Report

1. Study of
Coil
Tubing
Operations
for
Hydraulic
Fracturing
Hydarulic Fracturing Depatrament Essar
Oil Limited, Duragapur
By
Steffones .K
B. Tech in Applied Petroleum
Engineering
University of Petroleum and Energy
Studies
Dehradun
20th December 2014 to 10th January
2015
Under the Guidance of
Mr. Anjani Kumar
Manager H.F
Department
Essar Oil Ltd.

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Essar Oil Limited
Durgapur, West Bengal
CERTIFICATE
This is to certify that the student Steffones.K of University of Petroleum and Energy Studies,
Dehradun has successfully completed the project work on “Study of Coil Tubing Operations for
Hydraulic Fracturing” in the Hydraulic fracturing department at the Essar Oil limited, Durgapur
from 20th December, 2014 to 10th January, 2015. This project work is the requirement towards
awarding the Degree of Bachelor of Technology in Applied Petroleum Engineering, from University
of Petroleum and Energy Studies, Dehradun.
Mr. Anjani Kumar
Project Supervisor

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ACKNOWLEDGEMENT
I express my deep sense of gratitude to Mr. Manoj Kumar,(DGM-HR|E&P Division| Essar Oil) for
giving me the opportunity to work at Essar Oil and providing all the necessary facilities towards the
completion of this project. I am thankful to Anjani Kumar, (Manager| HF| Essar Oil Ltd.) who
mentored me throughout this project. It was with his invaluable guidance that this work could be
completed in time.
I express my sincere thanks Ms Priya Sihag (Assistant Engineer |HF| Essar Oil Ltd.) and Mr.
Zulquarnain (Assistant Engineer |HF| Essar Oil Ltd.) for providing valuable insights on operations
on-site. I would also like to thank to Mr. Manish Tiwari (Dy. Manager |HF| Essar Oil Ltd.) , Mr.
Anshit Sharma(Assistant Engineer |HF| Essar Oil Ltd.) Mr. Ramniwash(Assistant Engineer |HF|
Essar Oil Ltd.) and Ms.Suneha Sharma(Dy. Manager |HF| Essar Oil Ltd.) for their constant support
and guidance in every part of this study.
I would like to thank Dr. D.K. Gupta, Head – Department of Petroleum and Earth Sciences, UPES
for giving me this great opportunity to pursue a winter internship at Essar Oil Ltd.
Steffones .K
B.Tech, Applied Petroleum Engineering
UPES, Dehradun

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Table of Contents
Sl.
No. Subject
Page
No.
1 Introduction to Coil Tubing Unit 5
1.1 Coil tubing Reel 6
1.2 Coil tubing control Cab 6
1.3 Injector Head 8
1.4 Well control equipment 9
1.5 Coil Tubing String Design 10
1.6 Coil Tubing BHA 11
1.7 Advantages of Coil Tubing 14
1.8 Completion Application 14
1.9 Field Application 15
2 Operations of Coil Tubing 15
3
Procedural Analysis of Fracturing Operations
using Coil tubing. 16
4 Brief of Hydraulic Fracturing 18
4.1 Hydraulic Fracturing 18
4.2 Aim of Hydraulic Fracturing 18
4.3 Hydraulic Fracturing Fluid 19
4.3 Process of Hydraulic Fracturing 19
5 Conclusion 20

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List of Figures
Sl.
No. Subject
Page
No.
1 Coil Tubing Front View 5
2 Coil Tubing Reel Unit 6
3 Control Cabin 7
4 Injector Head 7
5 Injector Head Schematic Diagram 8
6 Stripper 8
7 Quad BOP 9
8 Coil Tubing Design Parameters 9
9 Coil Tubing BHA 11
10 Coil Tubing BHA 11
11 Roll Connector 11
12 Fullbore nozzle 11
13 BHA Schematic Diagram 12

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1. INTRODUCTION TO COIL TUBING UNIT
Coiled Tubing (CT) has been defined as any continuously-milled tubular product
manufactured in lengths that require spooling onto a take-up reel, during the primary
milling or manufacturing process. The tube is nominally straightened prior to being
inserted into the wellbore and is recoiled for spooling back onto the reel. Tubing
diameter normally ranges from 0.75 in. to 4 in., and single reel tubing lengths in
excess of 30,000 ft. have been commercially manufactured. Common CT steels have
yield strengths ranging from 55,000 PSI to 120,000 PSI.
The coiled tubing unit is comprised of the complete set of equipment necessary to
perform standard continuous-length tubing operations in the field. The unit consists of
four basic elements:
 Reel - for storage and transport of the CT
 Injector Head - to provide the surface drive force to run and retrieve the CT
 Control Cabin - from which the equipment operator monitors and controls the
CT
 Power Pack - to generate hydraulic and pneumatic power required to operate the
CT unit.
Guide Arch
Tubing ReelPower Pack
Coil Tubing
Injector Head
Fig.1 COIL TUBING UNIT FRONT VIEW

