Design Process for Completion and Workovers – Coiled

Microsoft Word - PCE-DEC-1-PC1Coiled Tubing System
The coiled tubing workover system primarily supplies a means of running small and medium diameter tubing
through the well production tubing (or larger diameter tubing into the casing), thus providing a circulating
path to the bottom of the well and similar to other concentric tubing systems. The following advantages are
apparent with coiled tubing:

o Coiled tubing can be run in the well against reasonable surface pressure, thus the well can be controlled
with a lowdensity, clean fluid, or not controlled at all; for many applications, a highpressure well does
not have to be killed with a damaging fluid
o Weight and size of the various coiled tubing components are such that transportation to an offshore
platform is facilitated since platforms and semisubs are designed with cranes and facilities to suit coiled
tubing operations lift requirements
o Tubing can be run at relatively high speeds of 150200 feet per minute, however, this is a maximum rate
and is not recommended for routine operations
o Circulation is possible while running and pulling and there are no collared connections in the string.
o In highly deviated (> 70°) wells, the inherent flexibility and strength of the coiled tubing permits it to be
pushed some distance into the deviated section to do servicing and tubingconveyed perforating, or, with
an electric cable inside the coiled tubing, production logging operations (the synergy between high
tensile strength pipes, chemicals, friction reducers, and downhole tools makes it possible to reach
hydraulic unit depths in wells with long horizontal sections
o New materials and the experience and innovation learned from applications suitable for coiled tubing
mean that it is currently common to find coiled tubing applications as part of the final well completion
either as a velocity string or equipment placement running tool
Figure 710 shows a typical rigup for an electric line job, on a highly deviated or horizontal well.
Figure 710 Coiled tubing rig up for electric line jobs on a highly
deviated well. Courtesy Halliburton
© PetroSkills, LLC. All rights reserved. _____________________________________________________________________________________________
1
COPYRIG HT

Services Variety of
Pipe Conveyed Fair No 2 Excellent No 2 90
Coiled Tubing Excellent Yes Good 3 Yes 90
LWD Limited Yes Excellent No 90
Wireline &
CT with Tractor Excellent Yes Excellent 4 Yes 90
1The hole deviation of 65 – 70 degrees for wireline is only achievable in cased holes. In open hole, the
number is more like 45 degrees. 2Pipe conveyed logging cannot be done at constant speed and there is no way to log under pressure. 3Pipe conveyed logging outperforms coiled tubing in extended reach horizontal wells. Buckling of the
coiled tubing limits its capability to push far out into horizontal wells. Software can help predict how far
out it will reach. 4Different tractor types are available with different advantages and disadvantages. Not all are capable of
operating in open hole sections.

Some of these characteristics are inherent to the standard applications of coiled tubing, thus it is

Primary coiled tubing unit components are the injector hoist unit, well control stack, continuous tubing,
and the storage reel.
Coiled Tubing
The tubing itself is usually of several common working outside diameter sizes such as 11/4in, 11/2in,
13/4in, or 23/8in. pipe (noting that, in certain areas, 27/8in. or larger pipe is available). Tubing is
milled from 80,000 to 120,000 psi minimum yield alloy steel (noting that 70,000 psi minimum yield alloy
steel is still available for some specific applications).

Various wall thicknesses are available from the pipe suppliers with different pressure drop (loss) for
each size.
2
Table 715 shows typical specifications for smaller OD pipes.
Table 715
psi, Elongation, 20% min 2 in.
Hardness22 Rc max
OD OD OD
Weight, lbs/ft 0.848 1.081 1.836
Wall area, sq in. 0.250 0.318 0.540
Load capacity, lbs (below) (below) (below)
Yield (min) 17,500 22,260 37,800
Ultimate (min) 20,000 25,440 43,200
Press. capacity2,
Torque, yield, ft lbs 306 504 1,001
Internal capacity (below) (below) (below)
Bbls/1000 ft 0.663 1.124 1,518
Ext. displacement (below) (below) (below)
Bbls/1000 ft 0.971 1.518 2.186

3
COPYRIG HT
The weak point in coiled tubing is the tubetotube butt weld and can be eliminated by using the bias
weld technique.

Taper and trutaper pipes allow thinner wall thickness, therefore lighter pipe sections on the downhole
end of the coiled tubing and thicker, heavier wall thickness on the pipe core (reel) end. Using this
concept, the depth for coiled tubing intervention has increased from initial tubing designs. Additionally,
new technology uses a slightly modified injector heads to run the tapered OD string in order to increase
intervention depth. Figure 714 compares the different pipe diameter designs and their approximate
rated depths.

The tubing reel, normally 810 ft in diameter, is powered by hydraulic drive to maintain tension on the
tubing and uses a "level wind" mechanism to reel the tubing uniformly. A manifold built into the reel
inlet connects the fluid pumping system to the tubing; the fluid from storage tanks connects to the reel
axis at the fluid head connection. With the coiled tubing having been run to a well’s working depth, well
circulation involves pumping fluids through all of the tubing on the reel as well as the tubing actually in
the well. An operating advantage for consideration is that the well can be circulated while running
tubing into or pulling tubing from the well.

