weight or force applied to the tool string by
bore than external fishing neck tools. setting down or picking up can be difficult to accurately
quantify. This inability is related to the behavior of the CT
When fishing or retrieving isolation devices, some consid- in the wellbore. By incorporating a hydraulic function into
eration must be given to pressure differential which may the tool mechanism, the operation is simplified and
exist across the tool. Such a differential pressure can act reliability increased.
to force the toolstring up or down the wellbore. Some types
of tool incorporate an equalization valve which prevents the 1.1.3 Wellbore and Completion Geometry
device from being released until the differential pressure is
reduced to a safe level. The maximum OD of CT and toolstring which can be safely
used is determined by the minimum tubular or restriction
Gauges and Monitoring Devices size. The presence and removal of fill or debris must also
be considered when assessing drift clearances on engag-
Gauges and monitoring devices are frequently run to record ing tools.
the reservoir parameters or bottomhole conditions while the
well is producing or shut in. In addition, it is often desirable The wellbore geometry must be carefully considered when
to obtain bottomhole data during stimulation treatments. determining the forces available for operation of the
The running and retrieving of memory gauges can be toolstring.
performed by CT in conjunction with the treatment or as a
separate operation. 1.1.4 Pressure Control Equipment

The ability to spot and circulate treating fluids through the In general terms, more complex operations will require
CT workstring avoids potential problems caused by produc- more pressure control equipment. If space at the wellsite is
tion or treatment solids which may hamper retrieval of the a constraint (e.g. offshore), some job design options for live
gauges. well work may be precluded. Government authorities or
operator procedures may determine the configuration of
pressure control equipment necessary to maintain the

Page 8 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

required number of barriers to wellbore pressure and fluids. Release joint mechanisms may be activated by tension,
internal pressure or both. Pressure activated devices may
The total length and OD of the recovered toolstring will require a ball to be circulated into place to effect a release.
determine the minimum length of riser or lubricator required. Care must be taken to ensure that the operation of the
There must be sufficient space within the pressure control release joint is compatible with the hydraulic functions of
equipment and lubricator to contain the entire length of CT the toolstring. In addition, any tools located above a ball
tool string and retrieved assembly. operated release joint must be drifted to an appropriate
size.
1.1.5 Toolstring Configuration
Jar
The selection of an appropriate running, retrieving or
operating tool depends on the size and type of downhole Jars are used to deliver an impact force to set or free a
device, and its orientation in the wellbore. A wide variety of downhole device. Most jars operate in one direction only.
tools, in a range of sizes, are manufactured by several However, some recently developed models are bidirec-
vendors. To avoid the requirement for an extensive range tional.
to be kept in stock, many STIFFLINE tools are capable of
being adapted or modified to suit the intended application. Early in the development of STIFFLINE services, a signifi-
cant limitation of CT as a conveyance method was identi-
All tools must have at least one means of disengaging in the fied. While much greater forces and tensions may be
event that the downhole device remains fixed and cannot applied by the CT, the ability to jar downward using the
be retrieved. Such release mechanisms may be actuated available tools is limited. Since many conventional wireline
by tubing set-down, over-tension or by a hydraulic system tool running and retrieving functions rely on a downward jar
controlled by fluid pump rate/pressure in the workstring. stroke to shear pins or release collets, alternative tool string
operating methods have been developed.
NOTE: The facility of an internal release mechanism does
not preclude the use of a separate release joint to be Jars and accelerators capable of firing upward and down-
operated in the event of release tool failure. ward and with a pump-through facility have been developed
for CT applications. Used in conjunction with appropriate
Support Tools tool strings, the down jars provide the controlled force
necessary to operate many of the existing running or
Support tools provide the toolstring with enhanced capabil- retrieving tool mechanisms.
ity for catching and retrieving the fish. They may not be
required for all applications. However, they can be consid- The operating principle of jars commonly used in CT fishing
ered as standard STIFFLINE equipment with appropriate operations may be mechanical, hydraulic or fluid powered.
size tools being held at many CT service points.
NOTE: Jars must always be used in conjunction with a
Release Joint compatible accelerator.

A release joint provides a means of parting the CT toolstring The available overpull at the tool should be determined
in a controlled manner in the event the toolstring becomes using computer simulations to allow the selection of an
stuck. The resulting fishing neck is designed to allow easy appropriate jar/accelerator assembly.
reconnection with an appropriate fishing tool.
Accelerator
It is recommended that a release joint be incorporated in
any toolstring with an external upset, or OD, greater than The primary function of the accelerator is to store the
that of the connector/check valve assembly. In addition, energy which is released when the jar fires. In addition, the
any toolstring which latches onto objects, or engage in toolstring and CT above the accelerator are protected from
profiles, in the wellbore should be protected by a release shock loads while jarring. The operating principal of most
joint. accelerators is mechanical. However, hydraulic accelera-

Page 9 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

tors, often known as intensifiers, are also available. be erroneously interpreted, so compromising the efficiency
of the job.
NOTE: Accelerators must be matched to the performance
of the jar. Fluids may be pumped for a number of reasons prior to, and
while performing, a STIFFLINE operation.
Orientation and Locating Tools
• Well control/kill
A number of tools have been developed to assist in locating
and engaging retrieving tools: An early decision as to whether the well should be killed
can significantly influence the selection of appropriate
• Centralizer tools and techniques. Therefore an attempt should be
made to evaluate the options associated with killing the
A variety of centralizers in a range of sizes may be used well early in the job design process.
to assist locating and engaging a device which is central-
ized in the wellbore. Springbow or spring arm centralizers • Conditioning wellbore
are the most appropriate design for use in multiple ID
applications. However, the additional friction caused by For example freeze protection in cold weather areas
the centralizer may induce premature lock up in highly
deviated and horizontal wells. • Fill removal

• Knuckle Joint Fluid circulation for the removal of fill material, or debris,
on and around the tool operating area is one of the major
Pump-through knuckle joints designed for use on CT advantages of CT conveyed fishing techniques.
operations are often required in deviated wells or crooked
tubulars, or where gas-lift mandrels hinder the operation • Jetting to assist centralization
of the toolstring. In some applications, two knuckle joints
or a dual knuckle joint tool are required to ensure the Side ported nozzles or subs can be used to centralize
necessary flexibility and alignment. toolstrings.

• Orientation Tools • Circulation power tools

These are a relatively new development to allow the Fluid powered jars, orientation devices and hydraulically
toolstring to be rotated. They are an example of a rapidly activated catch/release tools require the circulation of
increasing range of speciality tools developed for CT fluid or application of internal pressure in the workstring.
conveyance. Operation of the tools is typically controlled
and powered by fluid pumped through the CT. Slow • Circulation to cool tools
turning motors and indexing bent subs are currently being
developed and evaluated for a variety of applications. Circulation through hydraulic jars and intensifiers helps
dissipate some of the heat which can build up through
1.1.6 Pumping Fluids repeated jarring action. The efficiency and longevity of
the tools can thereby be improved.
In all CT operations the density and volume of all fluids
pumped must be closely monitored and noted. Because the • Buoyancy
workstring weight is a vitally important parameter while
running or retrieving downhole tools, any actions which may The effects of buoyancy can be applied to increase the
affect the weight must be closely monitored. Apparent tension applied at the toolstring. However, this technique
changes in workstring weight are quickly evident when should generally only be used as a contingency measure.
pumping fluids of differing density. Additionally, compara-
tively small volumes of fluid can induce changes which can

Page 10 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

1.2 Execution

Accurate monitoring and recording of key parameters (i.e.

weight, depth and pumped fluids) is essential during all
phases of the STIFFLINE operation. In addition, accurate
wellbore and fishing diagrams must be maintained and
updated as the operation progresses.

1.2.1 Execution Precautions

Personnel CT connector/check valve

All personnel involved in the operation design or execution

must be familiar with requirements detailed in the relevant Release joint
Standards of Operation.

Some applications may require the co-ordination of slickline

or wireline services to complete the operation. In this event,
special care must be taken to ensure all personnel involved Accelerator
are familiar with safety requirements and are aware of the
intended operation and procedures.

Well Security

The control of well pressure and fluids must meet the Weight bar
requirements of relevant Standards of Operation. In addi-
tion the requirements of the operating company and appli-
cable regulatory authorities must be known.

Fishing and STIFFLINE operations frequently use long

riser or lubricator assemblies. While recovering the fish or Jar
toolstring, relatively large volumes of gas may have to be
depressurized and purged from the surface pressure con-
trol equipment. Safety precautions associated with the
release and purging of flammable and/or toxic gases must
be observed. Running, operating or
pulling tool
Equipment

All treating and monitoring equipment must be spotted and

operated in accordance with the requirements of the rel- Figure 6. Basic Stiffline toolstring configuration.
evant Standards of Operation. In addition, equipment
certified for use in hazardous areas, must be operated and
maintained in accordance with the operating zone require-
ments (e.g. Zone II equipment).

Page 11 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

1.2.2 Equipment Requirements 1.2.3 Treatment Execution

The following equipment requirements are of significance The steps required to successfully complete a STIFFLINE
during CT STIFFLINE operations and should receive spe- operation depend on the particular conditions encountered
cial attention. in each case. In the following section, the key points in each
phase of the operation are outlined. When preparing and
Coiled Tubing Equipment documenting a treatment procedure, it is recommended
that the key points be reviewed with applicable points being
Depth and weight are critical parameters which must be incorporated into the procedure as required.
accurately monitored and recorded throughout the fishing
operation. Monitoring and recording equipment must be A basic tool assembly suitable for a variety of conditions is
fully operational and operating within the calibration limits shown in Figure 6. Several toolstring options may exist,
of error. though the final selection will typically be based on
availability, operator preference or previous experience.
Precise control of the injector head functions is required for
proper operation of downhole tools. Applying and releasing The operating method and sequence of each tool must be
tension in the workstring must be accomplished smoothly understood and a compatibility check made to ensure that
to avoid damaging downhole tools or surface equipment. the toolstring will operate as intended. This especially
applies to catch-tool release mechanisms.
Pressure Control Equipment
Wellbore Preparation
All components must be pressure tested and function
tested. In addition, the ID and length of all equipment must Wellbore preparation procedures performed as part of, or
be physically measured and a diagram prepared showing prior to, STIFFLINE operations may include the following.
configuration and lengths.
• Remove or secure the subsurface safety valve
Downhole Equipment
This reduces the risk of sticking the toolstring and or
All tool service joints and tool joint connections must be damaging the safety valve. In addition, the consequences
torqued to an appropriate value. Thread locking compounds of accidental safety valve closure, with the workstring in
should be used where applicable. the wellbore, can be severe.

A complete and accurate fishing diagram must be prepared • Placement of dummy gas lift mandrels
for the toolstring. This diagram must also be updated as
required. As above, to reduce the risk of sticking and/or damage.

Monitoring and Recording • Bullhead wellbore fluids

Depth measuring equipment should be zeroed with the CT It may be desirable to pack the wellbore with fluid to
connector against the stripper. The toolstring length and enable improved well control, (e.g. where a significant
distance from wellhead reference point must then be used pressure differential across the fish exists).
to correct for actual depth. The weight indicator should be
zeroed when the toolstring has been made up and swab • Slickline drift of wellbore tubulars
valve opened (i.e. zero weight indicator with wellhead
pressure applied). Performed to ensure free passage of the toolstring through
completion restrictions or scale build up.

Page 12 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

• Well kill • The toolstring cannot be retrieved high/far enough into the
pressure control equipment to allow closure of the master
A decision to kill the well prior to fishing operations valve (or similar isolation device).
commencing, can simplify several aspects of the job.
• In the event the string becomes stuck and it is necessary
Tool Operation to cut the workstring, consideration should be given to
cutting the CT inside the production tubing to allow easier
Repeated attempts to catch or work loose a downhole retrieval.
device may cause excessive fatigue on a localized portion
of the CT workstring. Close monitoring of the internal 1.3 Evaluation
pressure and the number of cycles made during each phase
of the operation is necessary. In the event a localized Evaluating the success of a STIFFLINE operation would
section of workstring is repeatedly worked, it may be appear to be straightforward. However, there are several
necessary to retrieve the toolstring and cut a length of possible outcomes which may influence subsequent op-
tubing from the end of the workstring. This will expose a new erations or the return to production. In the event that the
portion of workstring to repeated cycling. The cycling operation objectives are not entirely met, an analysis of the
parameters, number of cycles and length of tubing to be cut operation should be made to determine what actions or
must be determined by the conditions encountered. procedures could have been changed to yield improved
results. This should be documented as part of the job
When using hydraulic jars, repeated jarring should be report, thus enabling subsequent operations to be designed
undertaken with some consideration for the heat build up with the benefit of previous knowledge.
which will ultimately affect the useful life of the tool.

Retrieval

The advantages or disadvantages of maintaining circula-

tion during recovery should be assessed.

If the recovered assembly is near fullbore in the production

tubing, the tendency to swab should be anticipated and
necessary precautions taken.

In the event that complete recovery of the assembly is not

achieved, the job close-out report should contain a wellbore
diagram showing details and locations of known fish or
debris.

1.2.4 Contingency Plans

Contingency plans should be prepared during the job design

process. As a minimum, details of actions to be taken
under the following scenarios should be prepared.

• The downhole assembly cannot be retrieved and remains

stuck.

• The downhole assembly remains stuck and the running or

pulling tool cannot be released; the toolstring must be
parted by operating the release joint.

Page 13 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

2 FISHING WITH COILED TUBING The toolstring used to conduct CT fishing operations must
be capable of several functions.
Fishing may be defined as the removal of broken, dropped
or stuck tools and equipment (known as fish) from a • Catching and holding the fish.
wellbore. There are a number of tools and techniques which
may be used in fishing operations. The tools and tech- • Applying sufficient tension, or energy through jars to
niques used depend on the nature and configuration of the permit retrieval of the fish.
fish, the wellbore, and completion and surface equipment.
Consequently each fishing job is unique and requires • Releasing the fish in the event it cannot be retrieved.
thorough investigation to enable efficient design and ex-
ecution. On live-well fishing operations, sufficient riser or lubricator
length must be available to allow the entire fish to be pulled
Many of the tools and techniques used during fishing above the master valve or lowest pressure control valve.
operations are used to operate downhole completion equip- Only in this way can the CT equipment, toolstring and fish
ment and flow control devices, resulting in some confusion be safely removed while maintaining the necessary barriers
in definition and terms. For the purpose of this manual against well pressure and fluids.
section “fishing” does not include the running, retrieval or
operation of downhole flow control devices or equipment. Depth and weight are vitally important parameters in any CT
fishing operation. Both must be closely monitored and
The operational features of CT fishing techniques offer recorded during all phase of the operation. The importance
several advantages over conventional fishing methods: of properly functioning, accurate equipment cannot be
understated.
• Coiled tubing is considerably stronger than slickline or
braided line allowing the application of greater forces and The extensive range of existing tools and techniques
lifting capacity. coupled with the rapid development of speciality fishing
tools render it impractical for most CT service points to
• The rigidity of CT allows access to highly deviated or stock a comprehensive range of tools. However, since
horizontal wellbores. fishing operations often need to be mobilized quickly, it is
recommended that a contingency plan be prepared to allow
• Fluids circulated through the CT can be used to improve rapid response. Such a plan should be based on the
access to the fish. location and availability of third party fishing tools and
equipment. The typical configuration of local wellbore
• Fluids pumped through the CT can also be used to power tubulars and completions should be used to assist in the
specialized tools. preparation of the contingency plan.

There are a number of basic tools and techniques which are 2.1 Design
commonly used, and apply on most types of fishing
operation. Fishing operations, by their nature, are often approached as
“one-off” jobs. Consequently the documentation, or record-
Early fishing tools conveyed on CT were adapted from ing, of procedures and techniques has historically been
established wireline tools. Many of these tools were modi- deficient and much of the expertise in the industry has been
fied to allow circulation through the toolstring. This weak- acquired verbally or by experience.
ened some of the tool components, which combined with
the higher forces exerted by the CT, resulted in a service While CT conveyed techniques can be successfully em-
with questionable reliability. Subsequent tool designs are ployed over a wide range of fishing applications, medium-
designed and built to utilize the features of CT conveyed to heavy-weight through-tubing operations performed on
services with greatly improved reliability. live wells are most common (Figure 7). Conventional
wireline fishing techniques can be used to perform the
lighter-weight operations utilizing easily mobilized equip-

Page 14 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

FISHING TECHNIQUES AND APPLICATIONS

Lightweight Heavyweight

Slick Braided Coiled Snubbing Workover

Line Line Tubing Unit Rig
Live well x x x x

Deviated Well x x x

Circulation x x x

Easy Mobilization x x x

Rotation (Milling) x x x

Figure 7. Fishing techniques and applications.

FISHING JOB DESIGN DATA

Fish
- Depth to fish
- OD and ID of fish
- Length of fish
- Fish free or stuck
- Circulation through fish?

Completion
- Acquire completion diagram, special emphasis on points listed below
- Smallest restriction above fish
- Location of all restictions or possible hang-up points
- Deviation and dogleg details

Surface Equipment
- ID of pressure control equipment must be compatible with OD of fish and toolstring
- Available length within the pressure control equipment must be compatible with the
length of fish and toolstring

Fishing String
- A complete fishing diagram must be prepared for the fishing toolstring
- OD and ID of the toolstring must be compatible with the ID of completion and sur-
face equipment, and the OD/ID of the fish.

Figure 8. Fishing job design data.

Page 15 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

ment. The sensitivity of wireline equipment is considerably 2.1.1 Job Design Data
greater than that of CT equipment, making the retrieval of
small loose objects easier. In addition, the running speeds The initial steps for the design of an appropriate CT
and rig up times are faster than may be typically achieved conveyed fishing technique requires thorough investigation
by CT. of the following points:

Wireline equipment is of lower cost than CT equipment, • Fish type and dimensions
consequently, for lightweight fishing operations wireline is
generally the preferred conveyance method. However, in • Wellbore and completion geometry
an number of unusual conditions (e.g. if access to the fish
is hampered by fill), CT can provide the only viable means • Surface equipment
of completing the fishing operation.
• Logistical constraints

A summary of the typical data required is shown in Figure

8. This should be used as a checklist when preparing to
design or execute a CT fishing operation.

3.750 in.

2.313 in.
2.000 in.
Depth to top of fish 3455.50 ft
1.813 in.

2.000 in.
1.500 in.
3.500 in.
4.250 in.

Fish OD and length information

are presented in a general
fishing diagram Wellbore tubular

Figure 9. Fishing diagram - fishing neck detail.

Page 16 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

Fish Type and Dimensions Wellbore and Completion Geometry

Precise details of fish type and dimensions are often not The minimum tubular or restriction size will obviously
readily available. This will generally require some investiga- determine the maximum OD of CT and toolstring which can
tion or assumptions to be made. Under such circum- be safely used. The removal of fill or particulates must also
stances it should be noted that the chances of success and be considered when assessing drift clearances.
a timely completion of operations depends greatly on the
accuracy of data concerning the fish. Many types of fishing When fishing or retrieving isolation devices (e.g. inflatable
tools will only catch on a limited size range (OD or ID) and bridge plug) some consideration must be given to pressure
must be prepared accordingly. differential which may exist across the tool. Such a
differential pressure can act to force the toolstring up or
When the dimensions of the fish are known, an accurate down the wellbore.
fishing diagram must be prepared. The diagram should be
drawn to scale to allow the inclusion of additional factors. The wellbore geometry must be considered when determin-
For example, suspected scale build up on the wellbore ing the overpull available at the fish. Such information is
tubular can be included in the diagram, thereby influencing required for the selection of an appropriate jar/accelerator
the OD or profile of the fishing toolstring (Figure 9). assembly.

As a supplement to the fishing diagram a wellbore or Pressure Control Equipment

completion diagram should be prepared showing fish loca-
tion and noting the dimension and location of nipples and In general terms, complex job fishing operations will require
restrictions which could hamper retrieval of the fish. more equipment. If space at the wellsite is a constraint (e.g.
offshore), some job design options for live well work may
In addition to the location and dimensions of the fish several be precluded. National authorities or operator procedures
other points influence the selection of fishing tools and
techniques.

• Fish stuck/free

Stuck fish generally require stronger, more complex, and

consequently longer, toolstrings than fish which are free.
Offset and
• Presence of fill or junk on top of fish incomplete
impression
A significant advantage of CT fishing techniques is the
ability to circulated fluids while catching or retrieving the
fish. In this event, consideration must be given to the
fluids used and their compatibility with wellbore fluids and
the fill material).

• Fish material properties Fish lying on side

of wellbore
The material properties of the fish may have some bearing
on the fishing tools or technique selected. For example,
small ferrous objects may be retrieved by magnetic
devices.

Figure 10. Lead impression block interpretation.

Page 17 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

may determine the configuration of pressure control equip-

ment necessary to maintain the required number of barriers
to wellbore pressure and fluids.
Top connection/fishing
neck
The total length and OD of the recovered fish and toolstring
will determine the minimum length of riser or lubricator
which will be required.

When fishing wireline, suitable BOPs must be incorporated

into the surface equipment rig up to allow safe retrieval of
the fish.

2.1.2 Survey Tools Catch spring

A number of tools and devices have been designed to

assist in determining the fish type and orientation. Most of
these have been adapted from wireline applications, and
can now be run on CT or wireline. Lead impression blocks
are the simplest means of obtaining information on the
Catch and release
profile and orientation of the fish. However, the recovered
mechanism
impression is often confusing and requires some experi-
ence for correct interpretation (Figure 10).

In the right wellbore conditions, downhole cameras can

transmit images or video footage to surface equipment
through logging cable. Problems associated with these
techniques include ensuring a clean wellbore fluid, tem-
perature/time limitations and the high cost of service.

2.1.3 Primary Tools

Adjustable stop
The connector used on fishing operations must be strong
enough to withstand the anticipated forces exerted during Grapple
the job. Typically, roll-on connectors are not suitable for this Bowl
type of application.

To reduce the chance of tubing failure adjacent to the Figure 11. Typical overshot configuration.
connector, the CT should be cut back and the connector
replaced after each run on which jarring takes place.
2.1.4 Catch Tools
Tandem check valves should normally be incorporated in
the fishing toolstring. However, if it is desired to reverse The selection of an appropriate catch tool is dependent on
circulate fill material from the vicinity of the fish, the check the nature and profile of the fish, and its orientation in the
valves obviously should be omitted. wellbore. A wide variety of tools, in a range of sizes, are
manufactured by several vendors. To avoid the require-
NOTE: The required conditions stated in the Standards of ment for an extensive range to be kept in stock, many
Operation must be met before reverse circulation may take fishing tools are adapted or modified to suit the intended
place. application.

Page 18 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

All catch tools must have at least one means of disengag-

ing in the event that the fish remains fixed and cannot be
retrieved. Such release mechanisms may be actuated by
Top connection/ tubing set-down, over-tension or by a hydraulic system
fishing neck controlled by fluid pump rate/pressure in the workstring.

Fishing tool release mechanisms can be categorized as

single-shot or re-engagable. Single-shot tools can engage
and disengage the fish only once. After disengaging the
toolstring must be retrieved and redressed. Re-engagable
tools can be released and re-engaged multiple times.

NOTE: The facility of an internal release mechanism does

not preclude the use of a separate release joint to be
Catch and release operated in the event of release tool failure.
mechanism
Overshot

The overshot is designed to latch and grip on the outside

diameter of the fish (Figure 11). It is a popular option used
when sufficient clearance exists between the fish and
wellbore tubular or completion restrictions.
Catch spring
Spear

Spears are designed to latch and grip on the internal

diameter of a fish (Figure 12). They are favored in slim
completion applications since they do not effectively
increase the OD of the fish.

Adjustable stop Magnetic Tools

Grapple Magnetic fishing tools are used to retrieve small magnetic

Nose cone objects from the wellbore. They are available in a wide
variety of design and sizes and are commonly run on
wireline. Coiled tubing conveyance offers the advantage of
Figure 12. Typical spear configuration. circulation which can help remove fill material or create
turbulence. The creation of turbulence on bottom can be
important, since to be effective, the fish should actually
contact the magnet.

Most conventional CT toolstrings have restricted internal Improper handling and storage can significantly impair the
diameters and are typically fished by latching or gripping on strength of high-power fishing magnets. Shipping and
the OD surface. However, many release joints are designed storage details should be requested from the magnetic tool
to be retrieved by tools engaging on an internal profile manufacturer or supplier. Strong magnets of the type
fishing neck. This feature allows the release joint OD to be commonly used in fishing tools are subject to air freight
optimized, facilitating stronger designs while allowing the restrictions due to their effect on navigation equipment.
tool to pass through completion restrictions.

Page 19 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

Wireline Catcher

"Chinese Hat" used to Wireline can be fished using a variety of special retrieving
prevent wireline bunch- tools. The most common tools are fitted with barbs and
ing above the toolstring some means of balling the wire. On picking up, the wire is
caught by the barbs and retrieved to surface (Figure 13).

An important aspect of wireline fishing is ensuring that

operation of the pressure control equipment is not compro-
mised by retrieval of a large ball of wire. The distance
broken wire falls depends on the tubular diameter and the
wire size. However, it generally remains vertical at the
break and falls into a self-supporting helix within the tubular.

More complex designs of wireline catch tool do not require

the wire to be balled or packed in order to be caught. The
broken end of the wire is trapped between a bowl and slip
assembly as the tool is picked up.

2.1.5 Support Tools

Where tubing restrictions will allow,
an internal catcher helps bunch up
Support tools provide the fishing string with enhanced
the wireline to ensure an effective
capability for catching and retrieving the fish. They may not
catch
be required for all applications, however, they can be
considered as standard fishing equipment with appropriate
size tools being held at many CT service points.

Release Joint

A release joint provides a means of parting the CT toolstring

in a controlled manner in the event the toolstring becomes
stuck. The resulting fishing neck is designed to allow easy
reconnection with an appropriate fishing tool.

It is recommended that a release joint be incorporated in

any toolstring with an external upset, or OD, greater than
that of the connector/check valve assembly. In addition,
Spear-type wireline catchers can be any toolstring which latches onto objects, or engage in
used in smaller completions than the profiles, in the wellbore should be protected by a release
internal type shown above joint.

Release joint mechanisms may be activated by tension,

internal pressure or both. Pressure activated devices may
require a ball to be circulated into place to effect a release.
Care must be taken to ensure that the operation of the
release joint is compatible with the hydraulic functions of
the toolstring. In addition, any tools located above a ball
operated release joint must be drifted to an appropriate
Figure 13. Wireline catching tools. size.

Page 20 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

Jar NOTE: Accelerators must be matched to the performance

of the jar.
Jars are used to deliver an upward impact force intended to
free the fish. In some instances down jarring action is also Orientation and Locating Tools
used to operate the release mechanism of the catch tool.
Most jars operate in one direction only, however some One of the disadvantages of performing through-tubing
recently developed models are bi-directional. operations, is the restriction imposed on the size (OD) of
toolstring used. Since many operations are conducted in
The operating principle of jars commonly used in CT fishing the casing or liner below the tubing end, locating the fish
operations may be mechanical, hydraulic or fluid powered. with a “small tool” can be problematic, especially in highly
deviated or horizontal wellbores (Figure 14).
NOTE: Jars must always be used in conjunction with a
compatible accelerator. The available overpull at the fish A number of slickline tools have been adapted to assist in
should be determined using computer simulations to allow locating and engaging the fish:
the selection of an appropriate jar/accelerator assembly.
• Centralizer
Accelerator
A variety of centralizers in a range of sizes may be used
The primary function of the accelerator is to store the to assist locating and engaging a fish which is centralized
energy which is released when the jar fires. In addition, the in the wellbore. Springbow or spring arm centralizers are
toolstring and CT above the accelerator are protected from the most appropriate design for use in multiple ID appli-
shock loads while jarring. The operating principal of most cations. However, the additional friction caused by the
accelerators is mechanical. However, hydraulic accelera- centralizer may induce premature lock up in highly devi-
tors, often known as intensifiers, are also available. ated and horizontal wells.

Fishing tool becomes less effective in

larger diameter tubular

Fish tending to lie on the

lower side of the wellbore

Figure 14. Orientation and location.

Page 21 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

• Knuckle Joint • Fill removal

Pump-through knuckle joints designed for use on CT Fluid circulation for the removal of fill material, or debris,
operations are often required in deviated wells or crooked on and around the fish is one of the major advantages of
tubulars, or where gas-lift mandrels hinder the operation CT conveyed fishing techniques.
of the toolstring. In some applications, two knuckle joints
or a dual knuckle joint tool are required to ensure the • Jetting to assist centralization
necessary flexibility and alignment.
Side ported nozzles or subs can be used to centralize
• Orientation Tools toolstrings.

These are a relatively new development brought about by • Circulation power tools
the inability to rotate the CT workstring. They are an
example of a rapidly increasing range of speciality fishing Fluid powered jars, orientation devices and hydraulically
tools developed for CT conveyance. Operation of the activated catch/release tools require the circulation of
tools is typically controlled and powered by fluid pumped fluid or application of internal pressure in the workstring.
through the CT. Slow turning motors and indexing bent
subs are currently being developed and evaluated for this • Circulation to cool tools
type of application.
Circulation through hydraulic jars and intensifiers helps
2.1.6 Pumping Fluids dissipate some of the heat which can build up through
repeated jarring action. The efficiency and longevity of
In all CT operations the density and volume of all fluids the tools can thereby be improved.
pumped must be closely monitored and noted. Because the
workstring weight is a vitally important parameter while • Buoyancy
fishing, any actions which may effect the weight must be
closely monitored. Apparent changes in workstring weight The effects of buoyancy can be applied to increase the
are quickly evident when pumping fluids of differing den- tension applied at the toolstring. However, this technique
sity. Additionally, comparatively small volumes of fluid can should generally be used as a contingency measure.
induce changes which can be erroneously interpreted, so
compromising the efficiency of the job. 2.2 Execution

Fluids may be pumped for a number of reasons prior to, and The key to successful fishing operations is accurate
while performing, a CT fishing operation: information. There are many decisions and selections to be
made in the course of a fishing job, and almost all are based
• Well control/kill on the available information. In the event precise details are
not available (e.g. the exact nature of the fish) then
An early decision as to whether the well should be killed information in the form of previous experience and edu-
can significantly influence the selection of appropriate cated assumptions should be used.
tools and techniques. Therefore an attempt should be
made to evaluate the options associated with killing the Accurate monitoring and recording of key parameters (i.e.
well early in the job design process. weight, depth and pumped fluids) is essential during all
phases of the fishing operation. Also, accurate wellbore
• Conditioning wellbore and fishing diagrams must be maintained and updated as
the operation progresses.
For example freeze protection in cold weather applica-
tions.