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Coil Tubing Reel-
Coiled tubing is stored on a drum that is supported on a shaft and mounted on a skid
frame. A bi-directional hydraulic motor directly driving the reel via roller chain and
sprockets or by a gear drive system rotates the reel.
The drive system has dual function: when running in hole (RIH), the motor acts as a
constant-torque brake, enabling back tension to be held on the pipe and while pulling
out of hole (POOH), more tension is applied to enable efficient spooling of the pipe
onto the drum.
The reel will have a brake mechanism to prevent accidental rotational movement when
it is required. The reel drive system should produce enough torque to provide the
required tension to the coiled tubing to bend the coiled tubing over the gooseneck and
onto the reel. This tension provided by the reel on the coiled tubing unit between the
reel and injector is commonly referred to as ‘reel back-tension’
Coiled Tubing Control Cab-
The control cabin fully allows the operation and control of all functions of the coiled
tubing unit from within the cabin. The typical unit is hydraulically elevated for better
operator vision. The control panel incorporates:
 Injector controls
 Reel controls
 BOP controls
 Auxiliary shear seal BOP controls
 Hydraulic circuit pressure gauges
 Weight indicator
 Coiled tubing internal pressure
 Wellhead pressure - WHP
 Data Acquisition unit
 Remote power pack control
Fig 2 Coil Tubing Reel unit

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The unit is fully insulated with a heater for cold climates and space for air
conditioning unit in warm climates. All necessary hoses to control and operate the
Injector Head, BOP’s, PowerPack and Tubing Reels are incorporated on hydraulically
powered reels on the front of the skid.
Injector Head:
The basic functions are:
• Tubing is gripped between contoured
blocks carried by two sets of chain
guided by rollers over the area of
contact between blocks and tubing .
• Each set of chains is powered by a
hydraulic motor, which drives through
a safety clutch and gearbox.
• The clutch prevents tubing falling into
hole in event of prime mover failure
and also serves as a brake.
• Continuous straightening device and
depth measuring odometer are mounted
on injector’s sub frame.
• On top of main frame of Injector head a
curved roller guide is present known as
Gooseneck for supporting tubing
during its transition from motion along the vertical axis of wellhead to the horizontal
coiling axis of storage reel. Fig 4 Injector Head
Injector Head
Fig 3 Control Cabin
Goose Neck

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Well Control Equipment
Proper well control equipment is another key component of CT operations, given that
a majority of these operations are performed in the presence of surface wellhead
pressure. Typical CT well control equipment consists of a BOP topped with a stripper
(high pressure CT units have two strippers and additional BOP components). All
components must be rated for the maximum wellhead pressure and temperature
possible for the planned field operation.
The stripper (sometimes referred to as a pack off or stuffing box)
provides the primary operational seal between pressurized wellbore fluids
and the surface environment. It is physically located between the BOP
and the injector head. The stripper provides a dynamic seal around the
CT during tripping and a static seal around the CT when there is no
movement. The latest style of stripper devices is designed with a side
door,that permits easy access and replacement of the sealing elements,
with the CT in place.
The BOP is situated beneath the stripper, and can also be used to
contain wellbore pressure. A CT BOP is designed specifically for CT
operations. It consists of several pairs of rams, with each ram designed to
perform a specific function. The number and type of ram pairs in a BOP are
determined by the BOP configuration: single, double, or quad. A quad system is
commonly used in most operations.
The four BOP rams, from top to bottomand their associated functions are:
 Blind ram - seals the wellbore when the CT is out of the BOP
 Shear ram - used to cut the CT
 Slip ram - supports the CT weight hanging below it (some are bi-directional and
prevent the CT from moving upward)
 Pipe ram - seals around the hanging CT
Fig 5 Injector Head Schematic
Fig 5 Stripper
Cut View
Fig 6 Stripper
Front View

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Standard CT BOPs also contain two equalizing ports, one on each side of the sealing
rams. It also has a side outlet between the slip and shear rams. This outlet can be used
as a safety kill line. BOPs are available in a range of sizes, and normally follow the
API flange sizes.
Ct String Design-
The length of CT on a reel varies depending on diameter. For comparison, a small reel
may only be able to hold 4,000 ft. of 2 7/8 in. tubing, but may have a 15,000 ft.
capacity if 1 1/2 in. tubing is spooled on it. A properly sized CT string must have the
following attributes for the planned operation:
 Enough mechanical strength to safely withstand the combination of forces
imposed by the job..
 Adequate stiffness to RIH to the required depth and/or push with the required
force.
 Light weight to reduce logistics problems and total cost.
 Maximum possible working life.
The simplest method of designing a CT string considers only the wall thickness
necessary at a given location for the required mechanical strength and the total weight
of the string. This method assumes the open-ended CT string is hanging vertically in a
fluid with the buoyed weight of the tubing being the only force acting on the string.
Starting at the bottom of the string and working up, the designer selects the wall
thickness at the top of each section that provides sufficient tensile force at that
location.
Fig 8 Coil Tubing Design parameters
Fig 7 Quad BOP

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Coil Tubing BHA:
1. Connector- This is used to connect coil tube with the bottom hole assembly. Also
called grapple connector. They have diameter of about 1.75 in.
2. The Motor Head Assembly (MHA): This is the essential core piece of equipment
for all reliable coiled tubing operations. It incorporates five standard tools in one
purpose built unit; the coil connector, dual flapper check valves, the safety disconnect,
and a dual circulating sub. The dual circulating sub combines a conventional drop ball
circulating sub and a pressure activated rupture disc. The standard MHA is rated to a
working pressure of 10,000 psi.
Two types of MHA are generally in use in perforation operation:
High flow MHA: This is used for cleaning job and its diameter of 1 inches and we
can pump up to 6 bpm thorough this MHA.
Low flow MHA: This is used for perforation and its diameter of 0.6 in. we can
pump up to maximum 3 bpm thorough this MHA.
3. Centralizer: Coiled Tubing will exhibit a residual curvature that tries to force the
end of the tools against the side of the well bore and causing possible hang ups on
nipples etc. The centralizer uses four bow springs to effect centralization.
4. Straight bar: The Straight Bar is specially designed coiled tubing operations. It is
approximately 2 feet long full flow through metal bar with a box - pin connection. The
Straight Bar is often used to extend very short tool strings, such as a simple cleanout
or lifting tool string. By extending a short tool string the possibility of standing up in
restrictions will reduce.
5. Casing collar locator (CCL): is equipment used to locate the casing collar in bore
well. It has 3 keys in it which help in finding collar.
6. Nozzle: These are the holes from which high velocity water, gel or slurry is pumped
out in bore hole. The diameter of nozzle is 0.1875 in. The high-velocity slurry cuts
through the casing and cement and into the formation. The resulting perforations serve
as excellent initiation points for fracturing. Assemblies having 3 nozzles are in use for
perforation by most company. The reverse circulation nozzles assemblies have 3
nozzles of diameter 0.5 in. for making cuts and 5 pair of reverse nozzle housing.

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MHA
Centralizer
Jetting Nozzle
MCCL Key
Fig 9 Coil Tubing BHA
Fig 10 Coil Tubing BHA
Fig 11 Roller Connector
Fig 12 Fullbore nozzle

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BHA SCHEMATIC
Fig 13 Coil Tubing BHA