Page 22 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

2.2.1 Execution Precautions Coiled Tubing Equipment

Execution precautions to be observed during CT fishing Depth and weight are critical parameters which must be
operations principally relate to the maintenance of ad- accurately monitored and recorded throughout the fishing
equate barriers against well pressure and fluids. In addition, operation. Monitoring and recording equipment must be
every effort should be made to avoid compounding the fully operational and operating within the calibration limits
problem which the fishing operation has been initiated to of error.
resolve.
Precise control of the injector head functions is required for
Personnel proper operation of downhole tools. Applying and releasing
tension in the workstring must be accomplished smoothly
All personnel involved in the design or execution of CT to avoid damaging downhole tools or surface equipment.
fishing operations must be familiar with requirements
detailed in the relevant Standards of Operation. Pressure Control Equipment

Some fishing applications require the co-ordination of All components pressure tested and function tested. In
slickline or wireline services to complete the operation. In addition, the ID and length of all equipment must be
this event, special care must be taken to ensure all physically measured and a diagram prepared showing
personnel involved are familiar with safety requirements configuration and lengths.
and are aware of the intended operation and procedures.
Downhole Equipment
Well Security
All tool service joints and tool joint connections must be
The control of well pressure and fluids must meet the torqued to an appropriate value. Thread locking compounds
requirements of relevant Standards of Operation. In addi- should be used where applicable.
tion the requirements of the operating company and appli-
cable regulatory authorities must be known. A complete and accurate fishing diagram must be prepared
for the toolstring. This diagram must also be updated as
Fishing operations frequently use long riser or lubricator required.
assemblies. While recovering the fish or toolstring, rela-
tively large volumes of gas may have to be depressurized Monitoring and Recording
and purged from the surface pressure control equipment.
Safety precautions associated with the release and purging Depth measuring equipment should be zeroed with the CT
of flammable and/or toxic gases must be observed. connector against the stripper. The toolstring length and
distance from wellhead reference point must then be used
Equipment to correct for actual depth. The weight indicator should be
zeroed when the toolstring has been made up and swab
All treating and monitoring equipment must be spotted and valve opened (i.e. zero weight indicator with wellhead
operated in accordance with the requirements of the rel- pressure applied).
evant Standards of Operation. In addition, equipment
certified for use in hazardous areas, must be operated and 2.2.3 Treatment Execution
maintained in accordance with the operating zone require-
ments (e.g. Zone II equipment). The steps required to successfully complete a fishing
operation will depend on the particular conditions encoun-
2.2.2 Equipment Requirements tered in each case. In the following section, the key points
in each phase of the fishing operation are outlined. When
The following equipment requirements are of significance preparing and documenting a treatment procedure, it is
during CT fishing operations and should receive special recommended that the key points be reviewed with appli-
attention.

Page 23 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

CT connecor/check valve

CT connector/check valve
Accelerator

Release joint
Weight bar

Jar
Accelerator

Release joint (release joints placed

below the accelerator/jar assembly
must be carefully selected)
Weight bar

Slow speed motor

Jar

Bent sub

Catch tool (overshot, spear, pulling

tool, etc.) Catch tool (overshot, spear, pulling
tool, etc.)

Figure 15. Basic fishing toolstring configuration. Figure 16. Fishing toolstring incorporating a fishing
motor and bent sub.

Page 24 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

CT workstring

CT connector/check valve
CT connector/check valve

Release joint

Accelerator

Accelerator

Weight bar

Weight bar

Jar

Jar

Release joint (release joints below

the accelerator/jar assembly must
be carefully selected)
Hydraulic releasing spear
(GS pulling tool, etc.)
Knuckle joint

Centralizer
Baited receptacle with internal
Catch tool (overshot, spear, fishing neck
pulling tool, etc.)

Fish

Figure 17. High-angle fishing assembly. Figure 18. Baited fish and fishing assembly.

Page 25 of 27
 Section 350
COILED TUBING SERVICES MANUAL
Rev A - 98 STIFFLINE

cable points being incorporated into the procedure as • Well kill

required.
A decision to kill the well prior to fishing operations
Typical fishing tool assemblies for a variety of conditions commencing, can simplify several aspects of the job.
are shown in Figure 15 through Figure 18. Many toolstring
options exist, though the final selection will typically be Locate and Identify the Fish
based on availability, operator preference or previous
experience. The operating method and sequence of each The benefits of knowing what, and where, the fish is prior
tool must be understood and a compatibility check made to to running in with the CT are obvious. If necessary, wireline
ensure the toolstring will operate as intended. This espe- conveyed techniques can provide information to allow
cially applies to catch-tool release mechanisms. selection of a suitable toolstring which can then be run to
an appropriate depth with minimal delay.
Wellbore Preparation
Procedures performed to locate and identify the fish may
Wellbore preparation procedures performed prior to CT include the following. Some of these operations may be run
fishing operations may include the following. in conjunction with wellbore preparation procedures out-
lined above.
• Some phases of the fishing operation may be completed
with the assistance of slickline or wireline services. It is • Drift run to the top of fish, depth is confirmed and if
essential that lubricator or riser connections are checked necessary the toolstring can include an impression block.
for compatibility before the operation begins. The presence of fill or debris on top of the fish can also
be detected at this time.
• Remove or secure the subsurface safety valve
• In the case of tools or equipment accidentally dropped into
This reduces the risk of sticking the toolstring and or the wellbore, consult the completion diagram to identify
damaging the safety valve. In addition, the consequences likely restrictions on which the fish may be held.
of accidental safety valve closure, with the workstring in
the wellbore, can be severe. To secure the subsurface • If a significant volume of fill material or debris is evident,
safety valve, it should be hydraulically isolated in the a detailed fill removal procedure should be prepared. The
open position and a protective sleeve installed. wellbore must be completely cleared of fill material before
attempting to release the fish.
• Placement of dummy gas lift mandrels
• Baiting the fish with a wireline conveyed bait tool can
As above, to reduce the risk of sticking and/or damage. provide a easily latched and released fishing neck for
subsequent CT fishing.
• Bullhead wellbore fluids
Catching the Fish
It may be desirable to pack the wellbore with fluid to
enable improved well control, (e.g. where a significant • Repeated attempts to catch or work loose a fish may
pressure differential across the fish exists). cause excessive fatigue on a localized portion of the CT
workstring. Close monitoring of the internal pressure and
• Slickline drift of wellbore tubulars the number of cycles made during each phase of the
operation is necessary. In the event a localized section
Performed to ensure free passage of the toolstring through of workstring is repeatedly worked, it may be necessary
completion restrictions or scale build up. to retrieve the toolstring and cut a length of tubing from the
end of the workstring. This will expose a new portion of
workstring to repeated cycling. The cycling parameters,
number of cycles and length of tubing to be cut must be
determined by the conditions encountered.

Page 26 of 27
 COILED TUBING SERVICES MANUAL Section 350
STIFFLINE Rev A - 98

• Some types of fish may require dressing to allow correct the return to production. In the event that a fish is not
operation of the fishing tool. For example, a tapered mill successfully removed in its entirety, an analysis of the
may be used to ease the entry of a spear into the fishing operation should be made to determine what actions or
neck. procedures could have been changed to yield improved
results. This should be documented as part of the job
• When using hydraulic jars, repeated jarring should be report, thus enabling subsequent operations to be designed
undertaken with some consideration for the heat build up with the benefit of previous knowledge.
which will ultimately effect the useful life of the tool.

Recovering the Fish

• The advantages or disadvantages of maintaining circula-

tion during recovery should be assessed.

• If the recovered fish is near fullbore in the production

tubing, the tendency to swab should be anticipated and
necessary precautions taken.

• In the event that complete recovery of the fish is not

achieved, the job close-out report should contain a
wellbore diagram showing details and locations of known
fish or debris.

2.2.4 Contingency Plans

Contingency plans should be prepared during the job design

process. As a minimum, details of actions to be taken
under the following scenarios should be prepared.

• The fish cannot be retrieved and remains stuck.

• The fish remains stuck and the catch-tool cannot be

released; the toolstring must be parted by operating the
release joint.

• The fish cannot be retrieved high/far enough into the

pressure control equipment to allow closure of the master
valve (or similar isolation device).

• In the event the fishing string becomes stuck and it is

necessary to cut the workstring, consideration should be
given to cutting the CT inside the production tubing to
allow easier retrieval.

2.3 Evaluation

Evaluating the success of a fishing operation would appear

to be straightforward. However, there are several possible
outcomes which may influence subsequent operations or

Page 27 of 27
This page left blank
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98

COILED TUBING LOGGING

Contents Page

Introduction .................................................................................................... 2
1 COILED TUBING LOGGING ........................................................................... 2
1.1 Design ................................................................................................. 2
1.1.1 Openhole Logging ................................................................................ 3
1.1.2 Cased Hole Logging ............................................................................ 5
1.1.3 Assisted Production ............................................................................ 6
1.1.4 Perforating ........................................................................................... 6
1.1.5 Gun selection ...................................................................................... 7
1.1.6 Perforation Characteristics .................................................................. 7
1.1.7 Firing Mechanism ................................................................................ 8
1.1.8 Special Applications ............................................................................ 8
1.1.9 Wellbore and Completion Geometry ..................................................... 8
1.1.10 CTL System ........................................................................................ 9
1.1.11 Logistical Constraints ........................................................................ 11
1.1.12 Tubing Forces Model ......................................................................... 13
1.2 Execution .......................................................................................... 13
1.2.1 Execution Precautions ...................................................................... 13
1.2.2 Equipment Requirements .................................................................. 14
1.2.3 Treatment Execution .......................................................................... 14
1.2.4 Wellbore Preparation ......................................................................... 14
1.2.5 Tool Assembly/Deployment ............................................................... 15
1.2.6 Data Acquisition ................................................................................ 15
1.2.7 Tool Retrieval/Reverse Deployment ................................................... 15
1.2.8 Assisted Production While Logging .................................................... 15
1.3 Evaluation ......................................................................................... 15

Page 1 of 15
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING LOGGING

Introduction • Continuous logging can be performed (up and down) with

a high degree of speed and depth control.
Coiled tubing logging (CTL) uses CT to convey logging tools
and return the data from them to the surface. A logging • Long toolstrings may be pushed through doglegs or
cable installed in the CT workstring is used to transmit obstructions which would prevent the passage of wireline
power and data to and from the logging tools. In most conveyed toolstrings.
applications, the surface connection is made to a standard
logging service unit (e.g. Schlumberger Maxis 500). • Fluids may be circulated through the CT workstring
Downhole connection of the logging toolstring to the CT and before, during or after the logging or perforating operation.
cable is achieved electrically and mechanically by using a
CT logging head (CTLH) or adapter (CTHA). • The CT pressure control equipment provides constant
well security for safe operation on live wells.
1 COILED TUBING LOGGING
• Production logging of high flow rate wells is possible with
There are four main categories of CTL service: a reduced risk of the toolstring being forced uphole.

• Openhole logging • The logging cable is protected within the CT workstring.

In addition, reliability is increased since side entry subs
Principally, a formulation evaluation service performed and wet connectors are not required.
before setting a casing or liner over the interval of interest.
• The CT fluid conduit and the power/data transmission
• Cased hole logging capability of the cable can be combined for specialized
applications (e.g. borehole seismic).
An evaluation service which confirms or identifies char-
acteristics of a reservoir or completion. • Bottomhole measurements may be made while perform-
ing treatments providing real-time data for enhanced job
• Perforating design and execution.

Provides a clean flow channel between the wellbore and CTL operations require the joint participation of two oilfield
the producing formation. services which have historically been quite separate and
unrelated. Considerable planning and preparation effort is
• Special applications required to ensure that CTL services can be completed in
a timely and efficient manner. Therefore, close co-ordina-
These include the following: tion with the logging company is a prerequisite.
- Downhole video camera.
- Subsidence monitoring. 1.1 Design
- Electromagnetic fishing tools.
Determining the logging tool requirements and engineering
While CT is principally regarded as a viable conveyance the data acquisition portion of the operation is the respon-
method in highly deviated wellbores, a number of CTL sibility of the logging engineer/ representative. The initial
features can benefit operations conducted in vertical steps for the design of a CTL operation requires thorough
wellbores. The advantages or benefits of CT conveyance investigation of the following points.
may vary for each application, but can generally be summa-
rized as follows: • Data or type of log required by the client

• Logging tools can be conveyed over long distances in The nature of the desired data or log determines the
highly deviated and horizontal wellbores. logging tool requirements.

Page 2 of 15
 COILED TUBING SERVICES MANUAL Section 360
COILED TUBING LOGGING Rev A - 98

• Toolstring characteristics • Dual induction

The toolstring characteristics and operating criteria deter- Measures formation resistivity.
mines the type of cable and requirements of associated
equipment. • Litho density

• Wellbore and completion geometry Measures porosity and identifies lithology.

The wellbore and completion geometry and characteris- • Compensated neutron

tics may also determine equipment requirements or
suitability. Measures porosity and identifies lithology, locates gas
and fluid contacts.
• CTL system
• Sonic measurement
Available CTL equipment and components can be se-
lected, based on the requirements determined above. Measures acoustic velocity for porosity and identifies
lithology.
• Logistical constraints
• Stratigraphic
The requirement for special deployment equipment may
be determined by location (e.g. wells on offshore produc- Identifies bed orientation, fracture location, hole direction
tion platforms frequently have sufficient space between and geometry.
the wellhead level and the injector head level to allow long
toolstrings to be run without the need of a deployment • Rock sampling
system).
Provides side wall cores.
• Computer modelling
• Fluid sampling
The ability of the selected toolstring/workstring combina-
tion to log the zone(s) of interest is checked by computer Retrieves fluid samples under reservoir conditions and
modelling. estimates permeability.

A summary of the typical data required is shown in Figure • Borehole seismic

1. This should be used as a checklist when preparing to
design or execute a CTL operation. Recovers seismic data.

1.1.1 Openhole Logging Two distinct types of application exist for openhole CTL:

Openhole logging is principally a formation evaluation • In highly deviated and horizontal wellbores where the
service performed before setting casing or liner over the toolstring can no longer be lowered into the well by gravity.
interval of interest. In most cases, several tools of different
function are assembled and run simultaneously. The most • Special applications in vertical wellbores.
common tools and their corresponding measurements are:
Deviated Wellbore Applications
• Gamma ray
In deviated wellbores, conventional openhole logging op-
Lithology identification and correlation. erations are performed by conveying the toolstring on
drillpipe. CT offers several advantages over this technique:

Page 3 of 15
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING LOGGING

CTL JOB DESIGN DATA

Tool String Characteristics

- OD and outer profile of toolstring (complete fishing diagram)
- Weight
- Temperature and pressure specifications of the tool

Wellbore and Completion Geometry

- Production casing/liner and tubing details, e.g. size, weight, grade, depth, etc.
- Nipples or restrictions, ID and location
- Deviation, kickoff points, build rates and azimuth bearings
- Perforation or production interval details, e.g. depth, interval, shot density, rat hole.
- Bottomhole pressure and temperature

CTL System
- CT string details, length, OD, wall thickness, taper and cycle history
- Cable type, size, temperature rating, measured condition of conductors and insulation
(electrical values of cable/insulation typically include the pressure bulkhead and collector)
- CTHA/CTLH length, OD and weight
- BOP/Deployment equipment ID and length

Logistical Constraints
- Weight of CT reel

Figure 1.

• Shorter trip times. Vertical Wellbore Applications

• Continuous logging can be performed (up and down) with When logging on cable, the cable stretch and toolstring drag
better speed and depth control. can, under certain conditions, combine to create a slight yo-
yo effect at the toolstring while logging (also referred to as
• The logging cable is protected within the CT. slip-stick motion). In normal operations this is generally of
minimal significance and has little effect on data interpre-
• The toolstring is less likely to be damaged by excessive tation. However, when using high resolution tools, or in
compressive forces which may be exerted when con- applications which require a high degree of depth control, it
veyed on drill pipe. can be an important consideration. The rigidity of the CT
workstring combined with the high control levels available
The distance that a toolstring may be pushed along a on modern CT units provides a reliable conveyance method
horizontal wellbore depends on several factors, such as the for such applications.
weight and corresponding friction of the toolstring in the
wellbore. Since the CT has a higher tensile strength than normal
logging cables, CTL is often used in applications which
Open tool suites are generally large (3-3/8 in. OD) and carry a high risk of stuck toolstrings. Also, the rigidity of the
heavy. This combined with the relatively high friction tubing can be used to push tools past minor wellbore
encountered in the open hole section can limit the reach restrictions.
which may be expected during openhole CTL operations. A
computer model (e.g. tubing forces software) must be run The ability to circulate fluid through the CT can be an
prior to commencing CTL operations in deviated or horizon- advantage in applications that require clean operating
tal wellbores. conditions.

Page 4 of 15
 COILED TUBING SERVICES MANUAL Section 360
COILED TUBING LOGGING Rev A - 98

1.1.2 Cased Hole Logging • Vertical well applications where a high degree of depth and
speed control is required.
Cased hole logging is principally an evaluation service
which confirms or identifies characteristics of the reservoir • Applications that exploit the ability to pump through the CT
or completion. The most common activities include produc- while simultaneously logging.
tion logging, cement evaluation and corrosion logging:
Deviated Wellbore Applications
• Production logging
The principal objective of production logging in horizontal
Measurement of temperature, pressure, density, flow wells is to determine the flow profile and productivity
velocity; may include fluid sampling, noise tool and intervals along the wellbore (i.e. what intervals or fractures
gravel-pack tool. are producing, what fluids are being produced and how
much is each interval producing). The resulting flow profile
• Reservoir monitoring is correlated with lateral variations in permeability, satura-
tion, etc., to detect production anomalies (e.g. crossflow).
Gamma ray spectroscopy and thermal decay time logs. By performing simultaneous pressure and rate transient
tests the well and reservoir parameters can be quantified.
• Corrosion monitoring
The information obtained from such an operation can then
Multi-finger caliper, borehole televiewer be used to design the workover or remedial treatment
required to obtain optimum production from the reservoir
• Cement evaluation interval or well.

Cement bond log, cement evaluation tool, ultrasonic The acquisition and interpretation of data from horizontal
imaging tool. wells can be complex and difficult. This is due primarily to
the behavior of wellbore fluids and the operation of logging
• Gyro compass tools in a horizontal wellbore profile. The challenge brought
by such conditions has resulted in the development of
Wellbore survey sensors, tool string combinations, operating techniques
and advanced interpretation skills specifically designed for
• Free point indicator horizontal applications.

Stuck point determination The type of completion also has some bearing on the
complexity of acquiring and interpreting the data. Three
• Downhole seismic array basic types of horizontal completion may be encountered
(Figure 2):
The majority of cased hole logging operations are con-
ducted on completed wells which are currently producing. • Barefoot completion
Therefore, the need exists for pressure control equipment
and associated operating procedures which can maintain This is the simplest type of completion. However, it is
the required level of well security. Standard CT pressure limited to strong formations capable of withstanding the
control equipment and procedures can fulfil these require- pressure drawdown exerted during production. Logging
ments. operations can be effected or restricted by rough walls,
washed out or eroded areas. Otherwise, logs often pro-
Cased hole CTL services are suited for several types of vide useful data since the flow is contained within the
applications: wellbore. However, the possible variation in wellbore
cross-sectional area can cause interpretation difficulties.
• Highly deviated and horizontal wellbores where the tool
string can no longer be lowered into the well by gravity.

Page 5 of 15
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING LOGGING

• Cemented liner 1.1.3 Assisted Production

Cemented liners provide the operator with a means of By conveying logging tools on a tube, simultaneous pump-
segmenting or selectively perforating (producing) the ing and logging operations are possible. Nitrogen may be
reservoir. Accurate quantifiable data can generally be used to initiate and maintain production while logging.
obtained over the perforated interval.
Historically, production logging of non-eruptive wells has
• Slotted liner not been possible because the pumping device must be
removed to allow passage of the logging tools. With the
Slotted liners cause the greatest difficulties in measure- pump removed, the well does not flow and production
ment and interpretation. Complications arise from part of logging is not possible.
the flow being on the outside of the liner. The presence of
void areas and an uneven formation face profile causes 1.1.4 Perforating
the flow to enter and leave the liner, resulting in unpredict-
able flow meter readings. The objective of most perforating operations is to provide
a clean flow channel between the wellbore and the produc-
Vertical Wellbore Applications ing formation. The perforating charge must penetrate the
casing or liner, the surrounding cement sheath and the
The strength, rigidity and ability to circulate through the CTL producing formation. This operation should be completed
workstring provides the same benefits to vertical cased with minimal damage to the formation around the perfora-
hole operations as those previously mentioned for vertical tion tunnel. Excessive damage to this critical area can
openhole applications. restrict the production capacity of the perforated interval.

Hazards associated with production logging in wellbores Using CT to convey perforating guns is an extension of
having high fluid velocities are reduced. The CT is capable established CTL services. The rigidity and strength of CT
of withstanding forces acting to push the toolstring up the can be used when perforating highly deviated and horizon-
wellbore, and in most cases, will be capable of safely tal intervals and when long and heavy gun assemblies are
running in and out of the wellbore while production contin-
ues.

Barefoot
completion

Cemented
liner

Slotted
liner

Figure 2. Flow profiles of various completion types.

Page 6 of 15
 COILED TUBING SERVICES MANUAL Section 360
COILED TUBING LOGGING Rev A - 98

deployed. In addition, the configuration of CT pressure anticipated OD of the gun system after firing must be
control equipment allows perforating to be easily and safely compatible with the minimum restriction in the wellbore.
performed on live or under balanced wells.
1.1.6 Perforation Characteristics
1.1.5 Gun selection
The productivity, and therefore effectiveness, of a perfo-
Several types of perforating guns are used in conventional rated interval depends greatly on the geometry of the
perforating operations. These may be broadly categorized perforations. There are several factors that determine the
by type of application. efficiency of flow through a perforated completion.

Casing guns • Penetration

These guns are larger (e.g. 3-3/8-in. to 7-in. OD) and are Perforations must extend beyond the zone surrounding
conventionally conveyed on wireline or tubing/drill pipe the wellbore which has been damaged by drilling mud and
(TCP). cement filtrate.

Through-tubing guns • Perforation clean up

The most common perforating guns used with CT are of the Perforations must be cleaned of charge and formation
through-tubing type, as this is the application for which CT- debris resulting from the perforating operation. This is
conveyed perforating is commonly used. Because of the best accomplished by perforating in underbalance condi-
size restrictions associated with through-tubing work, such tions to enable all perforations clean up immediately after
guns are generally 1-11/16-in. to 2-7/8-in. OD. firing.

An additional subdivision of through-tubing guns reflects • Shot density and phasing

the recoverability of the fired gun system.
The density of perforations, i.e. shots per foot (SPF),
Expendable guns must be carefully selected to avoid excessive pressure
drop at the perforation. This is largely determined by
Expendable guns (e.g. 45° phased Enerjet) should only be formation characteristics. For example, in layered forma-
used in applications where debris of large size and volume tions with relatively poor vertical permeability, a higher
can be tolerated. shot density will be required. Shot phasing is desirable to
optimize productivity and maintain casing or liner strength.
Semi-expendable guns
• Perforation diameter
Semi-expendable guns (e.g. 0° phased Enerjet) should only
be used in applications where moderate debris can be In most applications a perforation diameter of 3/8-in. is
tolerated. considered adequate to allow easy clean up and avoid
premature plugging with asphalt or scale. Completions
Retrievable guns which are to be gravel packed require evenly spaced
holes of around 3/4-in. to minimize the pressure drop
Retrievable guns, e.g. HyperDome/Scallop guns, are con- across the packed perforation tunnel.
tained within a rugged hollow carrier which confines the gun
debris after firing. In addition to providing better retrieval, The relative importance of each factor is dependent on the
the carrier also allows the guns to be used at higher type of completion, formation characteristics, and the
temperature and pressure. extent of formation damage caused by drilling and cement-
ing operations. Computer models have been developed to
Hollow gun carriers tend to swell as a result of the extreme predict the outcome of any perforation job, allowing the
pressures encountered during perforating. Therefore, the completion engineer to compare alternatives.

Page 7 of 15
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING LOGGING

1.1.7 Firing Mechanism water clarity sufficient to achieve the desired video
resolution. Displacement of wellbore fluids with nitrogen
Two means of firing the guns are applicable to CT-con- may provide an appropriate alternative in such cases.
veyed perforating. Electrical firing using a CTL string or
pressure activated firing initiated by applied internal pres- • Subsidence monitoring
sure in the CT string.
Formation subsidence and compaction monitoring appli-
Pressure firing systems may be used without the need for cations require extremely accurate depth measurement
a cable in the CT string, but suffer a significant disadvan- and precisely controlled tool movement. Satisfactory
tage in that correlation logging tools cannot be run to results have been obtained using CT as a conveyance
confirm the location of the guns. method.

The conventional electrical detonators used in wireline • Electromagnetic fishing tools

perforating operations are susceptible to detonation caused
by induced currents from stray voltage sources. Stray Special electromagnetic fishing tools may be an appropri-
voltage can originate from many sources, e.g., faulty ate choice in some applications, (e.g. the removal of
electrical equipment, welding equipment, cathodic protec- metallic debris from horizontal wellbores).
tion equipment and radio frequency (RF) transmission.
Therefore, adequate safety precautions must be taken to 1.1.9 Wellbore and Completion Geometry
eliminate such sources before perforating operations can
commence. Several factors relating to the wellbore or completion
geometry may influence the CTL operation.
The Slapper-Actuated Firing Equipment, or S.A.F.E. firing
system, is protected from the effects of stray voltage. • Tubular restrictions

1.1.8 Special Applications The free passage of toolstrings through completion re-
strictions is an obvious requirement which can be compli-
Coiled tubing logging provides a tool conveyance and data cated by deviated wellbores or the presence of debris. In
acquisition system for which there are a great number of addition, while logging flowing wells the forces which
potential applications. Research and engineering efforts result from passing the toolstring through a restriction
have overcome the majority of technical problems to may be severe.
provide a flexible and reliable service which can often be
adapted to provide the data required by the client. The • Dog-leg severity
principal governing factor in special applications for CTL
services is economic viability, (i.e. the cost of acquiring the Severe dog-legs may hinder or prevent the passage of the
data desired by the client). toolstring, however most toolstrings have some flexibil-
ity. Flex-joints can be incorporated into the toolstring to
The following applications can or have been performed allow greater flexibility but at the cost of a greater
using CT as a conveyance method. toolstring length.

• Downhole video camera • Deviation and lateral displacement

The development of downhole video cameras and sys- The ability to convey logging tools into a deviated wellbore,
tems allows visual inspection of wellbore conditions. is the principal advantage of CTL operations. The forces
When conveyed on wireline, such video systems are involved are modelled using a tubing forces model to
restricted to gas or clear fluid filled wellbores. However, allow a prediction of the depth, or lateral displacement
the ability to circulate and spot clear fluids through the achievable in given wellbore conditions.
CTL reel, can allow visual inspection of the wellbore. In
some cases it may be difficult to maintain a downhole

Page 8 of 15
 COILED TUBING SERVICES MANUAL Section 360
COILED TUBING LOGGING Rev A - 98

1.1.10 CTL System utilization of high-cost CTL reels, heptacables are gener-
ally the preferred choice.
The CTL system components and points of special signifi-
cance are illustrated in Figure 3. They may be categorized In wireline conveyed applications, openhole logging tools
as follows: are generally conveyed on heptacable. Production log-
ging tools, and the majority of cased hole logging tools
• Power/data transmission which are used in conjunction with pressure control
equipment, are conveyed on monocable. Coaxial cables
• Depth measurement have a higher data transmission rate than monocables
and are also typically used in cased hole logging applica-
• Pressure control equipment tions.

Power/Data Transmission The electrical requirements of the toolstring, or tool suite,

obviously must be compatible with the capabilities of the
In addition to the logging cable there are a number of CTL reel. The table in Figure 5 provides a guide of tool/
components which are vital to the electrical reliability of the cable compatibility. The ultimate qualification of a CTL
CTL system (Figure 4): cable/reel assembly must be determined by a logging
company representative, following review of the cable
• Downhole connection specifications and the measured resistance and insula-
tion values.
Logging tools are mechanically and electrically con-
nected to the CT and cable by a CT head adapter (CTHA), Depth and Weight Measurement
CT logging head (CTLH) or CT modular head (CTMH).
On of the most important measurements made during any
• Deployment bar logging operation is depth. Accurate depth measurements
are required to plot data acquired from the toolstring and to
The deployment bar provides a means of suspending the allow correlation of logs with proposed treatment zones. On
logging toolstring in the BOP and isolating wellbore CTL operations, the output of depth encoders mounted on
pressure during deployment and reverse deployment. the CT injector head is connected to the CT unit control
cabin and to the logging unit acquisition system. In most
• Surface pressure bulkhead cases, the depth signal is processed or converted to be
compatible with logging computer input requirements.
The pressure bulkhead (PBH) is used to allow electrical
connections to be made with the logging cable inside the Accurate weight indicator information is essential during
CT while maintaining the pressure integrity of the reel. CTL operations for several reasons:

• Reel collector • In deviated wellbores, a weight/depth plot from a computer

simulation must be available to enable a comparison of
The reel collector is used to allow electrical connection predicted tubing behavior vs. actual.
between the rotating reel drum and the surface electrical
equipment. • Many of the slimhole logging tools cannot withstand the
forces which can potentially be applied by the CT string.
• Cable
• The toolstring contains a specified weak point; acciden-
There are three distinct cable types commonly used in tally exceeding this value will result in loss of the
normal wireline conveyed logging operations, heptacable, toolstring and a Major Operating Failure.
monocable and coaxial cable. Each type of cable has, at
one time, been installed in a CTL reel. However, to
increase the flexibility of use and ensure maximum

Page 9 of 15
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING LOGGING

Depth
measurement CTL reel

Depth
measurement

Pressure control
equipment
o s o f
L
a y
L e r 1 H ig h E h
x a u
s t o w O il
L
H ig
h C o o la
n t

o o la n
C t O il

n g in e
E

e m p re ta u
T e
P
r rm
e i s iv T
m p e ra tu re
e P re s u e
r Co o
l n
a t

S t ra t

E me g
r e
n c y Eg
n in e Ai r

e mp
T e a
r tu e
r P re s u
s e
r

c h m
a
T o e te r

s ta rt

i l
K K il
P re s u e
r

Power/data

MaXis 500

Deployment bar (pressure Logging tool string

control equipment) and
downhole tool connection

Figure 3. Principal components of a CTL system.

Page 10 of 15
 COILED TUBING SERVICES MANUAL Section 360
COILED TUBING LOGGING Rev A - 98

Surface computer

Surface
Reel collector
Equipment

Surface pressure bulkhead Cable/CTL string

Deployment bar
Downhole
Equipment
CTHA, CTLH or CTMH

Logging tools

Figure 4. Principal electrical components of a CTL system.