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Advantages of Coil Tubing-
While the initial development of coiled tubing was spurred by the desire to work on
live wellbores, speed and economy have emerged as key advantages for application of
CT. In addition, the relatively small footprint and short rig-up time make CT even
more attractive for drilling and workover applications.
Some of the key benefits associated with the use of CT technology are as follows:
 Safe and efficient live well intervention
 Rapid mobilization and rig-up
 Ability to circulate while RIH/POOH
 Reduced trip time, resulting in less production downtime
 Reduced crew/personnel requirements
 Cost may be significantly reduced
Coiled tubing can also be fitted with internal electrical conductors or hydraulic
conduits, which enables downhole communication and power functions to be
established between the BHA and surface. In addition, modern CT strings provide
sufficient rigidity and strength to be pushed/pulled through highly deviated or
horizontal wellbores. This enables successful execution of downhole operations that
would be impossible to perform with conventional wireline approaches, or would be
cost prohibitive if performed by jointed-pipe.
Completion Applications
CT is routinely used as cost-effective solution for numerous workover applications. A
key advantage of CT in this application is the ability to continuously circulate through
the CT while utilizing CT pressure control equipment to treat a live well. This avoids
potential formation damage associated with well killing operations. The ability to
circulate with CT also enables the use of flow-activated or hydraulic tools. Other key
features of CT for workover applications include the inherent stiffness of the CT
string. This rigidity allows access to highly deviated/horizontal wellbores, and the
ability to apply significant tensile or compression forces downhole. In addition, CT
permits much faster trip times as compared to jointed pipe operations.
Pumping Applications
 Removing sand or fill from a wellbore
 Fracturing/acidizing a formation
 Unloading a well with nitrogen
 Gravel packing
 Cutting tubulars with fluid
 Pumping slurry plugs
 Zone isolation (to control flow profiles
 Scale removal (hydraulic)
 Removal of wax, hydrocarbon,
 or hydrate plugs
Mechanical Applications
 Setting a plug or packer
 Fishing
 Perforating
 Logging
 Scale removal (mechanical)
 Cutting tubulars (mechanical)
 Sliding sleeve operation
 Running a completion
 Straddles for zonal isolation
 Drilling

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Coil tubing Field Applications
The use of CT has continued to grow beyond the typical well cleanout and acid
stimulation application. This growth can be attributed to a multitude of factors,
including advances in CT technology and materials as well as the increased emphasis
on wellbores containing a horizontal and/or highly-deviated section.
Various uses are-:
 Well Unloading
 Cleanouts
 Acidizing/Stimulation
 Velocity Strings
 Fishing
 ToolConveyance
 Well Logging (real-time & memory)
 Setting/Retrieving Plugs
2. OPERATIONS OF COIL TUBING
Fracturing / Acidizing A Formation-
This CT application has experienced significant growth in recent years, and provides
several advantages versus conventional formation treatment techniques. In particular,
CT provides the ability to quickly move in and out of the hole (or be quickly
repositioned) when fracturing multiple zones in a single well. CT also provides the
ability to facture or accurately spot the treatment fluid to ensure complete coverage of
the zone of interest. When used in conjunction with an appropriate diversion
technique, more uniform treating of long target zones can be achieved. This is
particularly important in horizontal wellbores. At the end of the formation treating
operation, CT can be used to remove any sand plugs used in the treating process, and
to lift the well to be placed on production.
One of the earlier concerns with CT fracturing was the erosion effects that occur when
proppant is pumped during the fracturing operation and the resulting impact on CT
string life. An ultrasonic thickness (UT) gauge is now used on location to measure CT
thickness during the job. Data from these UT measurements can be used to adjust the
CT fatigue models, and to accurately monitor remaining CT string life.
Removing Sand or Fill from a Wellbore-
The removal of sand or fill from a wellbore is the most common CT operation
performed in the field. The process has several names, including sand washing, sand
jetting, sand cleanout, and fill removal. The objective of this process is to remove an
accumulation of solid particles in the wellbore. These materials will act to impede
fluid flow and reduce well productivity. In many cases CT is the only viable means of
removing fill from a wellbore. Fill includes materials such as formation sand or fines,
proppant flowback or fracture operation screenout, and gravel-pack failures.

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3. PROCEDURAL ANALYSIS OF FRACTURING
OPERATIONS USING COIL TUBING
 Running In-
o The coil tubing unit is spotted near the wellbore and the injector head is
connected to the wellhead.
o Then Brakes are released, lever arm is lifted coiled tubing is guided
through guide arch into the injector head.
o All the master valves are opened and coil tubing is run in to the hole
through Opti-frac Head into the wellbore.
 Depth Correlation-
o The mechanical casing collar locator (MCCL) is used for depth
correlation for CT assisted perforating and fracturing operations and is
absolutely critical for depth correlation when zones are thin.
o It indicates the casing collars and, in turn, helps correlate the depth
shown on the CT unit depth meter to the wireline depth. A clear weight
spike indicates a collar when the CT is POOH at a slow speed. The speed
at which the CT is POOH is an essential factor that determines the
prominence of the weight spikes.
o Distance between nozzle and key is ‘t’ m and Coil tubing will show the
depth of nozzle not key. If we have collar depth of X then the depth of
nozzle should be X+t and if CT is showing Y depth of tubing then,
Z= Y- (X +t)
Then Z will be correction factor and correct depth in CT by new depth
Y + Z
 Tagging of Cement Tag/ Sand Tag- Tag
o As we run into the wellbore the weight of the coil tubing will increase but
as we encounter sand or cement we find that the weight of tubing
decreases, this is called as tag. Tag is the indicator of encountering sand
or cement in the well.
o In a job first we tag at the top of the cement point. By this we will know
the sump for the Fracturing job.
 Perforating the coal seam
o Actual depth of near collar is seen in CCL graph where we have to cut
and start pulling out the coil to locate that collar. Calculate offset and
correct the depth in CT and pull the coil up to the depth where we have to
cut.
o Slurry (gel + proppant) is prepared at the time of locating the collar and
after that pump the slurry through coil tubing at an optimum rate &
pressure and displace it with gel.