Pressure Control Equipment • In the process of deployment or reverse deployment it is

necessary to bleed, purge and equalize pressure in the
The configuration of pressure control equipment required pressure control equipment.
on CTL operations is dependent on the location (offshore/
onshore), complexity of the job (toolstring length) and the As in all CT operations, the OD of the toolstring and the ID
requirements of the operator and local or national authori- of the pressure control equipment must be measured and
ties. checked.

In addition to the pressure control equipment and proce- During normal operation and rig up/down, only the CTU
dures associated with “normal CT operations” there are a operator/engineer or his designate may operate the pres-
number of factors which must be considered when perform- sure control equipment.
ing any operation with a long toolstring or with cable
installed in the CT: 1.1.11 Logistical Constraints

• A dual barrier against wellbore pressure and fluids must Coiled tubing logging commonly uses long toolstrings,
be maintained during rig up/down as well as during the which may be difficult to handle. The toolstring length
operation. determines the amount of riser or lubricator required to run
or deploy the tools. This in turn determines the capacity of
• Any cutting or shear/seal devices must be capable of the crane(height) that is required. On many large offshore
cleanly severing the CT and cable. production platforms, there is sufficient space between the
wellhead and the working level to allow the toolstring to be
• When pressure deploying toolstrings, it is necessary to safely assembled and run without the need for special
handle heavy equipment above the wellhead and pres- equipment. However, on smaller offshore platforms and
sure control equipment. Extreme care and control must onshore wells, it is often necessary to pressure deploy the
be exercised to avoid injury to personnel or damage to toolstring.
equipment.
Deployment equipment and procedures allow long toolstrings
to run without the need for the injector head to be rigged at
an excessive height.

Page 11 of 15
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING LOGGING

LOGGING TOOL/CABLE COMPATIBILITY GUIDE

Tool Heptacable Monocable Coaxial Cable

Evaluation Services

LDT Litho Density Tool X - -

CNT Compensated Neutron Tool X - -
GR Gamma Ray X - -
EPT Electromagnetic Propagation Tool X - -

DI Dual Induction Tool X - -

TCC Telemetry Cartridge X - -
SDT Sonic Digital Tool X - -
RFT Repeat Formation Tester X - -
FMS Formation Microscanner X - -

CET Cement Evaluation Tool X - -

CBL Cement Bond Log X - -
SAT Seismic Acquisition Tool X - -
DSA Downhole Seismic Array X - -

Perforating Guns X X X

Production Logging Services

CCL Casing Collar Locator X X X

GR Gamma Ray X X X
PTS Pressure, Temperature and Density X X X
HMS HP Crystal Pressure Guage X X X

FBS Full Bore Spinner X X X

CFS Continuous Flowmeter X X X
NFD Nuclear Fluid Density X X X
HUM Hold-up Meter X X X

TCS Calliper X X X1
TDT Thermal Decay Time Tool X X2 X2
CNT Compensated Neutron Tool X X2 X2
RST Reservoir Saturation Tool X X X
GST Gamma Ray Spectroscopy Tool X X X

1
The only calliper that can be run on coaxial cable.
2
When TDT and CPLT are run in combination coaxial cable is required.

Figure 5. Logging cable/tool compatibility guide.

Page 12 of 15
 COILED TUBING SERVICES MANUAL Section 360
COILED TUBING LOGGING Rev A - 98

The advantages of using a deployment system are: Principally for this reason, it is essential that clear and
precise procedures are prepared for the entire logging
• Wellhead pressure is controlled by dual barriers during rig operation. This should include details of normal, contin-
up and throughout the operation. gency and emergency operating procedures. In addition to
being prepared and reviewed during the job design process,
• Equipment operators are not required to work under the job procedure and associated safety requirements
suspended loads while rigging up (or rigging down). must be discussed during the pre-job safety meeting.

• The pressure control equipment and injector head is more 1.2.1 Execution Precautions
stable and less likely to expose the wellhead to damaging
loads or forces. Execution precautions to be observed during CTL opera-
tions principally relate to the safe handling and operation of
1.1.12 Tubing Forces Software pressure control and deployment equipment.

Tubing forces software model calculates the forces and It is the responsibility of the logging company representa-
resulting stresses applied to the CT as it is run into and out tive to communicate safety precautions relating to the
of the wellbore. This model is used in the design of every storage, handling or use of explosives and radioactive
CTL job to determine the predicted limits of operation: materials. Subsequently, it is the responsibility of all
personnel to ensure that such safety precautions are
• How far the tools can be pushed into the highly deviated implemented.
or horizontal section of the well.
Personnel
• What the weight indicator reading should display during
these operations. All personnel involved in the design or execution of CTL or
CT services must be familiar with requirements detailed in
• What the maximum stress will be in the CT during these the relevant Standards of Operation.
operations.
All personnel must comply with the safety requirements of
Tools which measure the compression or tension applied to the logging company representative.
the tool string may be used on logging operations. These
tools provide a means of monitoring the progress of the tool Well Security
string through the wellbore.
The control of well pressure and fluids must meet the
The maximum possible depth of penetration is reached requirements of the relevant Standards of Operation. In
when CT lock-up occurs. At this point, further injection of addition, the requirements of the operating company and
tubing will only result in increasing the buckling of CT in the applicable regulatory authorities must be known.
wellbore. This may be observed on the CT weight indicator
display as a rapid loss of weight. The conditions for operation of emergency shear/seal
equipment must be detailed in the job design procedures
1.2 Execution and at the pre-job safety meeting. During normal operations
(i.e. not an emergency requiring immediate action) only the
The successful execution of CTL services requires the CTU operator/engineer or his designate may operate pres-
participation of two distinct business lines (or companies). sure control equipment.
The potential hazards associated with operations con-
ducted on live wells demands that personnel maintain a The conditions under which the well may be flowed while the
high degree of awareness and that good communication CT is in the wellbore must be understood and communi-
exists between all parties involved. cated to production operators or representatives.

Page 13 of 15
 Section 360
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING LOGGING

CTL operations frequently employ long riser or lubricator A complete and accurate fishing diagram must be prepared
assemblies. While recovering the toolstring, relatively large for the toolstring.
volumes of gas may have to be depressurized and purged
from the surface pressure control equipment. Safety pre- Monitoring and Recording
cautions associated with the release and purging of flam-
mable and/or toxic gases must be observed. Depth measuring equipment should normally be zeroed
with the CT connector against the stripper. The toolstring
Equipment length and distance from wellhead reference point must
then be used to correct for actual depth.
All treating and monitoring equipment must be spotted and
operated in accordance with the requirements of the rel- During CTL operations, the depth may be corrected to
evant Standards of Operation. In addition, equipment correlate with previous logs or wellbore markers. Careful
certified for use in hazardous areas, must be operated and recording of a depth correction is essential. In addition, the
maintained in accordance with the operating zone require- depth counters in both operator control stations (logging
ments (e.g. Zone II equipment). and CT control cabins) must be synchronized.

1.2.2 Equipment Requirements The weight indicator should be zeroed when the toolstring
has been made up and swab valve opened (i.e. zero weight
The following equipment requirements are of significance indicator with wellhead pressure applied).
during CTL operations and should receive special attention.
1.2.3 Treatment Execution
Coiled Tubing Equipment
The steps required to successfully complete a CTL opera-
Depth and weight are critical parameters which must be tion will depend on the particular conditions encountered in
accurately monitored and recorded throughout the CTL each case. In the following section, the key points in each
operation. Monitoring and recording equipment must be phase of a CTL operation are outlined. When preparing and
fully operational and operating within the calibration limits documenting a treatment procedure, it is recommended
of error. that the key points be reviewed with applicable points being
incorporated into the procedure as required.
Precise control of the injector head speed during logging is
often required. In addition, a high degree of control is 1.2.4 Wellbore Preparation
required for safe operation of deployment systems. Injector
head drive and control systems must be capable of reliable Wellbore preparation procedures performed prior to CTL
operation under such conditions. operations may include the following.

Pressure Control Equipment • Some phases of the fishing operation may be completed
with the assistance of slickline or wireline services. It is
All components must be pressure tested and function essential that lubricator or riser connections are checked
tested. In addition, the ID and length of all equipment must for compatibility before the operation begins.
be physically measured and a diagram prepared showing
configuration and lengths. • Remove or secure the subsurface safety valve - this
reduces the risk of sticking the toolstring and or damaging
Downhole Equipment the safety valve. In addition, the consequences of acci-
dental safety valve closure, with the workstring in the
All tool service joints and tool joint connections must be wellbore, can be severe.
torqued to an appropriate value. Thread locking compounds
should be used where applicable. • Slickline drift of wellbore tubulars - performed to ensure
free passage of the toolstring through completion restric-
tions or check for scale build up.

Page 14 of 15
 COILED TUBING SERVICES MANUAL Section 360
COILED TUBING LOGGING Rev A - 98

1.2.5 Tool Assembly/Deployment 1.3 Evaluation

The tool assembly and deployment procedures will be The evaluation of CTL services is based on the successful
completed jointly with the logging company personnel. A acquisition of the desired downhole data. The involvement
detailed procedure should be prepared and communicated of more than one organization in acquiring this data requires
to all parties concerned to ensure safe and efficient rig up close co-operation and a mutual understanding of CTL
and down. operations and limitations.

1.2.6 Data Acquisition

The operating parameters of the CTU while the toolstring is

downhole will largely be dictated by the tool or logging
procedure requirements. However, the anticipated proce-
dures and workstring movements should be detailed to
confirm compatibility with the CTU and workstring operat-
ing practices.

The implications of repeated cycling of the CTL workstring

should be known by all personnel to avoid localized fatigue
of the tubing.

1.2.7 Tool Retrieval/Reverse Deployment

Tool retrieval and reverse deployment procedures must be

prepared and should include details of depressurizing and
purging lubricators or risers.

1.2.8 Assisted Production While Logging

CTL may be used in non-eruptive wells in a variety of

conditions. In common with wireline conveyed techniques,
wells produced with the assistance of a gas lift completions
can be successfully logged; providing the toolstring can be
safely conveyed past the gas lift mandrels.

Wells which are produced by surface or downhole pumps

may be logged under certain conditions:

• Wells containing electric submersible pumps (ESP) can

be logged if the necessary completion equipment has
been run, e.g. Phoenix Y connector

• With the downhole equipment removed, rod-pumped wells

(or ESP wells) can be logged.

Page 15 of 15
This page left blank
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98

COILED TUBING COMPLETIONS

Contents Page

Introduction .................................................................................................... 2
1 COILED TUBING COMPLETIONS ................................................................ 2
1.1 CT Completions History/Evolution ....................................................... 2
1.2 CT Completion Benefits ...................................................................... 3
1.3 Types of CT Completion ...................................................................... 3
1.3.1 Velocity String Installations ................................................................. 4
1.3.2 Externally Upset Completions ............................................................. 4
1.3.3 SPOOLABLE™ Completions .............................................................. 5
1.4 Completion Applications ...................................................................... 5
1.4.1 Artificial Lift Completions .................................................................... 5
1.4.2 Remedial Completions ......................................................................... 5
1.4.3 Completion of CTD Wellbores .............................................................. 5
1.4.4 Candidate Wells................................................................................... 6
1.4.5 Constraints of Coiled Tubing Completions ............................................ 6
1.5 Completion Components ..................................................................... 6
1.5.1 Coiled Tubing Connectors .................................................................... 6
1.5.2 Connector – Externally Upset .............................................................. 8
1.5.3 External Connector – With Packing ...................................................... 9
1.5.4 Internal Connector – Spoolable .......................................................... 10
1.5.5 Gas Lift Valves and Mandrels ............................................................ 11
1.5.6 Gas Lift Valve – Externally Upset ...................................................... 11
1.5.7 Gas Lift Valves – Spoolable ............................................................... 12
1.5.8 CTS–TRSP Safety Valve ................................................................... 13
1.5.9 Surface Equipment Rig-Up (External Upset) ...................................... 14

Page 1 of 14
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING COMPLETIONS

Introduction 1 COILED TUBING COMPLETIONS

The development of larger OD (>2 in.) coiled tubing (CT) The definition of coiled tubing completions may be stated
has increased the utility of CT as a completion conduit. This as:
combined with the inherent advantages of live well opera-
tions permitted by CT equipment, has further increased Completions which utilize coiled tubing as a wellbore
interest and development efforts. tubular, or as a means of conveying and installing
completion equipment or tools.
The economic advantages offered by completions which
may be run and retrieved without the requirement for a rig 1.1 CT Completions History/Evolution
led CAMCO to a three year development and testing
program. The culmination of this program is a CT comple- In addition to innovative CT completion technology, there
tion system which is not only viable–but provides an exists a significant role for CT in completions which are
attractive alternative to conventional jointed tubular comple- adapted from, and use, conventional technology. An over-
tions. view of the history and evolution of coiled tubing comple-
tions is shown in Fig. 1.

HISTORY/EVOLUTION OF COILED TUBING COMPLETIONS

1969 Coiled tubing used as a workstring

1970 1-in. CT introduced
1978 1-1/4-in. CT introduced
1982 CT production installations (Canada)
1986 1-1/2-in. CT introduced
1986 CT hanger (Wellhead Spool) developed
1988 1-3/4-in. introduced, CT installed for gas and inhibitor injection,
CT production packer introduced
1989 2-in. CT introduced, Continuous strings (bias weld)
1989 Camco patent filed
1990 2-in. CT installed as production string
1990 2-3/8 and 2-7/8-in. CT introduced
1992 3-1/2 in. CT introduced
1992 ESP installed on coiled tubing
1993 SPOOLABLE™ completions introduced
1994 ESP on CT with internal cable
1995 4-1/2 in. CT introduced

Figure 1. History and evolution of coiled tubing completions.

Page 2 of 14
 COILED TUBING SERVICES MANUAL Section 370
COILED TUBING COMPLETIONS Rev A - 98

1.2 CT Completion Benefits There is an increasing awareness of reservoir damage

and its implications. It is generally accepted that preven-
Time and cost reduction are the principle benefits which are tion is easier and generally economically better than any
driving CT completion development. However, some CT attempt to cure.
completion applications offer the flexibility to increase, or
sustain production (velocity strings). This combined with 1.3 Types of CT Completion
the elimination of the costs and potential reservoir damage
associated with killing the well, ensures the attractiveness There are three main categories of coiled tubing comple-
of many CT options. tion.

• Time reduction • Velocity string installations

Rapid mobilization, installation and retrieval–one day in • Externally upset CT completion

and one day out are the goals of many CT completions.
In addition to the rapid deployment of the initial comple- • SPOOLABLE CT completions
tion string, the duration of future workovers will also be
reduced. In the earliest completion applications, coiled tubing was
installed in existing production tubing as siphon or velocity
• Cost reduction strings. This concept later expanded to include gas lift
applications with, in its simplest from, the coiled tubing
The cost of most completion activities is generally providing a single point gas injection system.
directly related to the time required. In difficult or hostile
environments there are additional cost factors which The efficiency of such gas lift applications is low which led
must also be considered, e.g., equipment and rigs suit- to the development of a gas lift system which utilized
able for arctic operations is extremely expensive. The existing gas lift technology and equipment adapted for
ability to run a completion string without the requirement coiled tubing completions. This has been refined to the
for a specialized workover or service rig provides signifi- reliable external upset coiled tubing completion detailed
cant economic benefits. below.

In many wellsites, the drilling rig or derrick has been A logical development of this technology marriage was to
removed, e.g., offshore. The cost of providing a tempo- design and build a completion string with components
rary drilling or workover rig may not be a viable option for which could be passed through the coiled tubing and
conventional jointed completion types. pressure control equipment. As a result SPOOLABLE
coiled tubing completions and accessories have been
Live well intervention dispenses with the need for poten- designed.
tially significant well kill procedures. Similarly, well kick-
off procedures and equipment are not required. Coiled tubing completions are best suited to applications
which allow operators to take the maximum advantage of
• Reduced risk of reservoir damage the inherent benefits CT can provide.

Many reservoirs, particularly reservoirs which are de- Note: Spoolable is a trademark of CAMCO
pleted, are extremely intolerant of kill fluids. Severe
formation damage may result from any attempt to workover
or recomplete the well. In such applications, the ability to
run a coiled tubing completion without killing the well may
be an attractive option.

Page 3 of 14
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING COMPLETIONS

1.3.1 Velocity String Installations 1.3.2 Externally Upset Completions

• Predominantly gas well application • Cannot be run through injector-head chains or conven-
tional pressure control equipment (Figure 3).
• Improve wellbore hydraulics
• Completion must be assembled on location
• Significant and sustained production
increases from marginal wells • Standard completion components

• Pump out plug or check allows live well • Requires special installation equipment
installation (Figure 2.) – Access window
– Annular BOP

Original production Safety valve control line

tubing
Safety valve

Coiled tubing

Gas lift mandrels and

valves as determined by
completion design
Production packer

Production packer or seal

Pump-out check valve assembly
or plug

Figure 2. Velocity string installation. Figure 3. Externally upset completion.

Page 4 of 14
 COILED TUBING SERVICES MANUAL Section 370
COILED TUBING COMPLETIONS Rev A - 98

1.3.3 SPOOLABLE™ Completions 1.4 Completion Applications

• Can be run and retrieved through conventional CT pres- Types of Coiled Completion
sure control equipment (Figure 4)
• Primary completions
• Can be assembled in controlled conditions away from the
wellsite • Artificial lift completions

• Designed for live well installation using standard CT • Remedial completions

equipment
• Special service completions

• CTD completions

1.4.1 Artificial Lift Completions

• Gas lift
– Externally upset
SPOOLABLE safety valve – SPOOLABLE™
(internal control line)
• Electric submersible pumps
Existing safety valve – External cable
– Internal cable

1.4.2 Remedial Completions

SPOOLABLE gas lift valve

• Velocity string

• Sand control

• Tubing/casing repair
Production packer
• Concentric injection string

1.4.3 Completion of CTD Wellbores

• Well deepening
Production packer or
• Sidetrack
seal assembly
• Multiple drainholes

CTD Completion Characteristics

• Small-diameter wellbore

• Operations performed thru-tubing

Figure 4. SPOOLABLE completion. • Live well operations

Page 5 of 14
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING COMPLETIONS

• Deviated wellbore 1.4.5 Constraints of Coiled Tubing Completions

• Multiple wellbores • Increased Xmas tree height

• Moderate to severe dog-legs • Weight and handling (especially offshore)

• Depleted reservoir • Completion-bore obstructed by components

• Unstable formations • Components not generally suitable for “sand” service

1.4.4 Candidate Wells • Coiled tubing material equivalent to L-80 or N-80 API
grade materials
Completion/Recompletion Applications
1.5 Completion Components
• Initial installations
– Slimhole completions • Production string(s)
– Under economic justification
• Connectors
• Improving production hydraulics
– Velocity string • Gas lift valves
– Reduce the required gas injection rate
– Installing gas lift in depleted reservoirs • Packers

Remedial Applications • Nipples and landing profiles

• Remedial installations • Flow control devices

– Thru-tubing gravel pack
– Casing/tubing repair and zonal isolation • Circulation devices
– Re-instate safety valve function
• Pumps
• Difficult pulling jobs
– Dual completions • Installation equipment
– Failed gravel packs
– Collapsed casing 1.5.1 Coiled Tubing Connectors

Reservoir and Economic • External Connector

• Special kill fluid requirements • Single O-ring

– Heavy (and costly) kill fluid required
– High risk of formation damage • Dual O-ring

• Economic • Packing element seal

– Marginal wells where rig costs cannot be justified
– Applications or locations requiring special rig • Internal Spoolable™ connector
configuration
The tensile strength of CT connectors is equal to or greater
than that of the coiled tubing.

Figure 5 shows dimensions for CT connectors.

Page 6 of 14
 COILED TUBING SERVICES MANUAL Section 370
COILED TUBING COMPLETIONS Rev A - 98

CT Size Grapple Connector Dimple Connector Roll-On Connector

(in.) OD ID OD ID OD ID
(in.) (in.) (in.) (in.) (in.) (in.)

1-1/4 1.705 0.937 1.750 0.750 1.250 0.625

1-1/2 2.120 1.250 2.000 1.060 1.500 0.625

1-3/4 2.250 1.125 2.250 1.125 1.750 1.000

2 2.500 1.250 2.500 1.250 2.000 1.125

2-3/8 2.750 1.750 N/A N/A N/A N/A

2-7/8 3.250 1.750 N/A N/A N/A N/A

3-1/2 4.250 2.250 N/A N/A N/A N/A

Figure 5. Typical CT connector dimensions.

Page 7 of 14
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING COMPLETIONS

1.5.2 Connector – Externally Upset

• Compact design

• Simple assembly

• High strength

• Utility applications

• O-ring seal suitable for applications with minimal tubing

OD deformation (Fig. 6)

Slip housing

Slip lock

Dual O-ring

Connector body

Tool joint cut as

required

Figure 6. External connector – dual O-ring.

Page 8 of 14
 COILED TUBING SERVICES MANUAL Section 370
COILED TUBING COMPLETIONS Rev A - 98

1.5.3 External Connector – With Packing

• Energized seal separate from slip mechanism

• Sealing arrangement tolerant of ovality and deformation

• Mechanism compensates for thermal expansion and

contraction (Fig. 7)

Slip housing

Threaded ring

Belleville washers

Packing arrangement

Body

Figure 7. External connector – packing element seal.

Page 9 of 14
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING COMPLETIONS

1.5.4 Internal Connector – Spoolable

• Alternative to welding when assembling completion strings

(Fig. 8)

• Can be passed through pressure control equipment and

spooled

• Slip grip increases with tension

Slip lock

Dual O-ring seals

Body

Figure 8. SPOOLABLE connector.

Page 10 of 14
 COILED TUBING SERVICES MANUAL Section 370
COILED TUBING COMPLETIONS Rev A - 98

1.5.5 Gas Lift Valves and Mandrels 1.5.6 Gas Lift Valve – Externally Upset

• External upset mandrels • Conventional gas lift equipment – proven design

– Sidepocket • Serviced by conventional slickline tools and techniques

– KBMG or KBMM mandrels (4.50-in. min ID)
• Slimhole and sidepocket mandrels (Fig. 9)
– Slimhole
– CT-40 or CT-50 mandrels (under 4.50 in. ID)

– Internal Spoolable™ mandrels and valves

Orienting sleeve

Discriminator

Offset valve housing

Tool joints compatible with

external connector threads

Figure 9. External gas lift mandrel.

Page 11 of 14
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING COMPLETIONS

1.5.7 Gas Lift Valves – Spoolable – CTS-I

Injection pressure operated, tubing production
• Production through CT or annulus
– CTS-IA
• Mandrel welded or jointed by SPOOLABLE™ connectors Injection pressure operated, annular production

• Applicable for 1-1/2 to 3-1/2-in. CT (Fig. 10) – CTS-F

Fluid pressure operated, tubing production
• Four production modes:
– CTS-FA
Fluid pressure operated, annular production

GLM
Tail plug

Bellows assembly

A A
Gas lift valve

Nose piece

Figure 10. SPOOLABLE™ gas lift mandrel.

Page 12 of 14
 COILED TUBING SERVICES MANUAL Section 370
COILED TUBING COMPLETIONS Rev A - 98

1.5.8 CTS–TRSP Safety Valve

• 2-3/8-in. OD (3-1/2-in. tubing)

• 1.467 in2 flow area

• Control line inside CT

• 5000 psi working pressure

• Curved flapper

• Verification tested (Fig. 11)

– Class 1 API 14A

Power spring

Hydraulic mechanism

A A

Recessed flapper valve

Figure 11. SPOOLABLE safety valve.

Page 13 of 14
 Section 370
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING COMPLETIONS

1.5.9 Surface Equipment Rig-Up (External Upset)

• Access window provides a work area for coupling the

completion components (Fig. 12)

• Annular preventer provides a well control barrier capable

of sealing on varying diameter tubulars

Injector head

Reel

Work window

Slip bowl

Annular BOP

Coiled tubing BOP

Gate valve

Coiled tubing hanger

Casing hanger

Figure 12. Surface equipment rig-up.

Page 14 of 14
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98

COILED TUBING DRILLING

Contents Page
1 EVOLUTION OF COILED TUBING DRILLING ............................................... 3
1.1 Advantages of CTD ............................................................................ 3
1.1.1 Safety ................................................................................................. 3
1.1.2 Economic ............................................................................................ 3
1.1.3 Operational .......................................................................................... 3
1.1.4 Environmental ..................................................................................... 3
1.1.5 Limitations and Disadvantages ............................................................ 3
1.2 CTD Applications ................................................................................ 4
2 JOB DESIGN AND PREPARATION ................................................................ 4
2.1 Establishing Objectives ....................................................................... 4
2.2 Technical Feasibility ............................................................................ 5
2.2.1 Weight On Bit ...................................................................................... 5
2.2.2 Annular Velocity ................................................................................. 11
2.2.3 Pump Pressure and Rate .................................................................. 11
2.2.4 CT String Tension .............................................................................. 14
2.2.5 Torque ............................................................................................... 14
2.2.6 CT Life and Fatigue ........................................................................... 14
2.2.7 CT Reel Handling .............................................................................. 14
2.2.8 Directional Requirements ................................................................... 16
2.3 CTD Project Preparation .................................................................... 16
2.3.1 Technical Preparation ........................................................................ 16
2.3.2 Basic Equipment and Services.......................................................... 16
2.3.3 Procedures and Plans ....................................................................... 16
2.3.4 Drawings and Schematic Diagrams ................................................... 17
2.3.5 Personnel .......................................................................................... 17
2.3.6 Administrative Preparation ................................................................ 17
3 EXECUTION ................................................................................................ 18
3.1 Well Control (Overbalanced Drilling)................................................... 18
3.2 Conventional Sidetracking ................................................................. 18
3.2.1 Well Preparation ................................................................................ 18
3.2.2 Setting the Whipstock ....................................................................... 19
3.2.3 Window Milling .................................................................................. 20
3.3 Thru-Tubing Re-entry ......................................................................... 20
3.3.1 Well Preparation ................................................................................ 21
3.3.2 Whipstock in Production Tubing ......................................................... 21
3.3.3 Thru-tubing Whipstock ....................................................................... 21
3.3.4 Cement Kick-off Techniques .............................................................. 21
3.4 Underbalanced Drilling ....................................................................... 22
3.4.1 Definition and Objectives ................................................................... 22
3.4.2 Creating Underbalanced Conditions ................................................... 24
3.4.3 Controlling Underbalance Pressure .................................................... 25

Page 1 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

COILED TUBING DRILLING

Contents Page

3.4.4 Well Pressure Control ........................................................................ 25

3.4.5 Drilling Fluid ...................................................................................... 25
3.4.6 Wellbore Returns ............................................................................... 26
3.5 Running and Pulling Wellbore Tubulars ............................................... 27
4 SURFACE EQUIPMENT .............................................................................. 28
4.1 Rigs and Structures for CTD .............................................................. 28
4.1.1 CTD Substructures and Jack Systems ............................................. 28
4.1.2 Location Requirements ...................................................................... 28
4.2 CT Equipment Package ..................................................................... 29
4.3 Well Pressure Control Equipment ...................................................... 29
4.4 Kick Detection Equipment ................................................................. 31
4.4.1 Flow Comparison ............................................................................... 31
4.4.2 Mud Tank Level Monitoring ................................................................ 31
4.5 Mud System ...................................................................................... 31
4.5.1 Mud Tanks ......................................................................................... 31
4.5.2 Mud Treatment Equipment ................................................................. 34
4.6 Pumping Equipment .......................................................................... 34
4.6.1 Low Pressure Pumping Equipment .................................................... 34
4.6.2 High Pressure Pumping Equipment ................................................... 34
4.7 Monitoring & Recording Equipment .................................................... 35
4.8 Pipe Handling Equipment .................................................................. 35
4.9 Ancillary Surface Equipment ............................................................. 35
4.10 Safety and Emergency Equipment .................................................... 35
5 DOWNHOLE EQUIPMENT ........................................................................... 37
5.1 Bits ................................................................................................... 37
5.1.1 Rock Bits .......................................................................................... 37
5.1.2 Drag Bits ........................................................................................... 37
5.2 Downhole Motors ............................................................................... 41
5.2.1 Positive Displacement Motors ........................................................... 41
5.3 CTD Downhole Equipment ................................................................. 42
5.3.1 BHA For Vertical Wellbores ............................................................... 44
5.3.2 BHA for Deviated Wellbores .............................................................. 44
5.4 Principal Components of a Directional BHA ....................................... 44
5.5 Specialized CTD Tools ....................................................................... 48

Page 2 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

1 EVOLUTION OF COILED TUBING DRILLING reduced hole size (slimhole) and wellsite area. In addition,
CT units and equipment typically have lower mobilization
The techniques and equipment associated with coiled and demobilization costs.
tubing drilling (CTD) have undergone rapid development
since the first operations attempted in 1991. A principal 1.1.3 Operational
stimulus for this activity was the availability of reliable
large diameter CT which enabled sufficient hydraulic The safety advantage brought by CT well control equip-
horsepower to be delivered downhole. This energy is ment enables underbalanced drilling operations to be
required to power the downhole motor and provide suffi- completed safely and efficiently. The principal advantage
cient flow rate to ensure adequate hole cleaning through of underbalanced drilling being reduced reservoir damage
efficient cutting transport. In addition, larger and heavier caused by the invasion of drilling fluid and cuttings.
wall tubing provides the necessary weight for efficient
drilling and to safely withstand the torque and fatigue Since the majority of CT services are performed through
imposed by drilling operations. the production tubing, specialized thru-tubing CTD can be
undertaken with the completion tubulars in place. Well
1.1 Advantages of CTD deepening and side-tracking of existing wells in depleted
reservoirs is an area in which CTD offers significant
The factors, or advantages, associated with CTD which operational and cost benefits compared with conventional
have provided the impetus for the service development drilling techniques.
can be categorized as shown below.
Ultimately, it is intended that the techniques and equipment
• Safety used in CTD will provide a level of control and response
which will permit “joystick drilling”.
• Economic
1.1.4 Environmental
• Operational
In several locations, e.g., urban areas, minimizing the
• Environmental wellsite area, as well as the visual and noise impact, is a
significant factor in the preparation and execution of drilling
1.1.1 Safety operations. The configuration of CT equipment enables
operations to be completed from a smaller work site using
The configuration of the well control equipment used in CT equipment which is less visually intrusive. Additionally,
operations provides a higher degree of control and safety operations using continuous tubing cause significantly
than that associated with conventional drilling equipment. less noise pollution than those using jointed pipe.
This level of control is maintained throughout drilling and
tripping operations. A large proportion of accidents are 1.1.5 Limitations and Disadvantages
associated with pipe handling and the making and breaking
of tooljoints. With CTD, exposure to such hazards is much The limitations and disadvantages of CTD can be summa-
reduced. rized in the following categories.

1.1.2 Economic • Economic – in many areas, the abundance of low-cost

conventional rigs render the use of CTD for some
Under the right conditions, CTD has the potential to provide applications uneconomic. In such areas, only special-
a general reduction in drilling and well costs. While this was ized CTD techniques which cannot be completed by
a significant objective for early CTD attempts, it was conventional equipment will be viable.
seldom achieved due to the difficulties which are typically
associated with an emerging technology. • Hole size – the advantage of being able to drill slimhole
is, in some applications, countered by the inability to drill
The principal areas of cost saving in CTD are related to the larger hole sizes.

Page 3 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

• Rotation – since the CT string cannot be rotated, steering 2 JOB DESIGN AND PREPARATION
adjustments in directional drilling applications must be
initiated using downhole tools. The job design and preparation sequence for CTD opera-
tions comprises several distinct tasks or areas of investi-
• CT fatigue and life – although the fatigue and useful life gation.
of CT strings are now well understood and monitored, it
can be difficult to accurately predict the extent to which • Establish the client's objectives
a strings life may be used during any CTD operation.
• Review the technical feasibility
1.2 CTD Applications
• Technical preparation
There are several ways in which CTD applications have
been classified. Most operations can be described using • Administrative preparation
the following criteria (Fig. 1):
2.1 Establishing Objectives
• Well status – new well or re-entry
Unlike most CT service activities, the overall objective(s)
• Well preparation – tubing/completion removed or thru- of the client may not always be immediately apparent, e.g.,
tubing is the well being drilled for production, appraisal, delinea-
tion or exploration purposes? It is beneficial to the overall
• Wellbore trajectory – well deepening or side track process if all parties involved in the design and execution
of the CTD operation are aware of the objectives and goals
• Wellbore conditions – underbalanced or overbalanced associated with them. In addition, the means and criteria
drilling by which the achievement of the objectives will be as-
sessed should also be known.

CTD

Vertical Directional
Applications Applications

New Well Electric Mud Pulse

Wells Deepenings Telemetry Telemetry

Fig. 1 Classification of CTD applications.

Page 4 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

There are several specific applications for CTD. The 2.2.1 Weight On Bit
following information and guides are based on the four
most common applications, i.e., the majority of CTD The necessary force, or weight on bit (WOB), required to
enquiries or feasibility studies requested by clients may maintain penetration while drilling, can be obtained from
be included in these categories. two sources. When drilling vertical or slightly deviated
wellbores, drill collars are used to provide weight on bit. In
• New exploration wells such cases the CT is kept in tension to ensure a stable
trajectory. In highly deviated wellbores the CT string is
• New development wells used to provide the necessary weight on bit.

• Existing well deepening In conventional drilling operations using jointed pipe, the
actual weight on bit is relatively easy to calculate.
• Existing well sidetracking However, due to the buckling which occurs in a CT string,
such calculations are no longer valid for CTD. A tubing
The location and logistic concerns outlined in Fig. 2 apply forces model must be used to determine the available
to all CTD applications. To assist with the data acquisition compressive load at the bit before the CT locks up. At the
process, an enquiry guide for each application is included point of lock-up, no further weight can be applied to the bit,
in Fig. 3 and Fig. 4. A summary of the current technical but surface indications (weight indicator) may not reflect
capabilities is also included. this condition. The term downhole weight on bit (DWOB),
refers to the actual force being transmitted to the bit, not
2.2 Technical Feasibility the apparent force displayed by the weight indicator at
surface.
When assessing the technical feasibility of any CTD
operation a logical and methodical approach is essential While drilling the buildup section of a deviated wellbore, the
(Fig. 5). The following areas should be investigated and the CT must provide sufficient force to bend the BHA around
relevant criteria determined (depending on the specific the build up curve and still provide sufficient DWOB to
application and conditions). A summary of the constraints ensure penetration at a reasonable rate. This bending
which may limit the application or extent of CTD operations friction force must be calculated then subtracted from the
is shown in Figure 6. model output value. The resulting force represents the
available DWOB.
• Weight on bit
The proposed trajectory co-ordinates are required to en-
• Annular velocity able computer model analyses. This information is typi-
cally obtained from the directional drilling (DD) representa-
• Pumping pressure and rate tive. Variations in azimuth and inclination effect the tubing
forces and add to the complexity of the simulation (Fig. 7).
• CT string tension If severe, the doglegs resulting from azimuth and inclina-
tion changes will significantly limit the extent of penetra-
• CT life/fatigue tion–this applies both to the drilling process and subse-
quent well intervention.
• Torque
The tables shown in Fig. 8 and 9 illustrate the force required
• CT reel handling for a range of hole and BHA sizes. Short radius BHAs
containing knuckle joints (or similar) will require more
• Directional requirements detailed modelling.

Several computer simulations may be required to compile

a table incorporating variables in BHA or hole size. In this
way the design can be optimized to provide adequate

Page 5 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

CTD ENQUIRY GUIDE – LOCATION, LOGISTICS AND ENVIRONMENT

Onshore Location
• In which type of environment is the wellsite, e.g., urban area, jungle or desert?
• What are the location constraints, e.g., size, obstructions and obstacles?

Logistics
• Are there any known logistical constraints, e.g., limits to access, operational windows
etc.?

Environment
• What provisions may be necessary to enable adequate environmental protection, e.g.,
noise, spill protection or temporary chemical storage?

Offshore Location
• What are the dimensional and deck load constraints for the operational, storage and fluid
handling areas?

Logistics
• Is a crane of adequate capacity available? Is it located in position which allows unrestricted
access to the well and operational areas? What are the load capacity and boom length?
• Where is the personnel accommodation?

Environment
• What provisions may be necessary to enable adequate environmental protection, e.g.,
noise, spill protection or temporary chemical storage?
• What local weather, sea, seasonal conditions may restrict operations?

Figure 2. CTD enquiry guide – location, logistic and environment.

Page 6 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

CTD ENQUIRY GUIDE – NEW WELLS & VERTICAL WELL DEEPENING

Current Technical Capability

Exploration and produc-

tion objectives

• Is this an oil or gas well?

Data collection
• How extensive is the logging program to be?
• What are the mud logging requirements?
• What is the minimum acceptable size of the production
casing or liner ?
Hole size
Wellbore design Up to 12-1/4-in. hole – for hole sizes
greater than 6-3/4-in. formations
must be unconsolidated (motors
Wellbore geometry OD:– 4-3/4-in. or modified 6-1/2-in.)
• What is to be the TD and open-hole sizes?
• What is the casing program, i.e., casing size and shoe depths? Depth
Achievable depth dependent on
Deviation hole size and formation drillability
• If the wellbore is deviated, what is the projected well profile, i.e, (new well CTD generally limited to
inclination and azimuth versus depth! 5,000 to 6,000 ft with three or four
casing strings.
• What is the acceptable target tolerance fromprojected profile?
• If the wellbore is vertical, what is the maximum acceptable Typical limitations
deviation? • Torque tolerance of the CT string limits
the motor size.
Downhole conditions
• The CT pumping pressure limits the
• What are the formation pressures and temperature?
• What is the well lithology? depth of the hole sizes larger than 4-3/
• Is there a risk of shallow gas? 4-in.
• Are there any sloughing shales?
• What is the likelihood of H2S? CT string size
• 2-3/8-in. CT is recommended for hole
Operations sizes greater than 6-3/4-in. or for 4-3/4-
in. sections deeper than 5,000 ft.

Bit and drilling performance

• What is known of the formation(s) drillability ?
• Are offset well bit records available?

Drilling fluid
• Is the reservoir to be drilled under or overbalanced?
• What drilling fluid(s) is to be used, i.e., mud, foam or air?
• What are the properties of the mud system to be used, i.e.,
type, density and characteristics?
• What is the likelihood of lost circulation?

Figure 3. CTD enquiry guide –new exploration well

Page 7 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

CTD ENQUIRY GUIDE – EXISTING WELL SIDETRACK REENTRY

Current Technical Capability

Production and comple-

tion objectives

Production
• Is this an oil, gas or injection well?

Completion
• What will be the liner size? Hole size
• What is the minimum acceptable liner size? Through-tubing
• Will the liner be cemented?
• Minimum completion size of 4-1/2-in.,
• How is the new completion to be configured?
allowing a 3-1/2- or 3-3/4-in. hole.

Wellbore design Conventional (completion removed)

• Up to 4-3/4-in. with a build-up radius of up
Wellbore geometry to 60°/100ft.
• What is to be the TD and open-hole sizes? • Up to 6-in. with a build-up radius of up to
• What are the existing casing sizes and shoe depths? 15°/100ft.
Deviation
Depth
• What is the existing well profile, i.e, inclination and azimuth
• Horizontal drainhole can exceed 2,000ft,
versus depth?
but is dependent on BUR, KOD, casing
• Which kick-off technique will be used, e.g., window or section
and CT sizes.
milling?
• What is the re-entry well profile, i.e., kick-off depth, build up Total depth
rate, inclination, azimuth and drain hole length? • Through tubing: up to 15,000ft
• What is the acceptable target tolerance from projected profile? • Conventional (completion removed):
more than 10,000ft
Downhole conditions
• What are the formation pressures and temperature? Typical limitations
• What is the well lithology? • Build-up radius (BUR) limited by bending
• Are there any sloughing shales?
• What is the likelihood of H2S friction force of the BHA which limits the
available WOB.
• Downhole WOB provided by the CT limits
Operations
the horizontal drainhole length (CoilCADE
check)
Bit and drilling performance
• What is known of the formation(s) drillability?
• Are offset well bit records available? CT string size
• 1-3/4- to 2-3/8-in. depending on the hole
Drilling fluid profile
• Is the reservoir to be drilled under or overbalanced?
• What drilling fluid(s) is to be used, i.e., mud, foam or air?
• What are the properties of the mud system to be used, i.e.,
type, density and characteristics?
• What is the likelihood of lost circulation or losses?

Figure 4. CTD enquiry guide – existing well sidetrack reentry.

Page 8 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

Investigate Annular Velocity

Gather Are Velocity Criteria Options
Calculate conditions for largest
velocity criteria • Install a suspended casing
Data hole size and highest deviation
met ? •Downsize the hole
section. Use 80% of maximum No
motor flow rate.

Yes

No Horizontal Yes
or highly deviated
wellbore

Investigate Pressure Parameters Investigate Tension Parameters Investigate DWOB Parameters

Run model to calculate CT string Run model to calculate the Run model to determine CT
and annular pressure loss at 80% of maximum CT string tension. compressive load before lock-up at;
the maximum motor flowrate. • the total depth (TD)
• the end of build-up section

Calculate
Calculate Establish maximum tension required
Estimate the pumping pressure by by adding 15,000 lb safety factor Calculate
adding the estimated BHA pressure to the model output. • Estimate the bending friction in
loss to model output. in the build-up section.
• Calculate the downhole weight on bit
(DWOB) available at the end of the
build-up section, i.e.,
Check Results model output less bending friction
Check Results • Against the maximum allowable
Against the maximum allowable tension for the CT string.
working pressure for the CT string. • Injector head pulling capacity.

Check Results
• Against the estimated minimum
DWOB for the hole size;
Above No Above • 4-3/4-in. hole – 1,500 lbf
maximum maximum • 4-1/8-in. hole – 1,000 lbf
allowable ? allowable ? No

Yes Yes
Below
No
Pressure Criteria Options Tension Criteria Options minimum
• Use CT string with greater OD • Use a higher capacity allowable ?
and/or injector head
greater wall thickness • Use CT string with greater
• Use a smaller motor wall thickness Yes
• Downsize the hole and/or
higher yield strength DWOB Criteria Options
• Use CT string with greater OD
and/or
greater wall thickness
• Decrease the build-up rate
• Downsize the hole

Can job
Project not feasible design changes
as proposed be made ?
No

Project is feasible
Yes as proposed

Figure 5. Step by step feasibility study flowchart.

Page 9 of 48
 COILED TUBING DRILLING – LIMITING PARAMETERS

Constraints Limitation Equipment Limitations Design Limit Remarks

Drilling Rate (ROP) Rev A - 98

Page 10 of 48
Section 380

Hydraulic power Maximum flow rate • CT Max allowable pressure • Hole diameter Use the largest fishable motor for the hole size for maximum flow
at the bit • Motor maximum flow rate • Hole depth rate (consider max allowable CT pressure). Use CT string length
• CT length and diameter appropriate to the well TD. Use a shear thinning mud to minimize the
• Mud type, weight, yield pressure loss.

Mechanical power Torque • CT max allowable torque • Hole diameter Use a motor with the maximum torque in its category. Make sure the
at the bit • Motor max torque CT and BHA max allowable torque is less than twice the motor stall
torque.

RPM • Motor speed • Hole diameter Two basic types of slim hole motors are available: high speed/low
• Bit max operating speed torque or low speed/high torque. A drill off test is necessary to
optimize ROP and minimize vibrations for a given formation and
motor/bit combination.

Weight on Bit • CT diameter, wall thickness • Hole diameter In the case of vertical or slightly deviated holes, drill collars are used
(WOB) and yield • Drain hole length to provide WOB, but for highly deviated or horizontal wells, the CT
• BHA ID, OD, and length • Build up rate provides the WOB and the maximum compressive load at the CT
end before lock up, is the limiting factor. “The maximum available
compressive load at the end of the CT, must be estimated using a
model in two critical positions: in the build up section and at the total
depth (TD).
• In the build up section, the max CT compressive load before lock
up must be sufficient to overcome the bending friction force of the
BHA while providing sufficient WOB to drill at an acceptable rate.
• At TD in the horizontal or deviated section, the max CT compres-
sive load before lock up given by the model, is the maximum avail-
able WOB at TD.
COILED TUBING DRILLING

Tripping and Hole Cleaning

Pull capacity • CT max allowable tension •Hole depth The maximum tension must at least be equal to the maximum hang-
Tension
• Injector Pulling capability ing CT and BHA weight + the estimated maximum hole drag + a
COILED TUBING SERVICES MANUAL

• BHA max allowable tension recommended safety margin for overpull (15,000 to 20,000 lbf).

Hole cleaning • CT Max allowable pressure •Hole diameter As a general rule, the minimum velocity in a vertical wellbore section
Minimum
• CT length and diameter is 40ft/min. In highly deviated wellbores 100 ft/min should be used as
annular velocity
• Motor maximum flow rate a guide. The Wellbore Simulator should be used in the assessment
of critical cases. The annular velocity should be considered in the
largest hole section that is generally the upper hole section where
the casing is the largest and in the most deviated hole section.

Figure 6. CTD limiting parameters

 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

DWOB throughout the build-up horizontal (or deviated) • Horizontal and highly deviated sections
sections. For example, larger or heavier CT work strings
provide more available DWOB while a higher build-up • Large diameter casings or top hole sections
radius reduces the available DWOB.
Hole geometry, cuttings size and drilling fluid characteris-
A friction coefficient of 0.4 should be used in model tics greatly influence the hole cleaning ability of any
analyses of openhole sections. system. However, due to the high-speed motor and bit
combinations typically used in CTD operations, the cutting
The minimum recommended DWOB available for CTD in size is generally very small (<50 microns). The small
various hole size ranges is shown below. cutting size significantly assists with removal.

Openhole Recommended The following annular velocity rules of thumb can be used
Diameter Minimum DWOB in preliminary feasibility and design work.
(in.) (lbf)
• Vertical hole sections – 30-40 ft/min annular velocity
3-3/4 to 4 1000 (new wells and shallow sections with coarser cuttings
4-1/8 to 4-3/4 1500 may require velocities as high as 50 ft/min).
5 to 6-1/4 2500
• Horizontal hole sections – 100 ft/min (depends a great
2.2.2 Annular Velocity deal on the length of horizontal section and the drilling
fluid characteristics).
It is necessary to determine if the available annular
velocity will be sufficient to provide adequate hole clean- A table of common hole, motor and CT sizes is shown in
ing. This is critical in two general areas. Fig.10.

There are several recently developed mud and drilling fluid

systems which provide improved hole cleaning ability and
fluid performance. Investigation and selection of CTD
drilling fluids should be conducted in co-operation with
DFS personnel.

Surface reference point Shear thinning fluids (e.g., some polymer muds) can
decrease pressure losses by 30-40%. A hydraulic model
typically cannot accurately simulate the performance of
such fluids with yield point (YP) and plastic viscosity (PV)
Survey point inputs alone–results are typically conservative.
• Measured depth
• True vertical depth High pressure wells requiring high mud weight can present
• Borehole Inclination a problem which limits the depth (length of CT string) which
• Borehole Azimuth may be efficiently drilled.

2.2.3 Pump Pressure and Rate

North axis
The friction pressure induced by long or small diameter CT
East axis strings can be a limiting factor for some motor/bit/CT
string combinations. Hydraulic models should be used to
ensure the compatibility of the various components and
pumping equipment. A computer model should be used to
Figure 7. Azimuth/inclination. calculate pressure loss within the CT string and annulus.

Page 11 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

BHA BENDING FRICTION FORCE – 2-7/8-in. MOTORS

Dog Leg Hole Friction BHA BHA Bending

Severity Diameter Coefficient OD ID Friction Force
(°/100 ft) (in.) (in.) (in.) (lbf)

15 4.75 0.35 3 2.25 254

20 4.75 0.35 3 2.25 391
25 4.75 0.35 3 2.25 546
30 4.75 0.35 3 2.25 718
35 4.75 0.35 3 2.25 905

40 4.75 0.35 3 2.25 1106

45 4.75 0.35 3 2.25 1319
50 4.75 0.35 3 2.25 1545
55 4.75 0.35 3 2.25 1783
60 4.75 0.35 3 2.25 2031

15 4.125 0.35 3 2.25 317

20 4.125 0.35 3 2.25 488
25 4.125 0.35 3 2.25 681
30 4.125 0.35 3 2.25 896
35 4.125 0.35 3 2.25 1129

40 4.125 0.35 3 2.25 1379

45 4.125 0.35 3 2.25 1645
50 4.125 0.35 3 2.25 1927
55 4.125 0.35 3 2.25 2223
60 4.125 0.35 3 2.25 2533

15 3.75 0.35 3 2.25 388

20 3.75 0.35 3 2.25 597
25 3.75 0.35 3 2.25 834
30 3.75 0.35 3 2.25 1097
35 3.75 0.35 3 2.25 1382

40 3.75 0.35 3 2.25 1689

45 3.75 0.35 3 2.25 2015
50 3.75 0.35 3 2.25 2360
55 3.75 0.35 3 2.25 2723
60 3.75 0.35 3 2.25 3103

Figure 8. BHA bending friction forces

Page 12 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

BHA BENDING FRICTION FORCE – 3-1/2-in. MOTORS

Dog Leg Hole Friction BHA BHA Bending

Severity Diameter Coefficient OD ID Friction Force
(°/100 ft) (in.) (in.) (in.) (lbf)

5 6 0,35 3.5 2.5 82

10 6 0,35 3.5 2.5 232
15 6 0,35 3.5 2.5 426
20 6 0,35 3.5 2.5 656
25 6 0,35 3.5 2.5 916
30 6 0,35 3.5 2.5 1204
35 6 0,35 3.5 2.5 1518
40 6 0,35 3.5 2.5 1854
45 6 0,35 3.5 2.5 2213

5 4.75 0.35 3.5 2.5 116

10 4.75 0.35 3.5 2.5 328
15 4.75 0.35 3.5 2.5 602
20 4.75 0.35 3.5 2.5 927
25 4.75 0.35 3.5 2.5 1296
30 4.75 0.35 3.5 2.5 1703
35 4.75 0.35 3.5 2.5 2146
40 4.75 0.35 3.5 2.5 2622
45 4.75 0.35 3.5 2.5 3129

BHA BENDING FRICTION FORCE – 4-3/4 -in. MOTORS

Dog Leg Hole Friction BHA BHA Bending

Severity Diameter Coefficient OD ID Friction Force
(°/100 ft) (in.) (in.) (in.) (lbf)

5 6 0.35 4.75 3 447

10 6 0.35 4.75 3 1264
15 6 0.35 4.75 3 2322
20 6 0.35 4.75 3 3576

Figure 9. BHA bending fricion forces.

Page 13 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

An estimate of the pressure loss within the BHA should be • Once the operation has commenced, a careful record
added to the resulting value. The total pressure loss is then must be kept and regularly reviewed to ensure that actual
compared with the allowable CT string pressure or pump- life usage is within that predicted.
ing equipment limitation(s).
Because of the variable and unknown factors associated
As a general guide, the following BHA pressure loss values with most drilling operations, it is extremely difficult to
can be used. estimate the expected life usage. Nonetheless, the
consequences of exceeding the fatigue and life limitations
Estimated can be severe (in the case of a failure) and inconvenient (in
Type of BHA pressure loss (psi) the case of a reel change being required).

4 3/4" OD vertical hole BHA 400 As a general guide, data gathered from completed CTD
3' OD Directional BHA 1000 operations indicates the following life usage.

2.2.4 CT String Tension Vertical wells

A tubing forces model should be used to determine the Shallow wells, e.g., 2000 ft can be drilled with the CT
maximum anticipated tension required to operate under being exposed to relatively few bending cycles (2 or 3
the expected wellbore conditions. A safety margin for cycles being typical). Therefore the life expectancy of a
overpull (typically around 15,000 lb) should be added to the string can reasonably extend to several wells.
maximum anticipated tension. The resulting total must
then still be below the maximum allowable CT string Deviated wells
tension as determined by an appropriate computer model.
Data from previous operations indicate that a 2-in. CT
2.2.5 Torque string can, on average, be used for three or four re-entry
wells. Similarly, a 2-3/8-in. CT string is typically used on
Excessive torque is not generally a problem with the bit/ two to three wells.
motor/CT string combinations typically used in CTD
operations. However, an awareness of the torque limits, In all cases, continuous monitoring and recording is
and factors influencing such limits, is essential in hole/bit essential to ensure that prescribed limits are not ex-
sizes larger than 4-3/4-in. ceeded.

The torque generated by 6-in. motors can exceed the 2.2.7 CT Reel Handling
torque limits of 2-3/8-in. CT. Consequently, CTD of large
hole sizes (e.g., 8-1/2 or 12-1/4-in.) should be completed One of the main constraints on the size and length of CT
using a 4-3/4-in. motor or 6-3/4in low torque motors (e.g. 1- strings are the limits imposed by road transport weight
2 or 2-3 lobes). regulations and offshore crane capacity. While it may be
undesirable to assemble (field weld) work strings, it may be
The maximum allowable CT torque should be less than the only option in the case of limited road weights. Offshore
twice the motor stall torque. crane capacity restrictions can be overcome, in some
circumstances, by spooling the tubing between a supply
2.2.6 CT Life and Fatigue boat and platform. Using this technique, the empty reel is
lifted to the platform and rigged up to spool the tubing string
There are two principal areas of importance regarding CT from a shipment spool on the boat deck.
life and fatigue in CTD operations.

• A careful study of the anticipated cycles and operating

conditions should be undertaken to assess the expected
life usage of the specified string.

Page 14 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

ANNULAR VELOCITY – MOTOR/HOLE SIZE vs. CT SIZE

Flowrate Hole ID Annular Velocity (ft/min)

(BPM) (in.) 1-3/4-in CT 2-in.CT 2-3/8-in. CT

2-7/8-in. motor 2.00 3.750 187 205 244

2.00 4.125 148 158 181
2.00 4.750 106 111 122
2.00 6.125 60 61 65
2.00 7.000 45 46 47
2.00 8.000 34 34 35
2.00 9.000 26 27 27

2-3/8-in motor 2.30 3.750 215 235 281

2.30 4.125 170 182 208
2.30 4.750 121 128 140
2.30 6.125 69 71 74
2.30 7.000 52 53 55
2.30 8.000 39 39 41
2.30 9.000 30 31 31

3-1/2-in. motor 2.30 4.125 170 182 208

2.30 4.750 121 128 140
2.30 6.125 69 71 74
2.30 7.000 52 53 55
2.30 8.000 39 39 41
2.30 9.000 30 31 31

3-1/2-in. motor 2.60 4.125 192 206 235

2.60 4.750 137 144 158
2.60 6.125 78 80 84
2.60 7.000 58 59 62
2.60 8.000 44 45 46
2.60 9.000 34 35 36

4-3/4-in. motor 4.75 6.125 - 146 153

4.75 7.000 - 109 113
4.75 8.000 - 81 84
4.75 9.000 - 64 65

4-3/4-in. motor 6.00 6.125 - - 194

6.00 7.000 - - 142
6.00 8.000 - - 106

Figure 10. Annular velocities for different hole size/motor/CT string combinations.

Page 15 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

2.2.8 Directional Requirements • Procedures and planning

Applications which require directional control and monitor- • Drawings and schematic diagrams
ing require special investigation and the involvement of
directional engineers at an early stage. As a guide of • Personnel
current capability, the following limits apply.
To enable the efficient management and co-ordination of
• Downhole temperature – currently limited to 310°F these individual areas, it is advisable to prepare a list of
maximum. tasks required to complete technical preparation. Such a
list should contain information on the task, designated
• Deviation build rates – A function of tool string length and person, deadline and additional information appropriate to
stiffness with, in general, longer tool strings requiring the specific task.
lower build rates. Also, aggressive build rates can limit
the efficiency of orienting tools. Current orienting tools 2.3.2 Basic Equipment and Services
are designed to operate within dog-legs of up to 50°/100
ft. To help identify the source(s) of equipment, services and
expertise necessary to complete the project, comprehen-
• Hole size – Currently, directional assemblies utilize a 2- sive check lists should be prepared under the headings
7/8-in. monel housing. Consequently, the minimum hole shown below.
size with directional control is 3-1/2-in.
Each list should be formatted to include an accurate
2.3 CTD Project Preparation description of the item or service, the source and appli-
cable deadlines or leadtimes.
The preparation for a CTD project typically involves co-
ordinating the input of several specialist disciplines to • Surface equipment
compile an overall job plan or procedure. In most cases it
is desirable to assign one engineer as the person in charge • Consumables
of the design and preparation of the CTD operation.
Logically, this person will provide a focused point of • Spare parts and supplies
contact between client and contractor(s), and be available
for operation support duties during the execution of the • Dowhhole tools
CTD project.
• Associated services
The tasks required to be completed in this phase of CTD
project preparation may be summarized as technical or 2.3.3 Procedures and Plans
administrative. Regardless of how the various elements
are categorized, each should be regarded as a key compo- Due to the complex nature of the overall operation, it is
nent which is essential for completion of a safe and recommended that detailed procedures and plans be
successful CTD project. prepared for the principal project elements. These proce-
dures should take account of the specific wellsite, wellbore
2.3.1 Technical Preparation and reservoir conditions (or anticipated conditions) under
which they will be executed.
There are several tasks to be performed, each with
associated deadlines, in the process of technical prepara- All procedures and plans should be carefully reviewed by
tion. The tasks can be planned, and appropriate duties the personnel, groups or organizations involved. In some
delegated, with the help of check lists in the following cases it may be necessary to adopt a formal review and
principal areas. approval process to ensure all parties acknowledge accep-
tance.
• Basic equipment and services

Page 16 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

Note: Ensure that each document is clearly identified with • Wellbore schematic (at each stage of the operation)
a date or version number. This will minimize confusion and
error where several parties are provided with procedures or • Trajectory plot if deviated
plans.
• Surface equipment lay out with dimensions (or scale)
The following list includes typical elements of a CTD including indication of restrictive zoning where appli-
project. This list comprises the basic requirements of a cable, e.g., Zone II
number of CTD applications, consequently, some ele-
ments may not be applicable. Similarly, additional ele- • BOP stack schematic with heights and dimensions
ments may be required for specific CTD project(s).
• BHA schematics (fishing diagram for each assembly)
• Mob/demob organization
• High pressure and low pressure lines schematics
• Rigging up/down
• Electrical wiring of surface equipment
• Setting whipstock & milling window (if required)
2.3.5 Personnel
• Well control
In addition to the availability and assignment of personnel,
• Well control equipment testing there may be several issues which should be addressed.
The following examples may apply to the organization of
• BHA deployment even overbalance CTD personnel for various applications and locations.

• Running and setting liner or casing (if required) • Training and certification of personnel

• Running completion string • Personnel job descriptions

• Cementing job design • Operations and support organization organograms

• Mud program 2.3.6 Administrative Preparation

• Contingency plans Clarify and finalize arrangements between the client and
third party contractor(s). The final agreement should in-
• Emergency responses (in the event of fire, etc) clude the following sections:

2.3.4 Drawings and Schematic Diagrams • Equipment list provided by contractor and operator

Much of the explanation required within procedures and • Personnel list provided by contractor
plans can be simplified by the use of clear and suitably
detailed drawings and schematic diagrams. The following • List of services provided by contractor and operator
list includes typical examples of drawings or schematic
diagrams for CTD projects. • Liability clauses

Note: Ensure that each document is clearly identified with • Day rates, lump sums, incentives and penalties including
a date or version number. This will minimize confusion and force majeure
error where several parties are provided with procedures or
plans.

Page 17 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

3 EXECUTION require the involvement of different specialist skills which

may require the participation of third party suppliers or
3.1 Well Control (Overbalanced Drilling) service companies.

This section addresses only well control in over balanced • Well preparation
drilling applications. The issues concerning underbalanced
drilling are addressed separately in Section 3.4. • Preparing/setting the whipstock

Most conventional well control precautions and proce- • Milling the window
dures used for conventional drilling apply to overbalanced
CTD (with minor modifications). For example, in slim hole • Drilling the sidetrack
wells, it is vital that kicks are detected as soon as possible.
Within the relatively small wellbore, even small influxes of Conventional sidetracking is currently undertaken at depths
reservoir fluid can displace a significant volume of drilling in excess of 10,000 ft, with resulting drain hole diameter
fluid–resulting in a rapid worsening of the situation. Dy- within a range of 3-1/2- to 6-in (Fig 11).
namic kill is not a viable option for CTD due to the small
annular pressure loss. The wait and weight method or the The application of conventional CTD sidetracking tech-
driller's method, such as used for kick control on conven- niques have special significance on offshore platforms,
tional drilling operations is typically used. where mobilization and logistic difficulties may render
conventional rig-based re-entry techniques non-viable.
The preferred kick detection system for CTD operations is The economic viability of onshore CTD re-entry operations
to use a flowmeter installed on the return line. The is greatly dependent on the local availability, and suitabil-
equipment is described in the surface equipment section ity, of conventional rigs and equipment.
of this manual.
3.2.1 Well Preparation
If foam or air is being used as a drilling fluid, the implication
is that the reservoir pressure is very low. In the event of a The following list summarizes the operations typically
kick, the well will generally kill itself, or worst case, required as well preparation for setting the whipstock then
pumping water will kill the well. Pressure deployment of the continuing with subsequent milling and drilling operations.
BHA is typically required if drilling with foam in a gas
reservoir. This is necessary as the foam may break when • Kill the well
tripping, resulting in unstable wellbore conditions.
• Nipple down christmas tree and nipple up well control
3.2 Conventional Sidetracking equipment

The term conventional sidetracking or re-entry applies to • Test the well control equipment
CTD operations which are undertaken under the following
conditions. • Pull the production tubing and retrieve packer (if required)

• The well is killed and all subsequent CTD activities are • Squeeze cement off perforated interval (if necessary)
performed in overbalanced conditions. or set cement plug and/or set bridge plug

• The original completion tubulars have been removed. • Run CCL (to check for casing collars at the KOD), CBL (to
check cement/bond quality) and Gamma Ray (to corre-
• A mechanical whipstock is used to initiate window milling late depth).
operations in the casing or liner.
• Run a casing scrapper to the KOD
There are four distinct operational phases in completing a
conventional side tracking operation. Each phase will

Page 18 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

• If azimuth control is required, set the whipstock anchor.