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 Clean out process
o According to the amount of sump available we can either dump the
perforation or cleanout the sand by doing bottoms-up.
o Bottoms up to be performed from an appropriate depth (usually 10-15 m
below the perforation) to remove any unnecessary sand plug.
o Gel is pumped the through coil and pumped until we get clean (sand free)
returns. After getting clean return we will pull the coil up and make the
next perforation.
 Injectivity Test
o After perforation job, it is important to check whether the perforation is
able to intake the acid or not. To check the injectivity simply gel is
pumped at lower rate either from CT of annulus.
o Pressure was applied across the annulus and was maintained to about 500
psi over the initial shut-in pressure (ISIP) of the previous treatment and
circulation pressure response is observed.
o If perforation has not been choked with sand settled than pressure trend
would be either constant or breakdown would be observed. Once the
injectivity is confirmed, acid job is carried out.
 Acid Displacement
o In this acid is pumped down the CT and jetted onto the perforations.
Instant reaction between the acid and carbonates present in the cement in
the near-wellbore region occurred.
o Acid was jetted onto the perforations for a period of approximately 3 to 4
minutes.
o Once the acid was jetted, it was displaced into the annulus between the
CT and the casing. Because of issues relating to health, safety, and
environment (HSE) concerns, it was displaced to the annulus, and
immediately after the fracture was initiated, all the reaction products were
flowed into the formation, along with any unspent acid.
 Acid Squeezing-
o There were multiple instances where there were exceptional cement
losses in the formation. It was observed that it was still hard to break
down the formation, even with the acid so the annulus was closed and the
acid was squeezed into the perforation.
o In this case, any acid in the annulus would enter the perforations,
providing an extended duration of time to react with the cement and also
enter the cleat’s natural fractures, which would have been the path of
least resistance for any cement losses that would have occurred.
 Stand by During the Fracturing Job-
o After getting pressure breakdown in acid job we will pull the coil up to a
safe depth (around 100 m above the perforation) and proceed for

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fracturing job and pump gel from coil at minimum rate to maintain
pressure in the coil during fracturing job.
 Complete Cleanout of wellbore after completion of all fracturing Jobs-
o The typical procedure involved in this application is to circulate a fluid
through the CT while slowly penetrating the fill with an appropriate full-
bore nozzle attached to the end of the CT string. This action causes the
fill material to become entrained in the circulating fluid flow, and is
subsequently transported out of the wellbore through the CT/production
tubing annulus. This operation is called wiper trip.
o An alternative fill removal approach is to pump down the CT/production
tubing annulus and allow the returns to be transported to surface within
the CT string. This procedure, called reverse circulation, can be very
useful for removing large quantities of particulate, such as fracturing
sand, from the wellbore. It may also be applied when a particular
wellbore configuration precludes annular velocities sufficient to lift the
fill material.
4. BRIEF OF HYDRAULIC FRACTURING IN CBM
Hydraulic Fracturing
Most coalbed require some method of stimulation to adequately produce water from
seam and allow for production of gas. Although production may occur without
stimulation, experiences have proven that economics are greatly enhanced following a
fracturing treatment. Hydraulic fracturing typically involves injecting fluid made up of
water, sand and additives under high pressure into the cased well. The pressure caused
by the injection typically creates a fracture in the coal seam where the well is
perforated. For a large CSG treatment, the fracture might typically extend to a distance
of 200 to 300 meters from the well. The fractures grow slowly. The sand in the
hydraulic fracturing fluid acts to keep the fracture open after injection stops, and forms
a conductive channel in the coal through which the water and gas can travel back to
the well.
Aim of Hydraulic Fracturing
 Enhance the permeability of the cleat system in the coal, which in turn enhances
the dewatering process while lowering the reservoir pressure to the desorption
pressure, consequently allowing gas production to occur.
 Affect a large portion of the reservoir, increasing both productivity and
reserves.
 Improve the economics of the well by increasing water withdrawal,
consequently leading to a shorter period of dehydrating, decreasing the time
required for gas flow to maximize and increase the gas flow rate.