Original wellhead This is typically run on wireline, but CT conveyance may
equipment removed with be appropriate in some circumstances.
production string
• Perform a gyro survey to determine the orientation of the
whipstock anchor. The orientation must be known to
allow the whipstock key to be set. Thereby ensuring the
whipstock orientation is correct when set on the whip-
stock anchor.

• Prepare the whipstock – if run without an anchor, the

whipstock is equipped with a set of slips which are set on
the casing wall (similar to packer slips). A bridge plug or
cement plug must be set at the kick off depth to enable
the whipstock slips to be set with set-down weight. If the
whipstock is to be used with an anchor, a mule shoe and
orientation stinger will be made up to the bottom of the
whipstock.

New side-tracked • Run and set the whipstock

wellbore
Whipstock run with an anchor and stinger

The BHA is run in the hole, the anchor is tagged and stinger
engaged into the anchor. A swivel assembly allows the
stinger to rotate freely allowing correct alignment of the
Retrievable whipstock may whipstock and anchor. Weight is then applied to set the
enable original wellbore to slips in the anchor, overpull confirms that the stinger is
be recovered after side anchored. A release stud between the whipstock and the
tracking is completed running tool is then sheared with additional overpull, and
the running assembly is retrieved or milling of the window
starts if a starting mill is run with the running tool.
Figure 11. Typical conventional sidetrack
configuration. Whipstock run without an anchor

The BHA is run in the hole, the cement plug or bridge plug
tagged and the whipstock slips set. A shear stud on the
3.2.2 Setting the Whipstock running tool is sheared by applying weight (or by pulling
depending on the type of whipstock). The running assem-
The procedures and equipment necessary to set the bly is then retrieved or milling of the window starts if a
whipstock depends on the operation objectives. If azimuth starting mill is run with the running tool.
control is required, then a whipstock anchor must be set.
The whipstock anchor is necessary to ensure the whip- In some applications a special mill/motor assembly is
stock is correctly orientated, to allow milling and drilling used as a running tool. The advantage being the ability to
operations to be started along the correct trajectory. start milling immediately the whipstock is set, with no need
to retrieve and change the BHA (see below).
The following list summarizes the activities which may be
necessary to run and set a mechanical whipstock ready for
milling operations.

Page 19 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

3.2.3 Window Milling Diamond speed mill (no lug in the whipstock concave)

It is generally recommended that window milling be per- • A diamond speed mill and low speed motor assembly is
formed using low speed motors (typically 3-1/2- or 4-3/4- used to mill approximately 5 ft of window.
in. motors, depending on hole size). The necessary weight-
on-bit being provided by drill collars. The WOB required to • A water melon mill is then made up above the speed mill
mill a casing window does not generally exceed 1,000 to to complete the window and to drill approximately 5 ft of
2,000 lbf. A representative of the whipstock vendor or formation.
directional drilling company is generally required on loca-
tion to supervise the preparation and execution of window • A string mill is then made up above the water melon mill
milling operations. for reaming the window section.

There are two basic options for window milling using a 3.3 Thru-Tubing Re-entry
mechanical whipstock.
The term thru-tubing reentry applies to CTD operations
• Using a conventional starting mill/whipstock lug combi- which are undertaken under the following conditions.
nation.
• Operations are conducted over (or through) the christmas
• Using a diamond speed mill tree.

Starting mill/whipstock lug combination • The original completion tubulars remain in place.

The following list summarizes the activities necessary to • Well control equipment is used to enable under- or over-
mill a casing window using a starting mill and whipstock balanced drilling to be conducted safely.
lug.
Thru-tubing reentries can only be undertaken using mill
• A conventional starting mill is first made up to a low speed and bit assemblies which are compatible with the minimum
motor and run in the hole to mill about 3 ft of casing and ID (restriction) present in the tubing string or completion.
the whipstock lug. In some cases, tubing restrictions may be milled out or cut
to allow access for larger mills and bits. Nondirectional
• The starting mill is replaced by a window mill and a water deepenings and sidetracks may generally be undertaken
melon mill. The water melon mill being made up between through completion strings of 3-1/2-in. or greater. Direc-
the window mill and the motor. About 9 ft of window is tional applications generally require tubing 4-1/2-in. or
milled, followed by approximately 5 ft of formation. greater to allow passage of the 3-in. OD directional BHA.
Drilling the formation allows the next milling assembly to The resulting drainhole hole is generally 3-1/2 or 3-3/4-in.
enter the open hole when dressing off the window. depending on the minimum restriction.

• A string mill is made up on top of the water melon mill for Thru-tubing reentry techniques have special significance
reaming the window section. on applications where completion removal is uneconomic
or impossible. The constraints associated with working
As an alternative to the multiple runs and BHA changes within the completion tubulars generally preclude conven-
outlined above, the low-speed motor can be used as a tional rigs and equipment from this type of operation.
whipstock running assembly. This enables window milling
to commence immediately after the whipstock shear stud Significant benefits can be gained from thru-tubing CTD in
has released, i.e., a BHA change is not necessary to start underbalanced conditions. Consequently thru-tubing CTD
milling. A check must be made to ensure the motor can can offer great potential in the development of depleted
withstand the necessary pull or set down weights required reservoirs.
to set the whipstock and shear the stud.

Page 20 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

There are three basic techniques which can be used to

kick-off and mill a casing or liner window below the tubing Original wellhead
tail-pipe. The regional CTD specialist should be contacted equipment removed with
during the design phase of any thru-tubing CTD application production string
to ensure that the most recent design and executing
techniques can be applied (Fig 12).

• Whipstock in production tubing

• Thru-tubing whipstock

• Cement kick-off techniques

– Time drilling in a cement plug
– Whipstock in cement plug pilot hole

3.3.1 Well Preparation

The following list summarizes the operations typically

required as well preparation for thru-tubing CTD opera-
tions.
New side-tracked
wellbore
• Nipple up CT well control equipment.

• Plug and abandon existing perforated zones

• Run CCL (to check for casing collars at the KOD), CBL
(to check cement/bond quality) and Gamma Ray (to
correlate depth) Figure 12. Typical thru-tubing sidetrack
configuration.
• Mill some nipples in the tubing or cut tail pipe if necessary
because of restrictions.
3.3.3 Thru-tubing Whipstock
3.3.2 Whipstock in Production Tubing
Thru-tubing whipstocks are a relatively recent develop-
If the kick off is to be performed from the production tubing, ment which requires ongoing refinement to improve reli-
a conventional whipstock and anchor can be set in the ability. The size ranges available are currently restrictive
tubing and a window milled in tubing and the casing/liner. (through 4-1/2-in. tubing to set inside 7-in, casing or liner).
The hardware and techniques required are currently avail- However this will undoubtedly increase as the tool reliabil-
able and are relatively conventional. However, some ity improves and the techniques become more common.
modifications may be required.
3.3.4 Cement Kick-off Techniques
It is generally not possible to set a whipstock in the
production tubing tail pipe. Therefore, the whipstock will Both of the cement kick-off techniques outlined below are
need to be set above the production packer. This is recently developed and are undergoing continued testing
generally an unacceptable option, consequently this tech- and development. They both require the accurate place-
nique has limited application. ment of a high quality, high compressive-strength cement
plug. Consequently, sufficient effort and resources should
be allocated to ensure the successful design and execu-
tion of the cement plug placement (Fig 13).

Page 21 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

Cement plug preparation • After carefully tagging bottom, the whipstock assembly
is correctly oriented using an orienting tool. By applying
• A cement plug of high compressive-strength is placed in weight, the slips of the whipstock are set against the
the interval 50 ft below the kick-off depth to the bottom casing/cement. Additional weight parts the shear-stud
of the tail pipe (subject to length and volumes). After the allowing retrieval of the running assembly.
cement has adequately cured, the top of the cement is
tagged and dressed if necessary. • A straight milling BHA with a diamond speed mill is run
to mill the window and approximately 5 ft of formation.
• The cement in the tail pipe is then drilled out using a
directional BHA comprising a diamond speed mill and a • The window is then dressed using a water melon mill
slightly bent motor (± 0.25°) assembly similar to that outlined in the conventional
sidetracking section.
• Once out of the tubing the bend is oriented in the direction
of the desired sidetrack. This is achieved using the The regional CTD specialist should be consulted during the
gravity tool face and the hole gyro survey. Drilling is design phase of any thru-tubing CTD application on which
continued through the cement plug, keeping the tool face either of the above cement kick-off techniques are to be
until it reaches the kick-off depth (KOD). used.

Time drilling from a cement plug 3.4 Underbalanced Drilling

• The BHA is retrieved and the bend changed to a higher 3.4.1 Definition and Objectives
angle (± 2.5°).
There has been confusion regarding the definition of
• The window is milled using a time drilling technique, i.e. underbalance drilling. For example, foam/air drilling or
milling with low WOB (or low motor differential pressure), drilling with a parasite string without the well flowing is
running the CT string in short intervals (1/4-in. or 1/2-in. called sometimes underbalanced drilling. However, this is
only) with predetermined delay intervals. The delay time in fact overbalanced drilling if the well does not flow. The
will vary throughout the milling operation as the quantity term underbalanced drilling implies that the reservoir
of steel to be cut varies through the window. pressure is at all times higher than the equivalent circulat-
ing density of the fluid in the annulus. Under these
• When the window and approximately 5 ft of formation conditions, the well will be capable of flowing reservoir fluid
have been drilled, the BHA is retrieved. while drilling or tripping.

• The window is then dressed using a water melon mill The principal objective of underbalanced drilling is to avoid
assembly similar to that outlined in the conventional formation impairment caused by the invasion of drilling
sidetracking section. A bull nose (no bit) is made up at fluid. Some of the horizontal wells drilled underbalanced by
the bottom of the water melon mill to avoid drilling out the CTD have production rates approximately twice that of
cement by accident while dressing the window. nearby wells which were drilled overbalanced. These
nearby wells were drilled using conventional techniques
Whipstock set in the cement plug pilot hole and are completed with larger wellbore and completion
tubulars.
• The pilot hole is drilled in the cement plug approximately
10 ft deeper than the KOD. This rat hole is used to set the Underbalanced drilling is not a damage free technique.
bottom section of the whipstock. However, the potential increase in well productivity out-
weighs most of the associated risks. Permeability reduc-
• The BHA is retrieved and the appropriate whipstock is run tion resulting from the imbibition of drilling fluid can occur.
to bottom. However, the relative effect is significantly less than
overbalanced drilling damage. The absence of a protective
sealing filter cake can also result in some formation

Page 22 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

Completion compo- Completion compo-

nents in place nents in place

Cement inside tailpipe Cement inside tailpipe

Drillout tailpipe Drillout tailpipe

Hole oriented to casing Hole oriented to casing

wall wall

Hole made to kick-off

depth + required rathole
Hole made to kick-off for whipstock
depth

Whipstock window cut

Time-drill window cut

Thru-tubing whipstock

Figure 13a. Time-drilled cement kick-off (thru-tubing). Figure 13b. Whipstock cement kick-off (thru-tubing).

Page 23 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

damage when the well is shut in. Further investigation is The means of creating suitable underbalanced conditions
necessary to assess the extent of these damages for the depends greatly on the anticipated reservoir pressure.
various types of drilling fluids in different formation types. Reservoir pressure can be characterized as being either
An appropriate choice of deployment technique to avoid above or below the hydrostatic pressure of a column of
shutting the well, may be the key to limiting reservoir water in the wellbore.
damage.
Reservoir pressure above water column hydrostatic pres-
One of the main concerns while drilling underbalanced is sure
maintaining borehole stability. Such concerns are height-
ened under the following conditions. Under these conditions, underbalanced pressure can be
created by using a fluid(s) which is less dense than water.
• If no liner or casing has been set over the cap rock interval In marginal cases, careful analysis of the equivalent fluid
above the pay zone density while circulating solids in the annulus should be
conducted to ensure underbalanced conditions exist.
• In unconsolidated reservoirs
Reservoir pressure below water column hydrostatic pres-
• In heterogeneous reservoirs with, for example, shale sure
stringers.
Underbalanced pressure conditions can be created in
Consequently, the reservoir stability and homogeneity three basic ways.
need to be evaluated for all candidate wells. Precautions
to control or limit borehole instability include: • Use a low density drilling fluid

• Careful controlling the degree of underbalance. • Use annular gas-lift

• Selecting appropriate drilling fluids to minimize adverse • Use nitrogen to kick-off the well, then use appropriate
reactions with sensitive formations. fluids

• Setting a casing or liner at the top of the reservoir. Low density fluids

Underbalanced drilling may be likened to drilling while The following low- and ultra low-density fluids have been
taking a kick. However, the equipment and techniques used for drilling. This method is applicable to most wells
used are specifically designed to operate under these with low or high gas-oil-ratios (GOR).
conditions, unlike conventional drilling. Also, since the
completion tubular and christmas tree are still in place, a • Oil based fluids – use is limited to reservoirs with
high level of control can be maintained. Safety issues are pressure corresponding to an equivalent mud weight
also affected by the reservoir pressure. (EMW) of at least 7 ppg. Oil based fluids must be
conditioned after the well returns have been passed
Thru-tubing underbalanced drilling is generally acceptable through the separators and mud treatment equipment.
to regulatory agencies, largely as a result of long estab-
lished CT workover procedures and experience in live • Nitrified or aerated fluid or foam – in wells with a high
wells. GOR, nitrified foam or mud is the only solution to avoid
downhole explosion or fire. In wells having a low GOR,
3.4.2 Creating Underbalanced Conditions the use of an aerated foam or mud instead of nitrified
systems needs careful risk analyses. Foam is typically
Creating and controlling the correct degree of underbalance the best option since a number of computer models are
can be an extremely complex process. For example, available to predict foam performance, pressure losses
computer models provide the only practical means of and resulting EMW. Treatment and disposal of the
predicting the well head and bottom hole pressures in a two wellbore returns are significant problems encountered
phase flow. with foam based fluid systems.

Page 24 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

• Gas – natural gas, air or an inert gas like nitrogen have 3.4.3 Controlling Underbalance Pressure
all, at some time, been used in drilling operations. Due to
the risk, and consequences, of downhole fires and A surface choke is the primary means of controlling the
explosions, Dowell only recommend nitrogen. A careful degree of underbalance created downhole. However, if gas
risk analysis is required for all non-inert gas (or air) lift mandrels or a parasite string is used, the gas or nitrogen
applications. Regardless of the gas used, this type of injection rate will also provide a means of control.
drilling is generally performed in very hard formation with Experience has shown that the surface equipment com-
very low permeability (such as found in the Rocky monly used to treat return fluid, creates a significant back
Mountain region). Such applications are quite distinct pressure. Consequently, varying the gas lift system
from "normal" underbalanced drilling with CTD. parameters to control the degree of underbalance is of
limited value.
Annular gas lift
A downhole annulus-pressure sensor helps to accurately
Two methods are in relatively common use to assist with monitor the bottom hole pressure. This can ensure the
drilling operations. Both being applicable in wells with low underbalance is maintained over a horizontal wellbore
GOR. section (assuming the reservoir pressure remains con-
stant over the horizontal interval).
• Parasite string – the existing production tubing is pulled
and a casing or tubing string with a parallel parasite string 3.4.4 Well Pressure Control
is set in place. The setting depth is dependent on the
formation pressure, i.e., the more depleted the reservoir, Well control procedures used for conventional overbal-
the deeper the string injection point will be. anced drilling are no longer applicable for underbalanced
drilling. A gas or oil kick does not require that the well be
On concluding the drilling operations, the parasite string killed even when tripping.
is pulled and a production tubing string run. Ideally,
retrieving the parasite string and running the production For a thru-tubing underbalanced operation, with the
tubing should be performed under live well conditions to christmas tree in place, the well control or safety proce-
avoid potential damage during shut-in. From a cost and dures are the same as when performing live well service
efficiency standpoint, a parasite string is generally not operations, and are well documented.
the best option.
For non thru-tubing underbalanced operations, accepted
• Gas lift system in the production tubing – if the well is or procedures are not well documented and each application
needs to be equipped with a gas-lift production string and must be carefully reviewed on a case by case basis.
the tubing is large enough to achieve the scope of work,
then the gas lift assisted drilling can be an economic 3.4.5 Drilling Fluid
option. If the well is not suitably equipped, the production
string can be pulled and replaced with larger tubing. The type of drilling fluid is largely determined by the means
by which the underbalance conditions are created. The
Well kick-off and appropriate fluids required functions of a drilling fluid used in underbalanced
drilling are not the same as that required for overbalanced
Some marginal wells may quickly load-up and be capable drilling. For example, a drilling fluid for underbalanced
of flowing only in ideal conditions. In such cases, nitrogen operations is not required to fulfill the following functions.
kick-off and careful fluid selection (and control) may be
sufficient to support underbalanced drilling with CT. This • Balance the formation pressure
method is only applicable in wells with high GOR.
• Minimize formation damage (filter cake and water loss).

However, the fluid must fulfill the following basic require-

ments.

Page 25 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

• Efficiently transport cuttings from the wellbore (slip and

annular velocity) – previous experience demonstrates The separated gas will be vented or flared depending on
that cuttings size in underbalanced conditions are such volume and local constraints. The separated oil is gener-
that slip velocity is very low. A circulating sub above the ally stored in an appropriate tank. The residual water and
motor provides the first option to increase flow rates for solids are routed to a settling tank system, from where the
improved hole cleaning (especially in 9-5/8-in. or larger water is disposed or recirculated and the solids cleaned
casing). A mud system with the appropriate PV, YP, and and dumped (either periodically or at the end of the project).
gel characteristics is preferred, especially in non thru- If water or mud needs to be dumped or treated, the same
tubing applications. procedures as for normal drilling operations can apply.

• Cool and lubricate the bit – generally not a major issue. If some of the fine solids are allowed to recirculate, an
increase in fluid density and pumping pressure can result.
• Control corrosion – controlled by additives, not generally In this likelihood, a centrifuge can be used to treat the mud
a major issue. downstream the separator(s). Cuttings from the centrifuge
will be collected in cutting bins and sent for treatment later.
• Provide sufficient inhibition over shale – may be a
concern if shale stringers are to be drilled, although can On gas wells, when foam is used, the returns will require
be addressed with OBM or mud with appropriate addi- partial separation to allow the gas to be vented or flared and
tives. the broken foam disposed. On foam-drilled oil wells, the
surface equipment may need to be adapted or modified to
If a production tubing gas-lift system is used, and shale ensure efficient breaking of the returns prior to separation.
inhibition is not a concern, water is generally recom-
mended as a drilling fluid. Water can generally achieve Recirculating foam fluid is an option but requires a specific
adequate hole cleaning in 4-1/2-in. tubing and even 7-in. separator built to break the foam (by lowering the pH).
liner below tail pipe. Disposal is simplified since water can Following separation, the liquid pH is increased to allow
generally be dumped or pumped into the production line. recirculation of the foam liquid phase.

3.4.6 Wellbore Returns 3.4.7 BHA Deployment

The simple solution for handling and disposal of wellbore In underbalanced drilling, the BHA needs to be deployed,
returns, i.e., drilling fluid, oil, gas, formation water and i.e., run and retrieved under pressure and live well condi-
cuttings, is to route the entire return flow to the production tions. There are two basic options, either use an external
line. Concerns regarding the routing of solids to production lubricator eg. wireline lubricator or an internal lubricator eg.
facilities are minimal, since the volumes of cuttings for the deployment against the SSSV.
small hole sizes drilled are generally tolerated–even at
high penetration rates. However, the flow line may create Lubricator/riser
enough back pressure to prevent the well from flowing. If
the production facilities cannot treat the returned fluids, it The deployment procedures are similar to those used
may be necessary to treat the returns independently, i.e., when deploying CT service tools. It will generally be
using three phase separators. necessary to deploy the BHA in more than one section
when using a wire line lubricator. On some offshore
The schematic diagram in Fig 18b outlines a typical locations, there is sufficient riser length to allow the BHA
process for treatment of wellbore returns. Returns are to be deployed in one section.
controlled by the choke manifold, following which they are
routed to the separator(s) where oil, gas, drilling solids, and Techniques allowing the well to flow while tripping, will
water are separated. Sample catchers (e.g. a tee with minimize formation damage which could result from shut-
valves and screens) can be installed downstream the in.
choke manifold or returns fluid samples are recovered and
centrifuged to recover cuttings.

Page 26 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

SSSV deployment 3.5 Running and Pulling Wellbore Tubulars

Deploying against the SSSV results in the well being shut It may be necessary to pull the completion string on re-
in and therefore balanced. As discussed in a previous entry wells before sidetracking or deepening. In addition,
section, the absence of filter cake can affect the formation the completion may be removed to allow access for a liner
during shut-in. However, further studies are required to to cover and protect the build up section. On new wells, it
determine the extent and nature of such damage. may be necessary to run one or two strings of casing. Two
options are available, crane or jacking substructure. Se-
3.4.8 Installing Completion Tubulars lection depends on the weight of the tubulars to be run or
pulled.
Installing a liner
Crane
The deployment technique limits the type of liner to a
predrilled liner (jointed or coiled) with the holes plugged with Providing the weight of the tubing or casing string does not
aluminium. The liner float shoe has an aluminium ball to exceed the crane capacity, this is the simplest method of
allow the deployment under pressure. The aluminium running or retrieving the string. However, if the string gets
plugs or ball are removed by spotting acid (with a CT work stuck, there is limited pulling capacity in reserve.
string) after running and/or setting the liner. Plugged liner
can withstand a maximum differential pressure of only Conventional drilling slips, elevators, and safety clamps
2,000 psi. are used. Single joints are handled with the crane which
also holds the entire tubing or casing string in much the
If a jointed slick liner (without collars) is to be run same way as a rig does. A power tong is required to make
underbalanced, the injector head can be used to snub the up the connections.
liner into the well. The length of liner being run will be limited
by the CT and injector head maximum pull capacities. The liner or casing string can be run and made up, floating
i.e. partially empty to limit its hanging weight.
If a conventional jointed liner with external collars is to be
run, it will be deployed with a wireline lubricator and the To run a liner we need to consider the weight of the total
capacity of the wire line will limit the weight and therefore weight of the string (comprising the liner string, liner
the length of the liner. hanger, running tool, and drill collars to provide weight to
push the liner around the build up if it is a directional well).
Coiled tubing liners are run as normal CT using the
appropriate size of coiled tubing and well control equip- A conventional CT logging deployment technique is used
ment. to make up the connection between the stripper and the
well head after the CT connector has been connected to
Installing a production string the liner string i.e. the liner string is hung off in the BOP
rams and the CT connector is made up to the liner. The
A production string will only be required on CTD operations skate pressure is released to allow the injector head to be
not performed through the production tubing. Either a CT stripped over the CT until the BOP/stripper connection can
completion string is run and the CT unit used to run it under be made up. Once all connections are made up and tested,
pressure or a conventional jointed tubing production string the string weight is picked up and the liner released from
is run by a snubbing unit. the BOP ready to RIH.

The maximum CT completion size is currently 3-1/2-in. Substructure with jacking system
Transportation and handling of 3-1/2-in. CT strings can be
logistically difficult offshore and onshore. It is likely that Dowell has designed and built three different types of
the majority of CT completion strings will be limited to 2- jacking systems to run or pull wellbore tubulars without the
7/8-in. or 2-3/8-in. requirement for a mast. Both systems include a substruc-
ture and a set of snubbing jacks. The jacks operate only

Page 27 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

with downward loading, i.e., they do not have any snubbing 4.1 Rigs and Structures for CTD
capability.
Coiled tubing drilling is performed with the support of
The Hydra-Rig or Kremco systems have two jacks with a conventional rotary rig masts and substructures, and with
160,000 lbf pull capacity and an 11 ft stroke. The Hydra Rig specially designed substructures and jacking systems
system can only be used with 7-1/16-in. or smaller BOPs. developed for CTD. For obvious reasons, substructures
designed specifically for CTD offer the greatest potential
The third system built by Dreco has four jacks with a for efficient CTD operations.
200,000 lbs pull capacity and an 8 ft stroke. The system
can be used with an 13 5/8-in. BOP stack and is the best 4.1.1 CTD Substructures and Jack Systems
suited system for drilling applications.
On specialized CTD rigs, the functions of the draw-works,
These substructures accommodate a tubing power tong to crown block, travelling block and drilling line are replaced
make up or break the tubing connections. Single joints of by the injector head and jacking system . The rotary table
tubing are handled by the CTU crane. Both systems also function being replaced by a downhole motor.
allow the injector head to be skidded off the well when
running or retrieving the BHA. 4.1.2 Location Requirements

4 SURFACE EQUIPMENT New wells

The type of application, location and complexity of the The location is typically required to be as small as
operation will determine which items of surface equipment possible, currently 25m x 32m (Fig. 14) is the minimum
are specified and then selected. The principal components foot print of a CTD rig. A conductor pipe must be driven
required to complete most CTD projects can be catego- prior to the rig mobilization. A small cellar around the
rized as follows. conductor will help collect mud and water spills when
tripping.
• CTD substructure or rig
The wellsite requires minimal preparation, basic grading
• CT equipment and levelling generally being sufficient. Provision for guy
cable anchor points may be required (depending on the
• Well control equipment configuration of the selected equipment).

• Pumping equipment Re-entry wells

• Mud storage and treatment equipment The location has already been established and is generally
larger than is required.
• Pipe handling equipment
Offshore wells
• Ancillary surface equipment
The selection and placement of CTD equipment is con-
• Monitoring and recording equipment strained by the space and handling capability of the rig
(semi) or platform. Tender assisted operations can sim-
• Safety and emergency equipment plify equipment placement. Basic considerations for off-
shore location planning include the following:
• Rig camp and wellsite facilities
• Exact dimensions of available space, including details of
areas effected by zoning requirements (e.g., Zone I or II).

Page 28 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

• Deck load capacities, including location of load bearing 4.3 Well Pressure Control Equipment
beams or restricted areas.
• BOP size and pressure rating – the BOP size or bore
• Details of the crane capacity and boom extension depends on the hole or planned completion size. Two
capability. BOP sizes commonly used are 4-1/16-in. and 7-1/16-in.
In special cases 11-in. BOPs are used. For most CTD
4.2 CT Equipment Package applications, a 5,000 psi pressure rating is adequate but
the operating pressure rating must exceed the expected
• Coiled Tubing – for new and directional wells, CT sizes bottom hole pressure.
of 1-3/4, 2 or 2-3/8-in. are required. A wall thickness of at
least 0.156-in. manufactured from 70,000 or 80,000 psi • 4-1/16-in. 10,000 psi quad-ram BOP– standard for CTD
yield strength material is recommended. operations (Fig. 16).

For sidetracks, determine the optimum size, wall thick- • 7-1/16-in. ram BOP – found in single or double, shear/seal
ness and yield strength through simulation. For simple or ram configurations. The shear rams can shear the 3-
well deepenings 1-1/2-in. CT can be used in certain in OD BHA components.
circumstances.
• Annular BOP/CT stripper – for CTD, the only function of
• Injector Head – for new and directional wells, a minimum this BOP is to close on the BHA when tripping the BHA
of 60,000 lbf pull capacity is recommended. For well or on the liner if a double ram BOP is to be used.
deepening a 40,000 lbf capacity injector head may be Alternatively, an accepted drilling practice is to drop the
used if conditions allow. A 72-in. radius gooseneck is BHA in the hole in case of a kick while tripping the BHA.
required for 1-3/4-in. and larger CT. However, local regulatory agencies generally ask for one
annular BOP. Annular BOPs are available in 4 -1/16 and
• Reel – the reel capacity (string length) and weight should 7-1/16-in. sizes.
be confirmed. A reel core expander may be required for
1-3/4-in. and larger CT. • Kill line – used to kill the well by pumping through/down
the annulus.
• Powerpack – If nonstandard equipment (e.g., high capac-
ity injector head) or auxiliary equipment is to be powered • Choke line – used to divert the flow to the choke manifold
by the CTU powerpack, confirmation should be made while controlling a kick and choking wellbore returns.
that the output of the power pack is adequate and that the
pressures and flowrates are compatible. • Choke manifold – pressure rating must be consistent with
the BOP rating. The manifold must be a drilling type
• Crane – for onshore operations, an independent crane choke manifold with two manual chokes and one pres-
truck is preferred to an integrated crane CTU trailer. sure gauge (some applications may require a remote
Boom length must be sufficient to handle a 40 ft pipe/ operated choke). This equipment is as important as the
BHA over the substructure. BOP for the rig safety (Fig 15).

• Wireline (for directional drilling with wireline) – A mono- or • Mud return line – normally not part of the well control
hepta-cable may be required depending on the operating equipment but when using two BOP stacks, the mud
system involved. return must be closed if it is necessary to shut in the well.
This is achieved with a remote operated valve installed
The CTL reel will be equipped with normal reel collector and on the outlet of the mud return mud cross.
pressure bulkhead equipment.
• BOP controls and instruments – the stripper and BOP are
controlled from the CT unit control cabin.

Page 29 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

Approx 30m

Tubular storage
1 2 15m

Crane
Cabin Zone II

Pump Unit

Approx
Access Coiled Tubing Unit 18m

Mud
Water Mixing Mud

Figure 14a. Typical CTD equipment and location layout – minimum footprint

Approx 32m
Tubular Storage

7 Cabin 8
Crane

15m
Cabin Pump Unit Zone II

Approx
Access Coiled Tubing Unit
25m

9 Mud Treatment 3
6
4 5

1 2 Store Water Dry Mud Store

Figure 14b. Typical CTD equipment and location layout – heavy set up

Page 30 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

For the 7-1/16-in. BOPs and the remote operated valves on A mud-pump stroke counter and a flow meter fitted on the
the mud return or choke lines, the control position is mud return line can also provide adequate data for flow
located on the accumulator or Koomey unit that must be comparison. The outputs of both devices plotted versus
positioned next to the CTU cabin. Remote controls be- time can give a reasonable indication. However, an as-
tween the Koomey unit and the CTU BOP command panel sumption of constant pump efficiency must be made. A
can be adapted if necessary. variety of flowmeters are available for this application. A
low-pressure electro-magnetic flow meter can be used on
4.4 Kick Detection Equipment the return line.

When drilling overbalanced, rapid detection of kicks or 4.4.2 Mud Tank Level Monitoring
losses is essential in slimhole drilling applications. There
are two common methods used in kick detection systems. While in principal this system is simple, it is only efficient
Both have advantages and disadvantages when used in if the tank section is small enough to enable a small
CTD operations. volume variation to be detected. An accurate monitoring
and recording system is needed to provide a suitable
• Flow comparison (flow in vs. flow out) display. A general trend versus time display format is
required, a digital display is not sufficient.
• Mud tank level monitoring
4.5 Mud System
4.4.1 Flow Comparison
4.5.1 Mud Tanks
One of the best ways of detecting a flow variation, is to
have a flow meter on the pump suction and one on the There are three types, or functions, of mud tank, i.e.,
wellbore return line. The flow difference is monitored and settling, active and reserve. Additional tankage or storage
recorded versus time. A flow increase indicates a kick, facilities may be required for water (Fig 17).
while losses are indicated by a drop in flow difference.
Settling tank
Inlet
(Wellbore returns) This is the first tank through which the wellbore returns
pass. The shale shakers (where fitted) will normally be
Choke Choke located above this tank. An overflow system from the
settling tank passes to the active tank. The settling tank
volume is typically 10 to 15 BBL for 2 to 3 bbl/mn flow rates.
A large (butterfly) valve is generally fitted to the base of the
Pressure tank to allow easy removal of the accumulated solids.
Buffer gauges Buffer Active tank
chamber chamber
The active, or suction, tank stores the drilling fluid and
supplies the mud pump suction. If continuous treatment or
additive is required it may be added to this tank. The tank
volume is generally around 50 BBL for 2 to 3 bbl/mn flow
rates. This allows a mud volume buffer to help stabilize the
mud characteristics. Smaller volume active tanks may be
used, however, key fluid parameters such as viscosity and
Outlet density can vary quickly if the mud volume is small.
(To pits or dump line)
The active tank suction is manifolded to allow recirculation
Figure 15. Choke manifold configuration. and precharging of the high-pressure pump. In addition to

Page 31 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

Stripper
Stripper
Mud cross with
Mud cross with manual manual valve fitted
valve fitted
Annular BOP

4-1/16-in. Quad BOP

4-1/16-in. Quad BOP

Choke line
Kill line to
with
mud pump
manual and Choke line
Kill line to
remote Casing spool with
mud pump
valve fitted manual and
remote
valve fitted Casing spool

Figure 16a. Typical well control equipment configurations – for hole sizes up to 4-in.

Page 32 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

Stripper

4-1/16-in. Quad BOP

Stripper
Mud cross with manual
Deck/floor level
valve fitted

7-1/16-in. Annular BOP Mud cross with manual

and remote valve fitted

7-1/16-in. Shear/
seal BOP 7-1/16-in. Annular BOP
7-1/16-in. Pipe/
slip BOP 7-1/16-in. Shear/
seal BOP
Casing spool
Casing spool

Figure 16b. Typical well control equipment configurations – for hole sizes 4-1/16-in. to 6 3/4".

Page 33 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

the recirculation line, a tank agitator is required to maintain • Vacuum degasser – creates a partial vacuum in a closed
the homogenity of the fluid. tank to knock out remaining gas. This system requires
an additional centrifugal pump. Generally the two sys-
Reserve tank tems are combined for maximum efficiency.

The reserve tank(s) are used to store a reserve of drilling Three phase separators
fluid and also provide a facility for mud treatment or
preparation. Ideally, the reserve mud volume should be On underbalanced CTD operations, the mud returns are
equal to the hole volume plus the active and settling tank directed to the choke manifold then to a conventional
volumes. However, this may be reduced if the well type three-phase production separator. The separated gas, oil
(exploration or development), downhole pressure or risk of and solids are then routed to disposal, production or
losses allow. Approximately half to one third of this volume storage facilities. The gas is either flared or sent to the
can be provided in re-entry of depleted reservoir wells. production line. The oil is either sent to the production line
Similar to the active tank, the reserve tank should be fitted or stored for later hauling. The residual solids are removed
with a recirculation and agitation system to allow condition- either periodically or upon completion of the project.
ing of the mud.
4.6 Pumping Equipment
4.5.2 Mud Treatment Equipment
4.6.1 Low Pressure Pumping Equipment
Shale shaker
Low-pressure pumping equipment is necessary for trans-
A shale shaker is necessary for exploration wells to get rid ferring, mixing and conditioning the drilling fluid. In addi-
of the large cuttings produced in the top hole section and tion, the high-pressure pumping equipment requires low-
to collect cuttings for geological analyses. pressure charge pumps to operate efficiently. An adequate
pre-charge system is especially important if kick monitor-
CTD operations on re-entry wells often do not require shale ing equipment is reliant on the pump stroke counter for fluid
shakers because of the very small cuttings generated by inflow data.
the high-speed bit/motor combinations. Short well
deepenings, can generally be performed without a shaker. A low-pressure manifold system is typically used with two
low-pressure pumps to enable flexibility and redundancy
Centrifuge (Fig. 17). The fluid mixing system typically comprises a
hopper and jet mixing system supplied by fluid from a
The centrifuge is an essential item for most CTD applica- centrifugal pump.
tions except short well deepening and shallow new wells.
The centrifuge removes very fine cuttings and avoids their 4.6.2 High Pressure Pumping Equipment
recirculation, which would in time increase the drilling fluid
density. Any uncontrolled variation in fluid density and The high-pressure pump specifications depend largely on
solids content can increase the risk of sticking or wellbore the hole depth and diameter. For holes smaller than 4-3/4-
instability. in., it is unlikely the pressure will exceed 5,000 psi and a
flowrate of 2.5 BPM. For larger holes, typically vertical
Gas Separation System exploration wells, the flow rate may be up to 6 BPM. Some
redundancy in pumping equipment and capacity is gener-
Two types of mud degassing equipment is commonly used ally required.
(similar to conventional drilling operations).
A high-pressure pump remote control panel is generally
• Poor boy degasser – located on the mud return line, it installed in the CTU cabin. This is necessary to alter or
knocks out gas using a system of baffles. The resulting stop the pump flowrate for tool operation or orientation. In
gas is vented from a stack designed to route gas away addition, close control of the CTU and pumping equipment
from work areas. is necessary if the downhole motor stalls.

Page 34 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

High-pressure piping and manifolding is generally as- 4.9 Ancillary Surface Equipment
sembled from 2-in. treating line, chicksans and the neces-
sary valves and accessories. • Substructure – used as a drill floor when tripping the BHA
and as a support for the injector head when drilling or
4.7 Monitoring & Recording Equipment tripping the CT.

• Conventional CTU monitoring equipment – required to • Generator – provides electricity to the portacabins, the
record the string cycle and pressure data for analysis. A flood lights, the centrifuge, the monitoring equipment,
tubing monitoring device (OD/ovality) should also be the BOP accumulator unit etc.
regarded as critical monitoring equipment.
• Electrical distribution panel – provides electrical connec-
• Other monitoring recording systems provide real time tion between the generator and the various electrical
acquisition, recording and display of the data from a devices with all necessary breakers and safety features.
variety of sensors. It provides the CT operator with digital
display or plots versus time through bar charts or strip • Flood lights – to provide lights for safe and efficient
charts on a monitor in the CTU cabin and also allow data operations at night.
analysis in the CTU or in an office. It makes the CTD job
safer (kick detection) and drilling more efficient (all • Air compressor – provide air to start the CTU engine if the
parameters displayed versus time, show to the CT tractor is not on location, or provide compressed air as
operator the trends, rate of penetration etc). needed.

4.8 Pipe Handling Equipment • Miscellaneous – cutting torch and welding machine:

This pipe handling equipment is used for handling jointed 4.10 Safety and Emergency Equipment
pipes e.g. drill collars, tubing joints, casing joints etc.
• Emergency kill – emergency kill on the CTU engine and
• Tubing spider slips – used to hold the BHA or jointed pump engines.
tubing when making up or breaking two joints.
• Fire fighting equipment – CO2 fire extinguishers on CTU
• Elevators – used to handle single joints of DC or tubing power pack, pumping unit power pack, near the
or casing. portacabins, near the fuel tank.

• Safety clamps – used as a safety device to prevent the • H2S protective equipment and gas detection equipment–
string from falling into the hole, if the slips do not hold and generally provided by the operator.
the string slides.
• Eye wash station – located next to the mixing facility with
• Tubing power tong – used to make up or break the BHA, a precharged tank filled up with treated water.
casing or tubing connections at the proper torque.
• Mud handling protective equipment – apron, goggles,
• Crane – used to handle single joints of BHA, casing or long sleeve gloves for chemical handling.
tubing. If necessary, it may be used to handle/run the
whole BHA or casing string if within the crane capacity. • First aid kits.

• Substructure and jacking system – used to pull or run a 4.11 Equipment and Consumables Checklists
whole casing or tubing string. Has a 170,000 lbs pulling
capacity–single joints are still handled by the crane. The checklists shown in Fig. 18 through Fig 19 are
intended as a guide for the compilation of checklists for
specific operations.

Page 35 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

Centrifuge
Centrifugal
Pump

Active Triplex
Wellbore returns Pump

Shale shaker

Reserve
Settling
Tank
Solids
sampling
and disposal
Water

Mixing Centrifugal
Hopper Pump

Figure 17a. Typical configuration of drilling-fluid equipment – overbalanced operations.

Wellbore returns Centrifuge

Centrifugal
Pump

Choke
Vacuum Triplex
manifold Active
degasser Pump

Three phase Reserve

separator

Gas to flare or
production Water
Mixing Centrifugal
Hopper Pump
Oil to production
or storage

Figure 17b. Typical configuration of drilling-fluid equipment – underbalanced operations.

Page 36 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

5 DOWNHOLE EQUIPMENT • Torque developed by the motor (high torque motors are
recommended)
The downhole tools and equipment required for any CTD
project is dependent on the complexity and specific • RPM of the motor
conditions under which it is to be completed. Most tools
and equipment used in association with CTD may be • Available WOB
summarized in the following categories.
• Drilling fluid type and flow rate
• Bits
Experience in a particular area/formation is the best basis
• Downhole motors for recommendation of bit/motor combinations.

• Downhole CT equipment 5.1.1 Rock Bits

• BHA for vertical well or well deepening Rock bits or tricone bits have three rollers with bearings
-Drill collars that can be sealed or non sealed i.e. mud lubricated. There
are two main categories, steel tooth bits and insert bits.
• Directional drilling BHA Both are available in different tooth design to drill very soft
- MWD or WL steering tool to very hard formations, the insert bit life is generally longer
- Monel, UBHO and it is more expensive than the mill tooth bit.
- Orienting tool
Roller cone bits operate by crushing, gouging and deform-
• Special BHA components ing the rock (Fig. 20) with the drilling efficiency being
-Drilling jars dependent on the weight-on-bit (WOB). Rock bits or
-Thruster tricones are designed to turn at relatively low speed
-Underreamer (generally not more than 150 RPM) and are not reliable for
diameters smaller than 4-3/4-in. The risk of losing cones
• Fishing tools is high, especially when used in small diameters and with
-Overshots high RPM.
-Fishing jars, spears
-Magnets, junk catchers 5.1.2 Drag Bits

5.1 Bits Drag bits do not have any bearings or rotating parts and are
designed to cope with the high RPM of the downhole
Depending on the hole diameter, two kinds of bits are motors. Two main types of drag bits are used: PDC bits
typically used. For 4-3/4-in. holes and larger, rock bits, (Polycrystalline Diamond Compact) and TSP bits (Ther-
tricones or drag bits are used. For holes smaller than 4-3/ mally Stable Polycrystalline).
4-in., drag bits are generally used.
PDC bits operate by shearing rock material much like the
The motor/bit combination for any application is critical action of a machinists tool on a lathe. TSP bits have a
and can drastically change the rate of penetration (ROP). similar cutting action, but are more tolerant of heat so are
The use of small downhole motors developing high RPM suitable for harder formations. However, the TSP bit
and little torque makes the drag bit selection difficult and cutting surface is significantly smaller than the PDC
it is recommended that selection is made by consulting bit cutter, consequently penetration rates are typically less.
manufacturers with the following information. In general, drag bits operate more efficiently with less
WOB than roller cone bits but are more sensitive to rate of
• Formation type, hardness and abrasiveness rotation.

Page 37 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

COILED TUBING DRILLING EQUIPMENT CHECKLIST

Offshore Onshore Short Well Other Provider

Wells Wells Deepening Wells (guide only)

Coiled tubing equipment

CTU control cabin X X X X Serv.Co.
CTU Power pack X X X X Serv.Co.
CT injector head X X X X Serv.Co.
CT reel X X X X Serv.Co.
Jacking frame As required a/r a/r a/r Serv.Co.
Crane As required a/r a/r a/r Serv.Co.client

Well control equipment

BOP – Ram X X X X Serv.Co./rental
BOP – Annular X X X X Serv.Co./rental
Wellhead adapters X X X X Serv.Co./rental
Mud cross X X X X Serv.Co./rental
Riser and/or spacer spools X X X X Serv.Co./rental
Accumulator unit X X X X Serv.Co./rental
Choke manifold X X X X Serv.Co./rental
Flowmeters X X X X Serv.Co.
Pit/tank level indicators As required a/r a/r a/r Serv.Co./rental

Drilling fluid equipment

CTD mud treatment unit n/a If available - X Serv.Co.
Alternative equipment– Serv.Co.
Remote controlled pump unit X X X X Serv.Co.
Settling tank X X X X Serv.Co.
Active tank (with paddle agitators) X X X X Serv.Co.
Reserve tank As required Serv.Co.
Centrifugal pump and power pack X X X X Serv.Co.
Low pressure mixing hopper X X X X Serv.Co.
Pump unit (standby) As required Serv.Co.
Drill water tank n/a X As required X Serv.Co.
Centrifuge X X n/a X Serv.Co./rental
Cuttings bin X X X X Serv.Co./client
Flareline As required Serv.Co./client
HP filter screens (Slim1) X X n/a As required Serv.Co.
Three-phase separator As required a/r a/r a/r Serv.Co.
Vacuum degasser As required a/r a/r a/r Serv.Co.

Pipe handling equipment

Jacking substructure As required a/r a/r a/r Serv.Co.
Power tong X X X X Serv.Co./rental
Spider slips X X X X Serv.Co./rental
Elevators and clamps X X X X Serv.Co./rental
Lifting sub(s) X X X X Serv.Co./rental

Figure 18a. Coiled tubing drilling equipment checklist.

Page 38 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

COILED TUBING DRILLING EQUIPMENT CHECKLIST (continued)

Offshore Onshore Short Well Other Provider

Wells Wells Deepening Wells (guide only)

Ancillary surface equipment

Substructure (if jacks not used) As required X X X Serv.Co.
Fuel tank and pump n/a As required - - Serv.Co.
Generator As required a/r a/r a/r Serv.Co.
Electrical distribution panel X X a/r a/r Serv.Co.
Cabin(s) (furnished) X X a/r -a/r Serv.Co.
Potable water tank As required X a/r a/r Serv.Co.
Lighting As required a/r a/r a/r Serv.Co.
Air compressor As required a/r a/r a/r Serv.Co.
Steam cleaner X X a/r a/r Serv.Co.
Location mats - As required a/r a/r Client

Monitoring and recording equipment

CTU monitoring system X X X X Serv.Co.
BHA associated monitoring X X X X Serv.Co.
Multi channel recorder X X X X Serv.Co.
Flowmeters X X X X Serv.Co.
Fluid parameter device X X X X Serv.Co.
Tubing integrity device X X X X Serv.Co.

Safety equipment
Emergency engine kill X X X X Serv.Co.
H2S safety equipment As required a/r X X Serv.Co.
Gas detection/monitoring equipment X X X X Serv.Co.
Fire extinguishers X X X X Serv.Co.
Sewage system (cabins) n/a As required - - Serv.Co.
Eye wash station(s) X X X X Serv.Co.

Casing/liner running equipment

Elevators and clamps As required a/r Serv.Co.
Casing or liner joints As required a/r Client
Casing shoe or float As required a/r Client
Liner hanger As required a/r Client
Running/setting tool(s) As required a/r Serv.Co.
Drill collars As required a/r Serv.Co/rental
Drop ball sub a/r Serv.Co.

Figure 18b. Coiled tubing drilling equipment checklist.

Page 39 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

COILED TUBING DRILLING CONSUMABLES AND MISCELLANEOUS SERVICES CHECKLIST

Vertical Short Well Sidetrack Provider

Well Deepening Well (guide only)
Equipment spares and consumables
Pump parts X X X Serv.Co.
Shaker screens X X X Serv.Co.
Mud unit sparts X X X Serv.Co.
CTU parts X X X Serv.Co.
Well control equipment parts X X X Serv.Co.
Fuel, oils and lubricants X X X Serv.Co.

Drilling consumables

Drill water X X X Client

Potable water As required a/r a/r Client
Diesel Client
Mud products Serv.Co./client
LCM As required a/r a/r Serv.Co./client
Cement (and additives) As required a/r a/r Serv.Co.
Bits X X X Serv.Co./client
Core bits As required a/r a/r Serv.Co./client

Logistics

Vehicles for crew Onshore only Serv.Co.

Helicopter or crew boat Offshore only Client
Consumables haulage X X X Client
Vacuum truck Onshore only Client
Cuttings disposal X X X Client
Radio communications As required Client

Sidetracking equipment

Whipstock - - As required Serv.Co./Vendor

Whipstock anchor - - As required Serv.Co./Vendor
Setting tool (s) - - As required Serv.Co./Vendor
Gyro/survey equipment - - As required Serv.Co./Vendor
Mill(s) - - As required Serv.Co./Vendor
Low-speed motor - - As required Serv.Co./Vendor

Logging tools and service

CCL (for sidetrack KOP) Serv.Co.

CBL (for sidetrack KOP) Serv.Co.
Other services as required Serv.Co.

Figure 19. Coiled tubing drilling consumables and miscellaneous services checklist.

Page 40 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

Some drag bits, and all rock bits, are equipped with • Maximum pressure drop – when a motor is operated off-
tungsten carbide nozzles that are interchangeable and bottom, a certain pressure loss is required to turn the
available in different diameters. The nozzles create a jet rotor. This pressure loss and RPM is proportional to flow
impact onto the formation and help clean the bottom of the rate. A typical no-load pressure loss is ±100psi for motors
hole. Most small drag bits do not have nozzles but have used in CTD applications.
ports which give a jetting effect (Fig. 21).
As WOB is applied, the pressure required to turn the rotor
5.2 Downhole Motors will increase. This increase in pressure is generally called
the motor differential pressure (Pressure on-bottom –
There are three types of dowhhole motor; turbines, vane Pressure off-bottom). The motor torque-output is directly
motors and positive displacement motors. proportional to the motor differential pressure. For a
typical 3-1/2 or 2-7/8-in multi-lobe motor the pressure drop
• Vane motors – there is limited experience with this type across the motor can be 500 psi or more.
of motor. Currently, only one manufacturer continues to
develop vane motors (Volker Stevin).

• Turbines – not yet available in small diameters.

• Positive displacement motors (PDM) – available in all

sizes but especially small diameters.

5.2.1 Positive Displacement Motors Crushing or

gouging action
The basic specifications for PDMs relate to the following
criteria.

• OD – the size of a motor has a direct bearing on most of

the other criteria, e.g., larger motors output greater
torque and require a greater flow rate (Fig. 22).
Figure 20. Rock bit cutting characteristis.
• Number of stages (stator and rotor lobes) – the number
of stages define the type i.e. low or high speed (Fig. 23).
In general, for a given size of motor, the greater the
number of lobes, the higher the motor torque and the
lower the output RPM.

• Maximum flow rate – each size of motor is designed to

operate within a specific throughput volume of fluid.
Multi-lobe motors typically have a wider flow range with
Aggressive
a higher maximum allowable flowrate. This can be an
shearing action
important consideration which effects the hole cleaning
ability for a given bit/motor combination.

The flow rate through motors is frequently used to

characterize performance, e.g.,

• RPM versus flow rate.

• Operating torque versus flow rate. Figure 21. PDC bit cutting characteristis.

Page 41 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

• Differential pressure at max operating torque – the power • Large motors (4-3/4-in.) – the maximum stall torque plus
output curve of a PDM is parabolic (Fig.24). Although the a 30% safety margin should be less than 80% of the
operating characteristics of the motor will change with maximum allowable torque of the CT string.
"operating hours" the same general performance profile
will be maintained. All motors have a maximum recom- 5.3 CTD Downhole Equipment
mended differential pressure. At this point, the optimum
torque is produced by the motor. CT Connectors

• Maximum stall torque – if the WOB is increased suffi- After performing several jarring and pull tests of various
ciently to cause the motor differential pressure to rise type CT connectors, it is recommended that a grub screw
above the maximum recommended, a stall is likely. At connector be used for CTD applications.
this point, the stator distorts allowing some passage of
fluid without turning the rotor, i.e., the drilling fluid flows Disconnecting subs
through the motor without turning the bit. A sharp pres-
sure increase will result, and no variation will be evident For CTD applications in large vertical hole (6-in. or greater),
as further WOB is applied. The motor is stalled and a pull disconnect release is recommended.
severe damage will result if pumping continues.
In re-entry wells or deep vertical wells, pull disconnects
Other specifications like maximum overpull and maximum (such as Griffco) are not recommended due to very limited
WOB are generally not limiting parameters for CTD appli- overpull margin it allows because of the drag.
cations.
Wireline steering tool BHAs can include an electrically
Recommendations regarding the selection of PDMs in- operated disconnect, or a tension/pull disconnect with a fail
clude the following. safe system incorporated.

• OD – select the largest possible motor size. Check valves

• RPM – select a low-speed high torque motor for slim Double flapper valves should be used on top of the pressure
holes, with the highest maximum torque rating for the disconnect in case of disconnection in a kick situation
given size. A high flow-rate is desirable to ensure (even if a float valve is installed on top of the motor).
adequate hole cleaning.

TYPICAL PDM SPECIFICATIONS

Hole size 6-in. to 7-7/8-in 4-3/4-in. to 5-5/8-in. 3-1/2-in. to 4-1/8-in.

Motor OD (Nom in.) 4-3/4 3-1/2 2-7/8
Motor type Low High Very Low Low High Low High
Speed Speed Speed Speed Speed Speed Speed

Maximum RPM 140 to 250 350 to 450 170 400 600 to 700 400 800
Operating torque (ft/lbf) 1500 950 700 500 300 300 200
Flowrate (gpm) 250 250 110 110 100 100 100
Max differential pressure (psi) 350 500 400 500 700 500 700

Figure 22. Typical PDM specifications.

Page 42 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

1:2 5:6

7:8 9:10

Single lobe motor Multilobe motor

configuration configuration
1:2 5:6

Figure 23. Typical PDM stator/rotor configurations.

Page 43 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

There are no drill collars in this BHA. The weight on bit is

provided by CT string, part of which will be in compression.
Motor stall starts
A typical CTD BHA for drilling deviated wellbores will
Horsepower

include the items shown in Figure 26.

Rapid increase in 5.4 Principal Components of a Directional BHA

pressure
Directional BHA used for CTD are also called steerable
systems. A steerable system provides the directional
drilling engineer with data to enable information relating to
Total stall the tool face, wellbore inclination and azimuth to be
monitored and recorded. By combining this information
Pump pressure with the measured depth of the wellbore, the progress of
the wellbore can be compared, and if necessary correc-
Figure 24. Typical PDM performance curve tions to the planned wellbore profile, can be made by
changing the toolface i.e. the relative position of the bent
housing to the low (or occasionally high) side of the
5.3.1 BHA For Vertical Wellbores wellbore.

The BHA required to drill vertical wellbores comprises Two steerable systems are commonly used in CTD appli-
conventional components, the larger versions of which are cations:
commonly used in conventional rotary drilling applica-
tions. • Wireless steerable BHA including a measurement while
drilling (MWD) tool.
A typical CTD BHA for drilling vertical wellbores will include
the items shown in Figure 25. • Wireline steerable BHA including a wireline steering tool

Drill collars are used to provide the weight on bit (WOB), MWD Tool/System
with the CT being kept in tension at all times. This creates
a pendulum effect which, in the majority of circumstances The MWD tool sends data to surface by inducing coded
will maintain a vertical wellbore. Spiralled drill collars are pressure pulses in the drilling fluid being pumped through
recommended to minimize differential sticking–especially the CT string. The signals recovered at surface are
for slide drilling applications. The selection of drill collars decoded and displayed using a PC.
of the appropriate size (OD) is dependent on the bit/hole
size. The following recommendations are made. A schematic diagram illustrating a MWD system is shown
in Figure 27.
Hole size Drill Collar OD
>6-in. 4-3/4-in. The principal advantage of the MWD system is the
3-3/4 to 4-3/4-in. 3-1/8-in. absence of wireline and electrical connections which are a
<3-7/8 2-7/8-in. potential source of problems.

5.3.2 BHA for Deviated Wellbores The disadvantage of the MWD system is the slow data
rate, i.e., one tool face every 30 seconds, one survey
The BHA required to successfully drill deviated wellbores (inclination and azimuth) every 30 minutes. However this
contains several specialized components which, in most is generally sufficient to control the trajectory of a CTD
cases, have been specifically developed for CTD applica- wellbore. Since the downhole components are sensitive to
tions. debris within the drilling fluid, it is generally necessary to

Page 44 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

CT String CT String

CT connector CT connector

Dual check valves

Check valves

Release joint
Release joint
Steering/orienting tool

Drill collars
Drill collars housing
survey and data ac-
quisition tools

Motor

Motor with bent housing

Drill bit Drill bit

Figure 25. CTD BHA for vertical wellbores. Figure 26. CTD BHA for deviated wellbores.

use a high pressure filter system. This is typically located Some operating conditions, e.g., drilling with foams and
adjacent to the reel manifold. gaseous fluids, preclude the use of MWD systems since
pressure pulses are absorbed by the fluid column. In such
Wireline Steering Tool circumstances the wireline steering system and associ-
ated toolstring must be used for directional control.
Wireline steering tools are basically the same type of tool
as MWDs but data is transmitted to surface through a Monel – Nonmagnetic Drill Collar
wireline. The advantage being the high data rate which
provides almost real time measurement. However, the A non magnetic tubular is required to house the steering
number of electrical connections required presents a tool assembly. This typically comprises two 15 ft sections
number of potential problems (Fig. 28). of 3-in. OD drill collar made of non magnetic material to
limit magnetic interference.

Page 45 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

Data transmitted by pressure

pulse telemetry

Coiled tubing

Upper CT BHA

Nonmagnetic housing
for MWD
Pressure transducer
on reel manifold

MWD assembly
Fluid pumps

Data processing and display

of directional information

PDM with bent sub

Remote display/monitoring or
Bit recording

Figure 27. MWD system schematic diagram.

Page 46 of 48
 COILED TUBING SERVICES MANUAL Section 380
COILED TUBING DRILLING Rev A - 98

Data transmitted through

wireline inside CT string

Pressure bulkhead - electrical

Coiled tubing access to tubing
Upper CT BHA Components within reel
core and on reel axle
Nonmagnetic housing Reel collector - electrical
for MWD access to rotating reel

MWD assembly

Fluid pumps

Data processing and display

of directional information

PDM with bent sub

Bit
Remote display/monitoring
or recording

Figure 28. Wireline steering system schematic diagram.

Page 47 of 48
 Section 380
COILED TUBING SERVICES MANUAL
Rev A - 98 COILED TUBING DRILLING

Orienting Tool Drilling Jars

An orienting tool is necessary to change the orientation of It is recommended that drilling jars are included in a CTD
the tool face. The MWD system incorporates an orienting BHA if there is a risk of sticking through formation
tool which rotates in 30° increments. This tool can only be instability of differential pressure.
used with a wireless steering system. Similar orienting
tools are available to be used with wireline steering tools. Underreamers
They generally provide a low torque, with the toolface
correction being made off bottom. There are two common conditions in which underreamers
enable a larger hole to be drilled. In through tubing applica-
Three main types of orienting tool are currently available tions where a fixed restriction limits the bit size, and in
conventional applications where the CT string cannot
• Pump actuated orienting tools provide the necessary WOB. It is not generally recom-
mended that drilling and underreaming are undertaken at
• Electrically operated orienting tools the same time. Instead, it is preferable to drill a pilot hole
which is then underreamed to the desired size.
• Hydraulically operated orienting tools
The underreamer is positioned in the BHA above the bit or
Pump actuated orienting tools bullnose.

The key component of pump operated orienting tools is an Thruster

indexing assembly which is actuated by shutting down the
pump, then resuming circulation. Each cycle causes the Thrusters were developed to avoid the consequences of
lower section of the tool to rotate 30°. the heavy vibration, which is typical of equipment used in
slimhole applications. The thruster dampens vibrations
Electrically operated orienting tools and equalizes the WOB.

A wireline provides electrical power to a DC motor in the Fishing Tools

orienting tool which drives a gear train or a hydraulic pump
to adjust the tool face angle. A selection of fishing tools should be prepared for, or at
least be on stand-by during CTD operations. The nature
These orienting tools provide high torque and allow tool and size of the fishing tools will be dependent on the CTD
face correction while drilling. Alternative tools are oper- BHA to be used and the anticipated downhole conditions.
ated or controlled by electrical or hydraulic systems Fishing tools may be needed at any time, appropriate
through cables or conduits installed in the CT string. contingency plans should be prepared during the well
planning phase of the operation.
•Hydraulically operated orienting tools
A typical fishing tool selection will include the following
A hydraulic orienting tool is operated via hydraulic control items.
line(s) installed in the CT workstring.
• GS fishing tool (or similar) – to suit the fishing neck of the
5.5 Specialized CTD Tools release joint being used.

Float Sub • Overshots and spears – available in a variety of sizes and

configurations to suit the toolstring in use.
The float sub (where fitted) is installed above the motor to
prevent wellbore fluids from entering the BHA and • Junk catchers and magnets – Appropriate precautions
workstring. The internal valve closes in the event of a kick must be taken at all times to avoid the introduction of junk
or underbalanced drilling situation. to the wellbore. In addition, it is recommended to have
fishing tools for small items and junk on site at all times.