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Hydraulic Fracturing Fluid
Water and sand make up around 97 to 99 per cent of the hydraulic fracturing fluid.
Added chemicals make up about 1 to 3 per cent of the hydraulic fracturing fluid. Some
commonly used chemical additives, and their uses in hydraulic fracturing fluids,
include:
 Guar gum (a food thickening agent) is used to create a gel that transports sand
through the fracture.
 Bactericides, such as sodium hypochlorite (pool chlorine) and sodium
hydroxide (used to make soap), are used to prevent bacterial growth that
contaminates gas and restricts gas flow.
 ‘Breakers’, such as ammonium persulfate (used in hair bleach), that dissolve
hydraulic fracturing gels so that they can transmit water and gas.
 Surfactants, such as ethanol and the cleaning agent orange oil, are used to
increase fluid recovery from the fracture.
 Acids and alkalis, such as acetic acid (vinegar) and sodium carbonate (washing
soda)to control the acid balance of the hydraulic fracturing fluid.
Process of Hydraulic Fracturing
 Pad Stage
In the pad stage, fracturing fluid only is injected into the well to break down the
formation and create a pad. Pad is the initial part of the fracture fluid that creates the
fracture width and controls the initial fluid loss but contains no proppant. The pad is
created because the fracturing fluid injection rate is higher than the flow rate at which
the fluid can escape into the formation. In other words, when injection pressure
exceeds the formation break down pressure, fractures in formation gets created. It is
very similar to the acid fracturing.
 Slug Stage
Two stages of slug stage is added between the Pad stage. It is usually added to block
the multiple mini fractures that are created during the evolution of fracture geometry
therefore slug stage helps in decreasing the tortuosity of the path so that in the later job
designed amount of sand can be placed within optimum pressure ranges.
 Slurry Stage
After Pad and Slug Stage there starts slurry stage, in this sand is added to the
formation in ‘Ramp’ & ‘Hold’ pattern so as to avoid sudden hit of sand into the
formation which may otherwise lead to early screen out. Proppant is used to sustain
the effect of the minimum horizontal stress from closing the fracture. The effective
packing is the reflection of the effective permeability between the reservoir and the

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wellbore through fractures; also good packing lessens the flow back of the sand during
production stages.
 Flush Stage
In this step lower viscosity gel is used to clean the wellbore and displace all the sand
which is in the wellbore, and displace it inside fractures.
5. CONCLUSION – FRACTURING THROUGH COIL
TUBING ADVANTAGES & DISADVANTAGES
Advantages
1. The coiled tubing can be used to isolate the completion from the fracturing process.
By setting a squeeze packer at the end of the tubing, the hole tubing string is protected
from the pressure and temperature changes normally experienced by the completion.
2. Coiled tubing fracturing is particularly effective when working on monobore
completions, or on wells that have not yet been completed. By using an opposing cup
tool, the coiled tubing can be used to easily isolate one zone from another.
3. If required, the coiled tubing can be used to gas lift the well on to production after
the treatment(s).
4. Coiled tubing can often be used as an alternative to a workover. This can mean
significant cost saving, especially offshore.
Disadvantages
1. The extra cost of the coiled tubing unit, over and above the cost of the frac spread.
However, often this extra cost can produce savings in other areas (rig time, frac crew
time etc). The operating company must also be prepared to pay for some or all of the
cost of the coiled tubing string.
2. The extra space needed, due to the extra equipment required as compared to the frac
spread by it. Of course, if the CT unit is being used as an alternative to a workover rig,
this may not be as significant.
3. Rate limitations. In general, for a given fluid system, higher rates can be achieved
through completions than through coiled tubing. However, it should be remembered
that it is usually possible to take the static coiled tubing to higher pressures than the
completion/wellhead assembly.
4. Although it is possible to frac through coiled tubing with standard fluid systems, as
the depth increases and/or the coiled tubing diameter decreases, it may be necessary to
use more exotic and expensive fluid systems.

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References Used-
1. An Introduction To Coil Tubing, ICoTA, 2005.
2. Coil Tubing Equipment Corresponding Course, BJ services, 2005.
3. Hydraulic Fracturing Operations—Well Construction and Integrity Guidelines
4. Modern Fracturing , Enhanced Natural Gas Production, Economides, 2007.