Page 48 of 48
 Section 390
COILED TUBING SERVICES MANUAL
Rev A - 98

HYDRAULIC FRACTURING

Contents Page

Introduction .................................................................................................... 2
1 CoilFRAC SERVICE ......................................................... ............................. 2
2 CoilFRAC PROCEDURE ................................................................................ 3
2.1 Coilfrac and Conventional Fracting Treatments ........................................... 4
3 BOTTOMHOLE ASSEMBLY ......................................................................... 5

Page 1 of 6
 Section 390 COILED TUBING SERVICES MANUAL
Rev A - 98 HYDRAULIC FRACTURING

INTRODUCTION Features

Hydraulic fracturing treatments are routinely performed on - Method of stimulating bypassed or marginal zones
oil and gas reservoirs throughout the world. In recent years - Selective placement of proppant
the incentive to develop techniques that enabled the treat- - Reduced wellsite services visits
ment of marginal wells or reservoirs has increased. In - Multiple fracture operations on a single trip
meeting this challenge, CT technology has been success- - Isolation of wellhead and tubulars from treating pressures
fully applied to provide a versatile treatment platform that
performs safely, reliably and economically. The availability Benefits
of larger tubing sizes, necessary to convey the higher fluid
flow rates required for hydraulic fracturing operations com- - Reduced operational cost of the completion process while
bined with the greater understanding of how CT operating optimizing well performance.
limits should be applied, are key factors in this process. - Average total completion time on each well significantly
Parallel developments in fracturing fluid and downhole tool reduced.
technology have enabled the provision of a comprehensive - Access to additional recoverable reserves
service that enables the design and execution process to be
conducted more efficiently. Through these features and benefits, the CoilFRAC Service
provides numerous economic, operational and environmen-
1 COILFRAC SERVICE tal benefits over conventional fracture treatments.

The CoilFRAC* Service combines two important but diverse The first fracturing treatments incorporating CT were per-
oilfield technologies: coiled tubing conveyance and hydrau- formed in 1992. The CT string was hung-off in the wellhead
lic fracturing. The service provides the capability of perform- and sheared before being used to convey the treatment,
ing proppant hydraulic fracturing treatments through a much as conventional tubing is used. Such treatments were
coiled tubing string. This combination adds versatility to the limited to single zone treatments and the CT string was
fracturing operation and provides numerous advantages subsequently used as the production conduit.
over conventional fracturing treatments.

Figure 1. CoilFRAC equipment rigged up at the wellsite.

* Mark of Schlumberger

Page 2 of 6
 COILED TUBING SERVICES MANUAL Section 390
HYDRAULIC FRACTURING Rev A - 98

A B C
Lower zone Intermediate zone Upper zone
treated treated treated

Figure 2. CoilFRAC fracturing principle.

The necessity for inexpensive multiple stage fracturing Excessive fluid friction pressure due to the restricted
treatments was identified for much of the shallow gas well diameter of the CT work string limited the application of
market in Canada. The primary candidates were multiply CoilFRAC techniques to relatively shallow wells (+/- 3000 ft)
perforated wellbores with commingled gas production. The using conventional fracturing fluids. With the introduction of
wells were economically marginal making conventional ClearFRAC, the enhanced rheological properties enabled
treatments uneconomic. An added constraint was the treatments at depths in excess of 9000 ft. An added
limited time available for the completion of each well. The advantage came in the non-damaging nature of these fluids
introduction of CoilFRAC treatments addressed both the that provided the possibility of achieving the desired fracture
time and economic issues by enhancing operational effi- conductivity at lower injection proppant concentrations.
ciency to complete successful fracturing treatments within This also helped maintain treatment pressures within oper-
a short time frame. ating limits.

Additional efficiencies were subsequently obtained through A series of treatments were executed to stimulate by-
the evolution of bottomhole assemblies (BHA) specifically passed pay zones in slimhole completions where signifi-
designed for CT applications. Initially a tension set packer cant productivity increases were achieved.
was used to isolate the wellbore above the treatment zone,
with any zones below being isolated by a sand plug. 2 COILFRAC PROCEDURE

The second generation BHA incorporated a swab cup The basic CoilFRAC procedure has been developed for
assembly that eliminated the need for sand plugs and multi-stage hydraulic fracturing treatments. The lowest is
enabled treatment pressures of up to 4000 psi. An inverted stimulated (Figure 2) and subsequently isolated. The BHA
swab cup above the tension packer provided the isolated is then repositioned at the next interval to be treated. On
interval for accurate treatment. Further development of the completion of each treatment stage, the process is re-
BHA incorporated a straddle packer assembly that in- peated until the entire producing interval has been treated.
cluded swab cup above and below a perforated joint that
enabled treatment pressures to be safely increased to 7000
psi.

Page 3 of 6
 Section 390
COILED TUBING SERVICES MANUAL
Rev A - 98 HYDRAULIC FRACTURING

Several options are available for isolation of lower stimulated - The wellsite rig-up requires additional considerations to
intervals. A sand plug and packer combination may be used safely accommodate the CT operating requirements (Fig-
for treating the lower interval, with subsequent treatments ure 1), including the running and retrieving of the special-
being made as the assembly is moved up the well. ized BHA.

A mechanical bridge plug can also be used in place of the - The surface pump pressure response during CoilFRAC
sand plug (Figure 4). However, the preferred method uses operations is significantly different than that associated
the swab cup assembly to isolate the treatment zone. with conventional fracturing operations due to the smaller
diameter tubulars used (Figure 3).
Minor modifications to the procedure have included ignoring
the need for isolation of the lower zone where the minimum Fluid friction pressure at the treatment rate through the CT
in-situ stress of the lower formation is known to be greater string is higher than the corresponding hydrostatic pres-
than the upper zone to be treated. Such variations should sure. The surface pressure will also increase as the
be applied cautiously and only with a full knowledge of the proppant concentration is increased. This is in contrast to
wellbore and reservoir conditions. conventional fracturing treatments where the larger flow
path results in decreasing surface pressures as the proppant
2.1 CoilFRAC and Conventional Treatments concentration is increased.

CoilFRAC treatments differ from conventional hydraulic

fracturing techniques in two fundamental ways.

Surface pressure
for CT fracturing

Surface pressure
for conventional
fracturing

Proppant concentration

Figure 3. Pressure response comparison between CoilFRAC and conventional techniques.

Page 4 of 6
 COILED TUBING SERVICES MANUAL Section 390
HYDRAULIC FRACTURING Rev A - 98

3 BOTTOM HOLE ASSEMBLY joints. Since the forces required in setting the tension set
packer and safely retrieving the BHA may also act to
In general, a simple tool string configuration is preferred for activate the release joint, the operation must be carefully
CoilFRAC operations. However, specific functions may planned and the release joint configured correctly for the
have to be considered in more complex applications. In all anticipated forces.
cases the following requirements apply.
The swab cup assembly (Figure 4C) is relatively simple,
- The material from which tool is manufactured should be with fewer moving parts, and may include centalizers to
resistant to erosion. reduce eccentric wear of the swab cups while running in
hole and respositioning between treatments.
- The tool string should be full-bore to minimize turbulence
and erosion.

When using the tension-set packer system, a trimmed

tailpipe assembly is recommended to enable the downward
movement necessary to unset the packer. If the wellbore is
full of sand, the tailpipe can penetrate the sand more easily
to enable movement.

To enable contingency release of the tool string in the event

that it becomes stuck, a tension activated release joint
must be used. The risk of residual sand preventing the clear
passage of a ball precludes the use of ball-operated release

A B C
Packer and sand Packer and bridge plug Swab cup straddle
isolation isolation isolation

Figure 4. CoilFRAC isolation options.

Page 5 of 6
 Section 390
COILED TUBING SERVICES MANUAL
Rev A - 98 HYDRAULIC FRACTURING

THIS PAGE INTENTIONALLY LEFT BLANK

Page 6 of 6
 Section 410
COILED TUBING SERVICES MANUAL
Rev A - 98

SAFETY CONSIDERATIONS

Contents Page
Introduction .................................................................................................... 2
1 HYDROGEN SULFIDE GAS........................................................................... 2
1.1 Description .......................................................................................... 2
1.1.1 Toxicity ................................................................................................ 2
1.1.2 Corrosion and Embrittlement ............................................................... 2
1.2 Sources Of H2S .................................................................................. 3
1.3 Identifying H2S Hazards ...................................................................... 4
1.3.1 Planning .............................................................................................. 4
1.3.2 Wells With a Potential to Bear H2S ...................................................... 4
1.3.3 Equipment Selection ........................................................................... 4
1.3.4 Personnel and Location Safety ............................................................ 5
1.4 Breathing Apparatus ............................................................................ 5
1.4.1 Features .............................................................................................. 5
1.4.2 Air Supply ........................................................................................... 5
1.4.3 Face Mask .......................................................................................... 6
1.4.4 Training ................................................................................................ 6
1.4.5 Operation ............................................................................................ 6
1.5 H2S Monitoring Equipment .................................................................. 6
1.5.1 Features .............................................................................................. 7
1.5.2 Personal H2S Monitors ........................................................................ 7
1.5.3 Fixed H2S Monitors ............................................................................. 7
1.5.4 Operation ............................................................................................ 7
2 FALL PROTECTION DEVICES ...................................................................... 8
2.1 Features .............................................................................................. 8
2.1.1 Safety Harnesses ................................................................................ 8
2.1.2 Safety Lines and Lanyards .................................................................. 8
2.1.3 Fall Arrest Equipment .......................................................................... 8
2.1.4 Anchor Points ...................................................................................... 8
2.2 Operation ............................................................................................ 9

Page 1 of 9
 Section 410
COILED TUBING SERVICES MANUALS
Rev A - 98 SAFETY CONSIDERATIONS

Introduction 1.1.2 Corrosion and Embrittlement

Safety aspects and criteria must be identified in the When water and H2S are present together, an acid environ-
planning phase for each operation. Safety considerations ment will result, due to the H2S hydrolyzing slightly in the
may vary according to geographical location and wellsite water. This acid environment in itself may cause a metal-
(e.g. offshore). loss problem; but when combined with the effect of hydro-
gen embrittlement and cracking the result is much more
The safety considerations outlined in this manual should be severe. In the presence of moisture, only a trace of H2S is
regarded as a summary of key points, and not an exhaus- needed to cause hydrogen embrittlement. The embrittlement
tive list. They do not supercede existing standards, policies process, sometimes called sulfide stress cracking (SSC),
or regulations. is not fully understood. It is generally agreed that SSC
results from the penetration of hydrogen atoms into the
1 HYDROGEN SULFIDE GAS lattice structure of high-strength steel alloys. The hydrogen
atom is smaller than the lattice structure and can migrate
Hydrogen sulfide gas presents a major potential hazard to into the structure of the steel. When two hydrogen atoms
personnel and equipment. Planning is required to determine
the risk of encountering H2S, and a plan of action should be
Effects and symptoms of H2S
prepared to protect both personnel and equipment.
ppm H2S Effect or symptom
1.1 Description
1 ppm 1/10,000 of 1%. Can be smelled
Hydrogen sulfide (H2S) gas is a highly toxic colorless gas, 10 ppm 1/1000 of 1%. Occuptational exposure
which is heavier than air and has the odor of rotten eggs. limit. Exposure limited to eight hours with-
This compound of hydrogen and sulfur has several names out a breathing apparatus.
including H2S and sour gas. Oil, gas and other fluids
containing H2S are known as “sour”. The effects of H2S are 20 ppm 1/500 of 1%. At and above this level,
of concern in two main areas: toxicity, and corrosion/ personnel must wear an appropriate breath-
embrittlement. ing apparatus.
100 ppm 1/100 of 1%. Loss of sense of smell in 2 to
1.1.1 Toxicity
15 min. May burn throat, cause headache
and nausea.
The principle route of exposure to H2S is by inhalation. A
high concentration inhaled in one breath attacks the respi- 200 ppm 1/50 of 1%. Sense of smell lost rapidly;
ratory portion of the nervous system and can cause burns eyes and throat.
respiratory paralyses and subsequent death by asphyxia-
tion. Lower concentrations produce irritation of the eyes 500 ppm 5/100 of 1%. Loss of reasoning and bal-
and respiratory tract. Low concentrations breathed for ance. Respiratory disturbance in 2 to 15
several minutes can deaden the sense of smell. Therefore min. Prompt resuscitation needed.
the sense of smell should not be depended upon to detect 700 ppm 7/100 of 1%. Immediate unconciousness,
the presence of H2S. breathing will stop and death will result if
not rescued promptly; immediate resusci-
The following table outlines the effects and symptoms of tation required
H2S poisoning, and identifies the limits at which preventive
action must be taken. Since small concentrations are 1000 ppm 1/10 of 1%. Immediate unconciousness,
significant, only reliable, calibrated monitoring equipment death or permanent brain damage may
should be used to assess H2S levels. result if not rescued and resuscitated im-
mediately.

Figure 1.

Page 2 of 9
 COILED TUBING SERVICES MANUAL Section 410
SAFETY CONSIDERATIONS Rev A - 98

meet within the steel lattice, they combine to form a In the case of coiled tubing, the constant bending and
hydrogen molecule with a resulting increase in size. The subsequent plastic deformation of the tubing over the reel
stress created by this increase in size can part the grains and gooseneck can lead to a work-hardening of the tubing,
of a low-ductility steel structure. Low-strength, high-ductil- thereby lowering its resistance to H2S attack. To increase
ity steels will yield to relieve the stress without failing and, the tubing resistance to H2S attack, the sulfur and nickel
therefore, are more suitable for use in an H2S environment. content of the alloy is kept to a minimum.

Factors recognized as influencing the occurrence and rate In Figure 2, the approximate failure time of carbon steel in
of H2S corrosion include the following: a given set of conditions is illustrated. For example, it can
be seen that steel hardness is a major factor in its ability to
• Hardness of the material. Risk of SSC reduced in survive in such a hostile environment.
materials below a hardness of Rockwell C22.
Estimated survival time of Rc 32 hardness steel (Example
• Cracking is very dependent on applied stress. A) is much shorter than the Rc 22 sample (Example B).

• Higher concentrations of H2S increase susceptibility to 1.2 Sources Of H2S

cracking. Effects have been reported in concentrations
as low as 1 ppm. There are two basic sources of H2S in wells:

• Presence of CO2 greatly increases susceptibility to • It occurs naturally in many formations, either by itself or
cracking. mixed with oil, gas or water.

• Influence of pH. The effect of H2S is reduced if pH is • Certain types of bacteria use a complex biochemistry to
maintained above a pH of 9. obtain oxygen from sulfate compounds and generate H2S
in the process. There are several dangers associated with
• Influence of temperature. The effect of H2S is reduced bacteria growth in wells. A small colony of bacteria may
above 150°F. start on the surface of the tubing or casing. As the
bacteria multiply, they generate H2S at the metal surface

40

40%
35
Rockwell Hardness, (Rc)

60%
A
30 80%

25 100%
B
20 130%
Applied stress as a % of
15 yield deformation
1 Day 1 Week 1 Month
10
1 5 10 100 1000
Time to failure, (hrs)

Figure 2. Approximate failure time vs hardness and applied stress for carbon steel, 3,000ppm H2S in 5%
solution of NaCl

Page 3 of 9
 Section 410
COILED TUBING SERVICES MANUALS
Rev A - 98 SAFETY CONSIDERATIONS

where it reacts to form iron sulfide in the form of extremely 1.3.2 Wells With a Potential to Bear H2S
small particles. A small pit develops which is filled with
iron sulfide and a mass of bacteria. Eventually, the pits Wells with a potential to bear H2S include:
enlarge and deepen until they penetrate the pipe. In
extreme cases, tubing, casing or pump rods will be • All wildcat wells
perforated or even parted as a result of the corrosion
damage. • All wells in a field known to have H2S producing forma-
tions, even if the subject well does not penetrate those
The hazards or potential hazards associated with H2S formations
should be taken into account in all phases of job planning
and execution. The potential for H2S to be generated or • All wells which have had a static fluid in the annulus for
liberated as a result of a well treatment is a hazard which a prolonged period
may exist after service provider personnel and equipment
have left the location. It is therefore important that company • All wells known to have corrosion problems or suspected
representatives or engineers are made aware of this poten- of having tubing leaks or scale deposits
tially hazardous situation as soon as possible in the job.
• All disposal wells or water injection wells
1.3 Identifying H2S hazards
• All geothermal wells or wells which have an abnormally
Identification of potential H2S hazards is required to ensure high temperature gradient
appropriate awareness by operational personnel, and should
be considered as part of each of the following job phases. • All wells where large losses occurred during drilling,
particularly losses of low or neutral pH water-base fluids
1.3.1 Planning
• Any well that has not been worked over for two years or
The planning phase is very important in determining the more and is now to be acidized
type of H2S hazard to be encountered and the appropriate
plan of action to protect personnel and equipment. Each Prior to performing a job on a known H2S location, an H2S
location should develop its own Hydrogen Sulfide Plans. monitoring and rescue team of at least two members should
These plans should include but not be limited to the be designated. The members should be trained on rescue
following points: procedures including the use of a self-contained breathing
apparatus and mouth-to-mouth resuscitation. The mem-
• A method of hazard appraisal from customer to service bers of the team must also be qualified to operate H2S
provider monitoring equipment and perform H2S surveys.

• Procedures when working in known, suspected and 1.3.3 Equipment Selection

unknown hydrogen sulfide areas
Any equipment which can not be positively identified as
• Procedures for working in areas where hydrogen sulfide is suitable for use in an H2S environment must be considered
not expected as unsuitable. Material and equipment suitable for use in
H2S applications must conform to the standards outlined by
There is an obvious danger when a well is known to produce API R49. The selection of appropriate seals and “O” rings
high concentrations of H2S or when drilling through forma- for use in an H2S environment is important to ensure the
tions known to contain H2S. However, the most dangerous integrity of the equipment while in use. If H2S is unexpect-
wells are those where H2S is encountered unexpectedly edly produced while non-H2S equipment is being used, the
and proper precautions have not been taken. Hydrogen operation should be suspended when practically possible
sulfide gas may be encountered unexpectedly in many and the well secured until alternative arrangements can be
different types of wells. The list below identifies the types made.
of wells of which to be especially careful.

Page 4 of 9
 COILED TUBING SERVICES MANUAL Section 410
SAFETY CONSIDERATIONS Rev A - 98

1.3.4 Personnel and Location Safety • Self Contained Breathing Apparatus (SCBA)

Monitoring for H2S gas is required on all jobs where H2S is The SCBA is primarily designed for rescue or working in
known or suspected. If the customer has not made ad- an H2S environment. A compressed air supply is con-
equate provision for H2S monitoring, the service provider tained in a cylinder worn on a back-or hip-mounted
must provide monitoring equipment and personnel as carrying frame. A full face mask is worn with a positive
required. If the effectiveness or efficiency of the customer’s internal air pressure to prevent the ingress of toxic gas.
monitoring and alarm equipment is in doubt, then the The SCBA may be fitted with a facility which allows the
customer should be informed and an alternative system connection to an air line system designed to extend the
provided if necessary. possible working time of the user.

Personnel who work in areas where H2S gas is likely to be • Emergency Life Support Apparatus (ELSA)
encountered should be trained at least annually. The
training should include the following items: The ELSA set is designed for emergency escape use
only. It generally consists of a small compressed air
• Hazards and characteristics of hydrogen sulfide gas supply and a face mask or hood which is positively
pressurized.
• Possible sources of release of H2S from equipment
1.4.1 Features
• Operation of safety equipment and life-support systems
1.4.2 Air Supply
• First aid in event of personnel exposure to H2S
The duration of the air supply, and therefore the safe
• Use and operation of H2S monitoring equipment working or escape time available to the user, is determined
by several factors:
• Emergency response procedures to include corrective
actions, shutdown procedures, evacuation routes and • Capacity of the cylinder or air supply
rescue methods
• Lung capacity of the user
All locations that routinely work in known H2S areas should
assign an individual to maintain the related H2S equipment, • Exertion level of user
and to train others on the use and care of it.
The working duration of any BA set is defined as the time
Following Completion of the Job a BA supply is expected to last - from the time of startup,
until the low-level warning sounds. The low-level warning is
If a treatment has been performed, which may result in the a feature designed to remind the user that it is time to leave
generation or liberation of H2S gas, then personnel involved the danger area.
in rigging down or subsequent operations should be made
aware that a potentially hazardous situation may exist. Since the lung capacity and level of exertion of the user are
unknown quantities, there are no safe means to accurately
1.4 Breathing Apparatus determine the exact duration of any BA. However, the
following guide is commonly used to estimate the cylinder
A breathing apparatus (BA) is required to be worn by supply duration.
personnel exposed to an environment which contains in
excess of 20 ppm H2S. The average rate of consumption is assumed to be ±40 L/
min. of air, which is an average rate for a man walking at
The BA may generally be described as follows. 4mph. Where a user undertakes a high rate of work, the
consumption will be greater and the duration correspond-
ingly less. A 10-minute safety factor is included in every

Page 5 of 9
 Section 410
COILED TUBING SERVICES MANUALS
Rev A - 98 SAFETY CONSIDERATIONS

estimated duration, therefore the calculation to estimate The manufacturers’ operation and maintenance documents
the working duration may be expressed as follows: for all safety equipment commonly used on each CTU
should be inserted in a locally prepared appendix to the
Working duration (min) = Coiled Tubing Equipment Operators Manual assigned to
that unit. This appendix is identified with a tab titled Safety
Contents of Cylinder (L) Equipment Operation and Maintenance.
- 10 (10 min safety factor)
40 (average consumption)
1.5 H2S Monitoring Equipment
Cylinder contents stated in litres of air at atmospheric
pressure The highly toxic nature of hydrogen sulfide gas, even at
extremely low concentrations, requires that monitoring for
1.4.3 Face Mask H2S be conducted on all jobs where H2S is known or
suspected. In many locations, the monitoring equipment is
Air-supplied respirators or a SCBA used in emergency or provided by the client in the form of fixed systems on the
work situations must be of a positive pressure type. This rig or platform. However, if the efficiency of the monitoring
ensures that any leak occurring in the face-mask assembly or alarm equipment is in doubt, then the client should be
will result in an outward flow of air rather than the inward flow informed and an alternative system provided, if necessary.
of toxic gas. If no such fixed system is provided, it is the responsibility
of the service provider to ensure that adequate equipment
Some designs of face mask/demand valve allow the and personnel are assigned to the H2S monitoring.
operation of the set in a non-pressurized mode. Care must
be taken to ensure that the equipment is always used by Personnel involved in the wellsite operation must be fully
selecting the positive pressure option. aware of the actions to be taken should the monitoring
equipment indicate the presence of H2S. A thorough under-
1.4.4 Training standing of the alarm/alert signals to be used in this event
is required by all personnel, and must be outlined in the
Employees likely to be exposed to H2S must be trained on prejob safety meeting.
the proper selection, use and maintenance of the respira-
tory equipment. Training should be documented, and must To operate safely and with confidence in an H2S (or
include the proper fitting of equipment. potential H2S) environment, requires the implementation of
a suitable H2S monitoring system. This system involves
A minimum of two BA sets, assigned to fully trained not only the monitoring of equipment, but also several other
personnel, must be available on every job location known key components that combine to provide maximum pos-
to, or suspected of containing H2S. The location of each sible protection to personnel and equipment throughout the
set, H2S monitoring equipment and nominated rescue operation. The system components are identified as the
personnel must be identified during the prejob safety following:
meeting.
• Initial hazard survey (known, suspected or unknown
1.4.5 Operation presence of H2S)

Safety equipment must only be used within the limits and • Location of safety and emergency equipment (wind
restrictions imposed by the manufacturer or authority socks, BA etc)
certifying the suitability of the equipment. To ensure that
personnel involved with the operation and maintenance of • Location of monitoring equipment
such equipment are aware of these requirements, the
operation and maintenance documentation must be made • Alarm or alert equipment or signals
available.
• Normal working procedures for personnel and equipment

Page 6 of 9
 COILED TUBING SERVICES MANUAL Section 410
SAFETY CONSIDERATIONS Rev A - 98

• Emergency response procedures for personnel and equip- 1.5.3 Fixed H2S Monitors
ment (Using trained personnel)
Fixed system monitors may be fitted to the rig equipment
It is important that all personnel likely to be exposed to H2S or the CTU. When fitted to the CTU, multiple sensor heads
are fully aware of, and abide by, the policy and responsibil- are connected to the control and monitoring station which
ity statements made in the Standards of Operation. is generally located within the unit control cab.

1.5.1 Features High-level alarms should be visible and audible both inside
and outside the control cabin. This will often require that an
There are several manufacturers of H2S monitoring equip- alarm repeater system be fitted.
ment, each providing a selection of models for use in
various applications. The features or specifications of the 1.5.4 Operation
equipment will vary according to its intended application.
However, there are some features which should apply to Safety equipment must only be used within the limits and
any H2S monitoring equipment regardless of application: restrictions imposed by the manufacturer or authority
certifying the suitability of the equipment. To ensure that
• The monitoring unit should operate from its own power personnel involved with the operation and maintenance of
supply. This may be supported by an external charge such equipment are aware of these requirements, the
circuit, but the unit must be operable on a “stand alone” manufacturers’ documentation must be made available.
basis.
The manufacturers’ operation and maintenance documents
• The unit should have a rapid response time. for all safety equipment commonly used on each (CTU)
should be inserted in a locally prepared appendix to the
• The unit should include visual and audible alarms. Coiled Tubing Equipment Operators Manual assigned to
that unit. This appendix will be identified with a tab titled
• Construction of the unit must be adequate for use in the Safety Equipment Operation and Maintenance.
intended environment.
Regular calibration by a qualified technician is a require-
• It should require low maintenance, without the need of ment applied to all H2S monitoring equipment. It is impor-
specialized help or equipment. tant to ensure that the frequency of the calibration checks
recommended by the manufacturer is adequate for the
Unless otherwise specified by local requirements, monitor- requirements of the certifying authorities or operators.
ing equipment should alarm at an H2S level of 10 ppm. Many
monitor models have a facility for dual level monitoring, in
which case a second, more intense alarm should activate
at a level of 20 ppm H2S.

Typically, the monitoring equipment used consists per-

sonal portable monitors or fixed monitors which are perma-
nently mounted on the CT truck or trailer.

1.5.2 Personal H2S Monitors

Personal H2S monitors should be carried by any personnel

that are required to work at (or near) the wellhead or cellar.
This includes inspection or maintenance work which may
be required on CT equipment rigged up to the wellhead.

Page 7 of 9
 Section 410
COILED TUBING SERVICES MANUALS
Rev A - 98 SAFETY CONSIDERATIONS

2 FALL PROTECTION DEVICES location of safety equipment will reduce the possibility of a
damaging shock load. A short safety line will obviously
Safety belts or harnesses, with lifelines or fall protection reduce the force exerted on a body in the event of a fall,
equipment attached, must be worn by employees when however, the reduction in operator mobility may render this
performing work at elevated positions. An elevated position system impractical.
may be regarded as being more than six feet above ground
or deck level or where it may be possible to fall further than Fall arrest equipment is designed to allow a high degree of
six feet from the work position. operator mobility. This is achieved by placing the anchor
point above the work site and using a retractable line to
2.1 Features maintain close contact with the operator.

2.1.1 Safety Harnesses Two types of fall arrest device are commonly available:

There are three basic types of harness commonly used: • Retractable safety line block

• Waist safety belt The block is attached to a suitable anchor point above the
work site. The operator’s harness is attached to the lightly
The simplest type of harness or restraint, comprising of tensioned line by a safety hook. In the event of a fall, the
a waist belt with some means of attaching a lanyard or retracting mechanism is locked by an automatic internal
safety strap. braking system. In addition to preventing a serious fall,
the mechanism is also designed to cushion the shock of
• Chest harness the fall arrest.

This type of harness usually comprises of a waist belt • Camlock Sleeve

with shoulder straps attached and possibly a secondary
belt buckled around the chest. A specially developed nylon rope is secured to a suitable
anchor point above the work site by a safety hook or
• Full safety harness similar means. The camlock device is attached to the
operator’s harness by a safety hook and “D” ring and
A harness which incorporates waist, shoulder and leg slides freely up and down the rope when in normal use. In
straps, designed in such a manner that in the event of a the event of a fall, the sudden downward movement locks
fall the forces are concentrated on the thighs and but- the device on the rope, thereby arresting and cushioning
tocks. the fall.

2.1.2 Safety Lines and Lanyards 2.1.4 Anchor Points

The most common means of attaching the safety harness Even on relatively short falls the load exerted on the fall
to an anchorage point is by a short safety line or lanyard. protection equipment and anchor point can be deceptively
These may be manufactured from wire or nylon rope, or high. Therefore, it is essential that anchor points for any
more commonly, from nylon webbing. Most safety lines are equipment are carefully selected.
supplied with a Karabiner type safety hook already at-
tached. In many cases the harness, line and hook are The following points must be considered when fall protec-
supplied complete and are non-detachable. Most safety tion systems are anchored:
lines are approximately two meters in length.
• Position
2.1.3 Fall Arrest Equipment
Whenever practical, the anchor point should be placed
Tremendous force may be exerted on a body, even after a vertically above the operator.
fall of only one or two meters. The proper selection and

Page 8 of 9
 COILED TUBING SERVICES MANUAL Section 410
SAFETY CONSIDERATIONS Rev A - 98

• Condition

Shock loads may exert forces three to four times greater

than the static weight of a body. Ensure that the anchor
point is capable of withstanding a load of this magnitude.
If a dedicated anchor point is used, regular inspection
must be made to ensure satisfactory condition.

• Stability

The point to which the fall arrest equipment is attached

should not be capable of moving, e.g. a hook attached to
a vertical member may slide when a load is applied.

The anchor point should not normally be located on

equipment which is capable of being moved indepen-
dently of the work site (e.g. if the anchor point equipment
is inadvertently moved, it may result in the operator being
pulled from the work site).

2.2 Operation

Safety equipment must only be used within the limits and

restrictions imposed by the manufacturer or authority
certifying the suitability of the equipment. To ensure that
personnel involved with the operation and maintenance of
such equipment are aware of these requirements, relevant
documentation must be made available.

Manufacturer’s operation and maintenance documents for

all safety equipment commonly used on each CTU, should
be inserted in a locally prepared appendix to the Coiled
Tubing Equipment Operators Manual assigned to that unit.
This appendix is identified with the tab Safety Equipment
Operation and Maintenance.

Page 9 of 9
This page left blank
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98

CONTINGENCY PLANNING

Contents Page

Introduction .................................................................................................... 2
1 CONTINGENCY PLANNING........................................................................... 2
1.1 Contingency Guidelines ....................................................................... 3
1.1.1 Workstring Integrity ............................................................................. 3
1.1.2 Stuck Workstring ................................................................................. 3
1.1.3 Mechanically Damaged Workstring ...................................................... 5
1.1.4 Pressure Control Equipment ................................................................ 5
1.1.5 Coiled Tubing Equipment ..................................................................... 6
1.2 Operational .......................................................................................... 6
1.3 Determining the Stuck Point ................................................................ 6
1.4 Cutting the Coiled Tubing at Surface .................................................... 6
1.5 Preparation for Cutting Tubing Downhole .............................................. 6
1.5.1 Explosive Cutters ................................................................................ 9
1.5.2 Chemical Cutters ................................................................................. 9
1.6 Coiled Tubing Retrieval ........................................................................ 9
1.7 Emergency Procedures ..................................................................... 10
1.7.1 BOP Emergency Operation ............................................................... 10
1.7.2 Power Pack Unit Failure ..................................................................... 10
1.7.3 Stripper Leakage ............................................................................... 10
1.7.4 Stuck Coiled Tubing ........................................................................... 11
1.7.5 Collapsed Coiled Tubing ..................................................................... 11
1.7.6 Surface Treating Line Leak ................................................................ 12
1.7.7 Injector Chain Slippage...................................................................... 12
1.7.8 Reel Swivel Leak ............................................................................... 12
1.7.9 Pinhole at Surface ............................................................................. 12
1.7.10 CT Rupture at Surface ....................................................................... 13
1.7.11 Leaking Riser and/or Crossover Between BOPs and Wellhead .......... 14

Page 1 of 14
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98 CONTINGENCY PLANNING

Introduction The role of contingency planning in CT services is illus-

trated in Figure 1 and defined below:
The primary objective of contingency planning is to mini-
mize response time, or down-time, in the event unplanned • Normal Operating Procedures
conditions are encountered. In many cases, delays in
response to unusual conditions results in a worsening of the Procedures prepared to ensure correct execution of the
circumstances or problem. The potential risk to well secu- intended operation in a safe manner. Job procedures or
rity and personnel safety can be quickly compounded in guidelines must be prepared for every CT operation.
such circumstances. Therefore, contingency planning must
be part of every CT operation. • Contingency Plans

1 CONTINGENCY PLANNING Contingency plans should be prepared for use when

unplanned conditions are encountered during an opera-
The level of contingency planning will generally reflect the tion. These may include emergency procedures to main-
conditions, potential hazards and/or complexity of the tain control of well pressure or surface equipment. CTU
intended operation. Operations conducted in high potential operators must be fully familiar with these procedures.
hazard conditions require a higher level of contingency
planning. In some circumstances, detailed procedures • Emergency Procedures
may be included in contingency plans to ensure the safety
of personnel and equipment. Emergency procedures may be defined as an immediate
response to conditions which threaten well security, or

COILED TUBING SERVICES - PROCEDURES AND PLANNING

Normal Operating Procedures

A sequence of actions, checks and controls to ensure

correct execution of the intended operation

Well Security
Personnel Safety
Equipment and Tools

Contingency Plans Emergency Procedures

A reference source to be used as a guide Trained responses to conditions

in the event reasonably unforseeable but which jeopardize the safety of
unplanned conditions are encountered personnel or security of the wellbore
during the operation

Figure 1.

Page 2 of 14
 COILED TUBING SERVICES MANUAL Section 420
CONTINGENCY PLANNING Rev A - 98

personnel safety. Such responses are enacted as a result Parted Tubing at Surface
of detailed training, familiarity with equipment and ex-
ecuted with the knowledge and awareness of the wellbore There are two major concerns associated with the workstring
and operational conditions. parting on the surface:

In each of the above, consideration must be given to three • Well security and the presence of a tube extending
key areas of responsibility: through the wellhead

• Well security • The free end(s) of the tubing, which react to the workstring
internal pressure
• Personnel safety
Parted Tubing in the Wellbore
• Equipment, tools and the intended operation
A workstring which has parted in the wellbore will generally
As a supplement to any contingency plans, the source and be indicated by a sudden change in the weight indicator
availability of any special equipment or services should be (weight loss) and/or a variation in circulating pressure.
noted (e.g. chemical cutting services). Attempting to tag a known restriction may confirm that the
tubing has parted, if the apparent depth is greater than
1.1 Contingency Guidelines previously noted.

The contingency guidelines are categorized as follows. In some cases the first indication that the workstring has
parted will be the release of well fluids as the tubing stub is
• Workstring integrity pulled through the stripper. In this event, closing the blind
rams will regain control of the well.
• Stuck or damaged workstring
Plugged Tubing
• Pressure control equipment
Most CT applications require fluids to be circulated, either
• Coiled tubing equipment as part of the treatment or to maintain well conditions
suitable for continuing the operation (e.g. to prevent tubing
• Operational collapse).

1.1.1 Workstring Integrity 1.1.2 Stuck Workstring

Fatigue tracking and reel history recording significantly There are many ways by which a workstring can become
reduces the number of workstring failures and leaks. stuck. Selection of the appropriate action or treatment to
However, fatigue, corrosion and mechanical damage can resolve the condition depends on several factors. The
result in tubing leaks of varying severity. Regardless of the following points should be considered:
cause, workstring leaks are unacceptable, and must result
in the suspension of the operation pending repair or replace- • Wellbore geometry
ment of the workstring.
• CT toolstring geometry
Leak at Surface
• Presence of fines or small solids (circulatable) in wellbore
A leak in the tubing string indicates a significantly weak- or treatment fluids
ened area which may fail completely following further
cycling. Action taken to secure the well and recover the • Presence of junk or large solids
workstring should be made while attempting to minimize
further damage or fatigue to the string at the leak point. • Characteristics of treatment, produced or wellbore fluids

Page 3 of 14
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98 CONTINGENCY PLANNING

• Stuck point assessment • Fill material:

- Produced sand or fines
Working the tubing string in and out of the wellbore in an - Junk
attempt to pass a hang-up point is often effective. However,
this induces localized fatigue as the tubing is cycled around • Reaction products:
the gooseneck and reel, which can rapidly lead to failure of - Scales
the workstring. - Paraffin or asphalt deposits
- Hydrates
The weight indicator response can be used to help deter-
mine whether sticking is due to a downhole or near wellhead Near Wellhead
condition. For example, a rapid loss of weight over a short
interval can indicate a hang-up point at or near the wellhead • Mechanical:
or pressure control equipment. Deeper, downhole hang-up - Incomplete opening of valves - (swab, master, lubricator
points will cause a slower reaction which is dampened by DHSV/SSSV)
the effect of tubing stretch or buckling. - Wellhead or pressure control equipment profile
- Toolstring hang-up (e.g. centralizer or underreamer)
The interval over which the weight loss is observed also can - Distorted tubing hanging-up in stripper
be used to help identify the hang-up mechanism. For
example, a single-point mechanical hang-up can effect a • Hydraulic:
more rapid weight indicator reaction than the penetration, or - Piston effect in non-perforated wellbores
pull through, fill material. - Piston/surge effect of close toolstring OD and produc-
tion tubing ID (packers)
Obstruction Going In-Hole
• Reaction products:
There are a number of conditions which hinder or prevent - Scales
the progress of the CT or toolstring into the wellbore. - Paraffin or asphalt deposits
Determining the cause of such conditions is important, not - Hydrates
only to allow the operation to continue, but to avoid the
potential of worsening conditions which may ultimately lead Stuck Coming Out-of-Hole
to a stuck workstring.
The techniques which can be used to free a stuck workstring
The following conditions can hinder the progress of tubing are significantly hampered if the ability to circulate fluids is
or toolstrings being run into a wellbore: also lost. Consequently, at least a slow circulation rate
should be maintained throughout the operation if the threat
Downhole of annular plugging exists. Pump rates should be mini-
mized while cycling the tubing to reduce the induced
• Mechanical: fatigue.
- Nipple or restriction profile hang-up
- Collapsed or damaged well tubulars In the absence of a release mechanism, the following
- Toolstring hang-up (e.g. centralizer or underreamer) techniques have been frequently used in successful recov-
- Severe dog leg ery of stuck tubing strings. A moderate overpull should be
- Deviation/lock-up applied to the tubing string as these techniques are tried.

• Hydraulic: • If stuck due to drag or fill, circulation of a slick fluid to the

- Piston effect in non-perforated wellbores stuck point should be attempted to “lubricate” the tubing.
- Piston/surge effect of close toolstring OD and produc-
tion tubing ID (packers) • Surging the well by rapidly bleeding pressure from the
- Differential sticking annulus can be effective.

Page 4 of 14
 COILED TUBING SERVICES MANUAL Section 420
CONTINGENCY PLANNING Rev A - 98

• Circulating a dense fluid into the annulus while displacing • Intended application and anticipated forces
the tubing string to nitrogen increases buoyancy effects.
• Availability of a substitute reel
If the string remains stuck, the well should be killed and the
tubing severed above the stuck point. 1.1.4 Pressure Control Equipment

1.1.3 Mechanically Damaged Workstring Pressure control equipment is typically regulated by local
or national authorities. Should the integrity or efficiency of
Mechanical damage to the workstring is of concern for the equipment be in doubt, the intended operation must be
several reasons: suspended and the well secured until all pressure control
equipment requirements are met.
• The pressure capacity of the workstring may be weakened
to the point of failure. The equipment configuration may allow several options to
be considered in overcoming malfunctions or failures.
• The tensile capacity of the workstring almost certainly will However, it is generally required that two barriers against
be weakened. well fluids and pressure be in place at all times. The priority
in contingency planning or emergency procedures must be
• The efficiency of pressure control equipment can be to maintain or regain the required level of protection before
compromised (e.g. stripper efficiency). proceeding with the operation.

• If severe, distorted tubing will not pass through pressure Stripper Packer Failure
control equipment bushings.
Gross leaks at the stripper packer are easily identifiable
• Even small damaged areas can lead to unpredictable and cause obvious safety and environmental hazards.
failures due to the effects of localized stress. Less severe leaks can be more difficult to detect, espe-
cially if the injector head is poorly lit or some distance from
Collapsed Tubing the control cabin. However, such leaks can still pose a
significant hazard and should be rectified as soon as
Tubing collapse typically occurs near the wellhead where possible.
the axial tensile force is greatest, or at the bottomhole end
where the applied pressure is greatest. Leak in Riser/Lubricator Above BOP

A collapsed tubing string can be indicated by an increase Leaks in the riser or lubricator section above the BOP are
in circulating pressure, severe leakage of wellbore fluids often caused by an unstable equipment rig-up which can
past the stripper, or an overpull caused by the distorted result in high bending moments being exerted on connec-
tubing being forced through the stripper bushing. tions or flanges. In the event of a leak, the stability of the
equipment rig-up must be checked and improved as neces-
Damaged Tubing at Surface sary.

Kinked or damaged tubing will typically be identified by the Leak in Riser/Lubricator Below BOP
TIM as it is being spooled from the reel. A close inspection
must then be made to determine the extent of damage Leaks in the riser or lubricator below the BOP are of special
before the tubing is run through the injector head. Appropri- concern since they cannot be controlled by the primary or
ate action can then be determined following consideration secondary well control equipment. Where fitted, shear/seal
of the following points: BOPs can be activated to regain control the well. However,
the workstring and/or toolstring below the shear/seal will be
• Extent of damage parted.

• Location of damage

Page 5 of 14
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98 CONTINGENCY PLANNING

In the absence of shear/seal pressure control equipment, • Downhole Tool Operations:

a rapid assessment of the situation is required. - Suspected tool failure/malfunction
- Unable to penetrate/RIH
1.1.5 Coiled Tubing Equipment - Depth correlation appears incorrect

Only items of equipment which can directly jeopardize well 1.3 Determining the Stuck Point
security are included in this section. Additional contin-
gency plans should be prepared for special or unusual When attempting to free a stuck workstring it is necessary
equipment configurations, as required. to determine as accurately as possible the point at which
the workstring is held. The completion, or well geometry,
Loss of Power or Control data are generally good indicators of potential stuck points.
However, if possible, a stretch test/calculation should be
Before repairing or replacing the power unit, the following conducted to confirm/determine the stuck point.
steps should be taken:
The worksheets shown in Figures 2 and 3 are intended to
• Close the slip rams and the pipe rams. Close the manual help record and calculate the data required to determine the
locks on both sets of rams in case of hydraulic leakage. CT stuck point. The accuracy of this technique is greatly
dependent on the accuracy of the information input. There-
• If applicable, apply the reel brake. fore, it is essential that accurate information is gathered on
tapered string dimensions, etc., before applying the calcu-
• Maintain circulation as required (e.g. to prevent tubing lation.
collapse or the settling of wellbore solids).
1.4 Cutting the Coiled Tubing at Surface
Reel Swivel Leak
Before the CT is cut at the surface, the well must be killed.
In the event of a reel swivel leak, a rapid assessment of the If possible, this should be conducted by circulating through
conditions may be necessary. For example, when circulat- the CT. This will maintain a kill-weight column of fluid inside
ing fill material from the wellbore, interrupted or reduced and outside the CT string.
circulation may result in sticking the workstring. In addition,
the nature of the fluid inside the workstring may determine If circulation is not possible, bullhead the kill fluid down the
necessary action (it is undesirable to stop circulation with annulus. In this event, account must be taken of the
cement or acid in the workstring, but it is extremely injection pressure limits imposed by the well tubulars and
hazardous to sustain a high-pressure leak of corrosive or equipment, and the risk of collapsing the CT.
flammable fluid).
The pressure control equipment shown in Figure 4 provides
1.2 Operational a means of securing and circulating through the CT after the
string has been cut downhole.
The following list of wellbore or treatment conditions can be
considered as foreseeable in certain circumstances. 1.5 Preparation for Cutting Tubing Downhole

• Circulating Applications: When cutting a CT work string, the well must be killed and
- Lost circulation/returns flow checked. To ensure that a complete cut is made, the
- Well/formation kick cutter (explosive or chemical) should be centralized with
- Interruption to fluid supply the correct standoff from the tubing to be cut. A complete
- Insufficient fluid supply (rate or volume) tubing string/well schematic must be made available for the
- Treatment fluid out of specified limits cutting technician.
- Unable to penetrate/RIH

Page 6 of 14
 COILED TUBING SERVICES MANUAL Section 420
CONTINGENCY PLANNING Rev A - 98

COILED TUBING STRING STUCK-POINT CALCULATION WORKSHEET

Length of CT in the Well.......................(ft)

Measured Stretch.......................(in.) at Applied Load..............................(lb)

NONTAPERED STRING

AE l
Length to Stuck Point L=
12 F

2
Cross-Sectional Area.....................(in. ) x 29,000,000 x Stretch......................(in.)
= Length to Stuck Point = .......................(ft)
12 x ( Applied Load)....................(lb)

2 2
A – Cross-Sectional Area = (OD - ID ) F – Applied Load (at the time the CT stretch was measured at surface)
4
l – Measured Stretch E – Constant for Young's Modulus of Elasticity (29,000,000)

L – Length to Struck Point

TAPERED STRING

1. Determine the actual tubing string stretch for a given load.

2. Using the calculation form overleaf, determine the taper section in which the stuck point is located. Starting with the top section,
calculate and add the stretch induced in each taper section until the sum is greater or equal to the actual measured stretch.

3. Determine the location of the stuck point in the last taper section by applying the following formula. The value for l (Stretch)
is obtained by subtracting the sum of the free taper sections calculated stretch from the measured stretch.
AE l
Length to Stuck Point L=
12 F

2
Cross-Sectional Area.....................(in. ) x 29,000,000 x Stretch......................(in.)
= Length to Stuck Point = .......................(ft)
12 x ( Applied Load)....................(lb)

2 2
A – Cross-Sectional Area = (OD - ID ) F – Applied Load (at the time the CT stretch was measured at surface)
4
l – Stretch E – Constant for Young's Modulus of Elasticity (29,000,000)

L – Length to Struck Point

4. Add this length to the lengths of the free taper sections. Taper Section No. 1 Length .......................(ft)

Taper Section No. 2 Length .......................(ft)

Taper Section No. 3 Length .......................(ft)

Taper Section No. 4 Length .......................(ft)

Taper Section No. 5 Length .......................(ft)

Length from Stuck Point to the Last Taper Section .......................(ft)

Total Length to Stuck Point .......................(ft)

Figure 2. Stuck-point calculation work sheet.

Page 7 of 14
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98 CONTINGENCY PLANNING

COILED TUBING STRING STUCK POINT CALCULATION

TAPERED STRING WORKSHEET

Length of CT in the Well.......................(ft)

Measured Stretch.......................(in.) at Applied Load..............................(lb)

Weld Location.................(ft)
12 F L
Tubing Stretch in Taper Section No. 1 l=
AE
Wall Thickness................(in.)

2 12 x ( Applied Load)....................(lb) x Taper Section Length .............................(ft)

Cross-Sectional Area (A)...................(in. ) 2
2 2 Cross-Sectional Area.....................(in. ) x 29,000,000
A= (OD - ID )
4

Taper Section No. 1 Length .......................(ft) Taper Section Stretch = ........................(in.)

Weld Location.................(ft)
12 F L
Tubing Stretch in Taper Section No. 2 l=
AE
Wall Thickness................(in.)

2 12 x ( Applied Load)....................(lb) x Taper Section Length .............................(ft)

Cross-Sectional Area (A)...................(in. ) 2
2 2 Cross-Sectional Area.....................(in. ) x 29,000,000
A= (OD - ID )
4

Taper Section No. 2 Length .......................(ft) Taper Section Stretch = ........................(in.)

Weld Location.................(ft) 12 F L
Tubing Stretch in Taper Section No. 3 l=
AE
Wall Thickness................(in.)

2
12 x ( Applied Load)....................(lb) x Taper Section Length .............................(ft)
Cross-Sectional Area (A)...................(in. ) 2
2 2
(OD - ID ) Cross-Sectional Area.....................(in. ) x 29,000,000
A=
4

Taper Section No. 3 Length .......................(ft) Taper Section Stretch = ........................(in.)

Weld Location.................(ft)
12 F L
Tubing Stretch in Taper Section No. 4 l=
AE
Wall Thickness................(in.)

2 12 x ( Applied Load)....................(lb) x Taper Section Length .............................(ft)

Cross-Sectional Area (A)...................(in. ) 2
2 2 Cross-Sectional Area.....................(in. ) x 29,000,000
A= (OD - ID )
4

Taper Section No. 4 Length .......................(ft) Taper Section Stretch = ........................(in.)

Weld Location.................(ft)
12 F L
Tubing Stretch in Taper Section No. 5 l=
AE
Wall Thickness................(in.)

2
12 x ( Applied Load)....................(lb) x Taper Section Length .............................(ft)
Cross-Sectional Area (A)...................(in. ) 2
2 2
A= (OD - ID ) Cross-Sectional Area.....................(in. ) x 29,000,000
4

Taper Section No. 5 Length .......................(ft) Taper Section Stretch = ........................(in.)

l – Stretch F – Applied Load (At the time the CT stretch was measured at surface.

L – Length of Taper Section E – Constant for Young's Modulus of Elasticity

A – Cross-sectional Area of the CT Taper Section

Figure 3. Stuck-point calculation – tapered string work sheet.

Page 8 of 14
 COILED TUBING SERVICES MANUAL Section 420
CONTINGENCY PLANNING Rev A - 98

Wireline stuffing box and sheave wheel

Small-diameter wireline lubricator

Pump-in connection

Weco 2-in. lateral Y

Coiled tubing connector with cross-

over to Weco 2-in. connection
Coiled tubing

Figure 4. Pressure control and circulating equipment rigup.

1.5.2 Chemical Cutters

It is recommended that the pressure control equipment in
Figure 4 be used to maintain the well security when the cut The technician or engineer running the chemical cutter will
is made. The cutting tool dimensions, before and after be responsible for ensuring that the correct procedures and
firing, should be considered when making up this equip- actions are followed. The normal wireline/explosives han-
ment. dling safety procedures must be applied and enforced.

Note: Explosive and chemical cutting tools must only be The chemical cutter head should be sized to allow passage
assembled and prepared by experienced and qualified of the coiled tubing string, but with minimum standoff from
personnel. it. Factors to be considered include the presence of weld
bead (if applicable) and the possible ovality of the tubing.
1.5.1 Explosive Cutters
1.6 Coiled Tubing Retrieval
The technician or engineer running the explosive cutter is
responsible for ensuring that the correct procedures and After the CT has been cut and the cutting tool string
actions are followed. The normal wireline/explosives han- retrieved, circulation through the CT may commence. In
dling safety procedures must be applied and enforced. cases where the well was not killed by circulating through

Page 9 of 14
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98 CONTINGENCY PLANNING

the CT, at least 1-1/2 wellbore volumes should be circulated • Close the blind rams
to ensure that a continuous column of the required kill-
weight fluid exists. • Rig up to circulate the well with kill fluid through the kill
port.
Prior to rigging down the pressure control equipment, a flow
test should be conducted to verify the well status. 1.7.2 Power Pack Unit Failure

To recover the cut tubing string, the tubing must be joined In the event of a power pack unit failure, the following
temporarily by a double roll-on connector. This will allow the actions should be taken:
tubing to be spooled onto the reel. The reel-drive hydraulic
circuit should be operated at a reduced backpressure until • Apply the brake
the tubing joint is three to four wraps on the reel.
• Close the slip and pipe rams. Manually lock both rams.
An accurate track of the tubing recovered must be kept to
avoid withdrawing the end from the injector chains. How- • Depending on well pressure, it may be necessary to
ever, in most cases, tubing cut by an explosive cutter will continue circulation, to maintain differential pressure.
not pass through the stripper.
• If performing a fill cleanout job, ensure that circulation
1.7 Emergency Procedures continues until returns are clean.

The objective of emergency procedures is to secure • Repair or replace power pack.

existing or potentially hazardous conditions sufficient to
enable a review of possible options (contingency plans) to • Resume operations:
be safely made. The procedures must be executed with
minimal delay or consultation and are typically associated - Activate stripper
with the operation of well pressure control equipment or
devices. Consequently, all CTU operators must be fully - Equalize pressure across rams
familiar with the equipment in use. In addition, operators
should be constantly aware of current and potential well - Unlock rams manually
conditions.
- Open pipe rams and slip rams hydraulically
1.7.1 BOP Emergency Operation
1.7.3 Stripper Leakage
• Stop pipe movement
In the event of stripper leakage, the following actions
• Close slip and pipe rams should be taken:

If time and circumstances permit, review options with • Stop pipe movement
company representative. Where there is immediate and
serious danger to personnel, enact the BOP emergency • Increase pressure in stripper system or activate tandem
procedure. stripper

• Stop pumping • Assess the situation before continuing job

• Close shear rams and cut pipe • Even if the increased stripper pressure stopped the leak,
it may be safer to change the stripper inserts at this time
If time permits apply tension to pipe before cutting
• Close the slip and pipe rams. Manually lock both rams
• Pull pipe above the blind rams

Page 10 of 14
 COILED TUBING SERVICES MANUAL Section 420
CONTINGENCY PLANNING Rev A - 98

• Bleed off pressure above the pipe rams If it is not possible to free the coiled tubing:

• Release skate tension and jack up the injector • Hang off the coiled tubing in the slip rams

• Split the stripper caps and pack the stripper hydraulically • Kill the well
to remove the inserts
• Cut the coiled tubing above the injector head and cross-
• Reassemble the stripper with new inserts over the coiled tubing with the wireline lubricator

• Hydraulically pressure up the stripper • Determine the free point using the stretch method or
wireline free point tool
• Lower the injector and apply skate pressure
• Run chemical/flash cutter through the wireline and cut the
• Pressure test the stripper pipe at the free point

• Equalize pressure across the rams • Retrieve the free coiled tubing

• Open the pipe and slip rams manually • RIH with a fishing BHA and try to free remaining CT string

• Open the pipe and slip rams hydraulically 1.7.5 Collapsed Coiled Tubing

• Resume operations Indications of collapsed coiled tubing include:

1.7.4 Stuck Coiled Tubing • An increase in pump pressure

If the coiled tubing is stuck and a pull higher than 80% of • An increase in pull (stripper bushing)
the yield strength is required to free it, the following actions
should be taken: • Injector chain slippage

• Determine the possible causes, to select correct action The actions to be taken are:
plan:
• Close the slip and pipe rams on a good section of pipe.
- Work the string up and down without exceeding 80% of Manually lock both rams
the yield strength. Be aware of low cycle fatigue.
• Kill the well
- Circulate a slick pill to reduce friction between the CT
and casing/tubing walls. • Cut the coiled tubing above the injector and remove the
injector head
- Rapidly bleed off annulus (surge) while pulling on the
pipe. • Clamp down the coiled tubing and test the clamp

- Increase buoyancy • Remove the section of collapsed coiled tubing using a

crane or travelling block
- Release the BHA by means of the release joint
• Leave 15 feet of good coiled tubing above the BOPs
- RIH with a fishing BHA to retrieve the fish left inside the
hole • Set the slip and pipe rams. Manually lock both rams

Page 11 of 14
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98 CONTINGENCY PLANNING

• Walk the injector head over the 15 ft section of coiled Do not do the following:
tubing
• Stop injector chain rotation
• Connect the injector head to the BOPs. Apply inside skate
pressure • Close the BOP rams

• POOH a few feet of coiled tubing • Apply reel brakes

• Connect the coiled tubing with double roll-on connector • Apply injector brakes

• Carefully spool the coiled tubing back to the reel 1.7.8 Reel Swivel Leak

1.7.6 Surface Treating Line Leak In the event of a reel swivel leak, the following actions
should be taken:
Actions to be taken include:
• Stop any coiled tubing movement
• Stop the pumps
• Close the slip and pipe rams. Manually lock both rams.
• Stop any coiled tubing movement. Depending on well
pressure and depth, it may be advisable to manually lock • Isolate the coiled tubing using the valves on the reel
the slip and pipe rams manifold

• Isolate the coiled tubing using the valves on the reel • Bleed pressure from the reel manifold
manifold
• Monitor the differential pressure on the coiled tubing by
• Bleed pressure from lines regulating the choke if necessary. Coiled tubing collapse
is a major concern at this point
• Monitor differential pressure on the coiled tubing by
regulating the choke if necessary. Collapsing coiled • Repair the leak and resume operations
tubing is a major concern at this point
1.7.9 Pinhole at Surface
• Repair the leak and resume operations
The actions to be taken depend on whether the check
1.7.7 Injector Chain Slippage valves are holding.

Actions to be taken in the event of injector chain slippage Check Valves Holding
include:
Actions to be taken include:
• Increase the skate tension
• Stop pumping
• In the event of coiled tubing runaway:
• Stop coiled tubing movement
- Apply emergency traction
• Alert people to the potential danger
- Chase coiled tubing with the injector chains
• If possible, flag the position of the pinhole with paint
- Increase stripper pressure

Page 12 of 14
 COILED TUBING SERVICES MANUAL Section 420
CONTINGENCY PLANNING Rev A - 98

• If pumping corrosive fluid, run pinhole below the stripper • Walk injector head over 15 ft section of coiled tubing and
and displace with water. Caution must be exercised due connect injector head to BOPs. Apply inside skate
to the danger of breaking the pipe when running it through pressure
the gooseneck and chains
• POOH a few feet of coiled tubing
• If the fluids are not dangerous, carefully POOH coiled
tubing string • Connect coiled tubing with double roll-on connector

• Monitor the differential pressure on the coiled tubing by • Carefully spool coiled tubing back to reel
regulating the choke or flowing the well if necessary
• Rig up standby reel and complete operations
• Depending on the wellhead pressure, continue to pump to
decrease the chances of collapsing the coiled tubing The following is an alternative procedure:
string
• RIH coiled tubing below stripper. Caution must be exer-
• Rig up standby reel and resume operations cised due to danger of breaking the pipe when running it
through the gooseneck and chains
Check Valves Not Holding
• Do one of the following:
The job must be terminated. Actions to be taken include:
- Kill the well and retrieve the coiled tubing string, or
• Stop pumping
- Depending on the depth, pressure and type of reservoir
• Stop coiled tubing movement fluids in the well, continuously pump fluids or inert gases
through the coiled tubing string while pulling the coiled
• Alert people to the potential danger tubing string out of the hole

• Apply complete BOP emergency procedure: 1.7.10 CT Rupture at Surface

- Close slip and pipe rams The actions to be taken depend on whether the check
valves are holding.
- Close shear rams
Check Valves Holding
- Pick up CT above blind rams
The following actions should be taken:
- Close blind rams
• Stop coiled tubing movement
- Open shear rams
• Apply reel brake
- Manually lock blind, pipe and slip rams
• Stop pumping
• Kill the well
• Close slip and pipe rams. Manually lock both rams
• Prepare to retrieve the coiled tubing using an overshot or
spear • Monitor differential pressure on coiled tubing by regulating
the choke or flowing the well as necessary. Collapsing the
• Leave 15 feet of coiled tubing above the BOPs coiled tubing is a major concern at this point

• Connect coiled tubing with double roll-on connector

Page 13 of 14
 Section 420
COILED TUBING SERVICES MANUAL
Rev A - 98 CONTINGENCY PLANNING

• Carefully spool coiled tubing back to reel 1.7.11 Leaking Riser and/or Crossover Between BOPs
and Wellhead
• Once there are a couple of wraps on the reel, start pumping
to reduce chances of collapse The following actions are to be taken:

• Rig up standby reel and complete operations • Stop pumping

• Depending on the type of well, the complete BOP • Stop coiled tubing movement
emergency procedure may need to be initiated
• Alert people to the potential danger
Check Valves Not Holding
• Apply the BOP emergency procedure without setting the
The following actions are to be taken: pipe and slip rams

• Stop coiled tubing movement - Close the shear rams

• Apply reel brake - Pick up the CT above the blind rams

• Stop pumps - Close the blind rams

• Apply the complete BOP emergency procedure - Open the shear rams

- Close slip and pipe rams - Close the wellhead master valve

- Close shear rams • Ensure sufficient coiled tubing is off bottom, so that when
the shear rams are used, the coiled tubing drops below the
- Pick up 1 ft master valve

- Close blind rams • Repair the crossover and/or riser leak

- Manually lock the blind, pipe and slip rams • RIH with a fishing BHA and retrieve the coiled tubing

- Open shear rams The following alternative method can also be used:

• Kill the well • If available, pump an inert fluid down the coiled tubing
annulus and coiled tubing string
• Retrieve the coiled tubing using an overshot or spear
• POOH the coiled tubing string as quickly as possible
• Leave around 15 ft of coiled tubing above the BOP

• Walk the injector head over the 15 ft of tubing. Connect the

injector head to the BOPs. Apply inside skate pressure

• Connect the coiled tubing with double roll-on connector

• Carefully spool the tubing back onto the reel

• Rig up standby reel and complete operations

Page 14 of 14