Working with the friction pressure loss in smaller 100 in. OD x 0.095 in. wall thickness tubing is a
challenge as a 375 psi/1000 ft of tubing pressure loss will occur when pumping fresh water at 0.5
bbl/min; about 70% less friction loss will occur when the water is treated with friction reduction
chemicals in the fluids. Using a 11/4 in. OD x 0.095 in. wall thickness, tubing pressure loss with water at
1 bbl/min is 359 psi/1,000 ft. With 11/2 in. OD x 0.109 in. wall thickness, tubing pressure loss drops to
138 psi/1,000 ft at 1 bbl/min with fresh water. With 200 in. OD x 0.125 in. wall thickness tubing, loss

Table 716 compares circulating rates and times for 1 in. (original design tubing size not presently used
today for downhole applications), 11/4in., and 11/2in. coiled tubing inside 51/2in., 17 lb/ft casing.
This table shows the limitation of low annulus velocity, due to low rate or a big annular flow area, or, a
Design Process for Completion and Workovers – Coiled Tubing Systems
4
COPYRIG HT
combination of both. Such design specification becomes an important issue when removing / lifting
solids from the well in the tubing / coiled tubing annulus. Such is an incentive for larger OD coiled tubing
or for reverse circulation. Reverse circulating fluids upward through coiled tubing in the well and on the
reel is a technique that must be carefully considered as this pumping method (a) exerts pressure on the
formation that could exceed fracture pressure, and, (b) exerts annulus pressure that could possibly
collapse the coiled tubing. Published collapse strength data on coiled tubing applies to new, round pipe.
However, due to regular wear and tear, every new coiled tubing pipe has its ovalilty reduced by as much
as 1% under each pass of the stresses exerted by the continuous gripper action of the injector during the
useful life of the coiled tubing string. Therefore, the predicted or calculated collapse pressure will
decrease dramatically from new coiled tubing conditions to older tubing that is worn. In earlier usage of
coiled tubing, a working collapse pressure of 1,000 to 1,500 psi was considered an upper limit. Today,
with new metallographic structures/compositions for coiled tubing manufacturing, knowledge of
materials behavior, simulation software, careful monitoring of the coiled tubing and prudent field
practices, the limit has been raised significantly.

Table 716
Comparison of 1in., 11/4in., and 11/2in. OD Coiled Tubing Circulation at 11,000 ft
51/2in., 17 lb/ft casing
Tubing
11/4 45 4911 15.8 0.82 0:15 3:43 3:58
11/2 78 4968 17.9 1.47 0:12 2:17 2:29

A key to success in coiled tubing operations is having a healthy respect for the forces exerted on the
tubing in well operations, particularly in highly deviated holes. In a more or less vertical well, the surface
weight indicator, with small corrections for residual bending and buoyancy, gives an accurate indication
of downhole forces acting on the tubing (noting that a 13/4in. coiled tubing string weighs about 2
lb/ft). With a highly deviated hole, however, the surfaceindicated weight decreases as the tubing is
"pushed" into the deviated section; there is no correlation between surface load or movement and
downhole movement. Several forces and effects must be taken into account including buoyancy,

The buoyant weight of each element in the coiled tubing exerts a tensile effect on other elements. This
weight is affected by the density of internal and external fluids and contributes to the friction force on

A residual bend (radius of curvature of about 20 feet) remains in the tubing after it passes through the
wellhead assembly. This accentuates the tendency for the tubing to form a helical configuration as it is
5
COPYRIG HT
pushed into a straight hole. The period of the helix increases (tubing straightens) as tension increases,
but as tubing tension decreases, the helical buckling becomes tighter, thus causing additional friction
against the side of the hole which further tightens the helix. At some point, the frictional forces equal
the forces pushing the tubing, lockup occurs, and, with these existing conditions, the tubing cannot be
pushed further into the deviated hole. Chemical friction reducers and mechanical tubing ‘tractors’ are

Hole profile affects the total effective tubing load, first, because the friction of the tubing moving on the
low side of the hole depends on the deviation angle, and second, because of the "belt effect" that
occurs as tubing is pulled against the inside of a curved hole while trying to withdraw it from a deviated
section.

Wellhead pressure tries to force the coiled tubing out of the hole, and, with larger tubing and higher
wellhead pressures, this can be a significant effect. A phenomenon known as ‘catastrophic buckling’
could occur when the force needed to move the coiled tubing downward is higher than its resistance to
column failure.

Reel backtension, necessary to keep the tubing under control on the spool, affects the load cell
indication located under the injector head. Thus, it must be accounted for, even though it does not

Stripper friction depends on wellhead pressure and the force applied to the stripper element to prevent
leakage. In some situations, lubricant can reduce this effect.

Fluid friction caused by flow in the tubing or annulus affects tubing stress although vibrations caused by
flow may actually reduce helical buckling frictional effects. Jetting applies a force at the end of the
tubing, opposing that of the fluid. This dragging effect is usually important on pinpoint jobs with high
annular pump rates.

Models are available to predict forces acting on the coiled tubing and an example is illustrated in Figure
715. Pre planning and modeling are a necessary component of any planned operation, especially those
that will test the limits of the tubing and associated equipment. Answers must always be made available
for the following questions:

o What is the apparent weight (surface load cell read out) of coiled tubing running in or pulling
out of hole?
o What are the maximum stresses acting on the tubing running in or pulling out?
o Over what distance can the coiled tubing can be safely pushed into a highly deviated wellbore?
o What force can be exerted, push or pull, at the end of the coiled tubing? (This question is quite
important because some tools will only work on a certain force range; examples are mud
motors, hydraulic jars on fishing BHA, and others.

6

Coiled Tubing Failures
Coiled tubing life is a function of the record of the work performed by a tubing string. It can be quite
short, varying from 20 trips where high pulls and pressures are involved, to 100 trips when working
under lowtensile stress, lowburst conditions. Factors that contribute to the failure of coiled tubing
include:
o Pump pressure applied
o Corrosivity and abrasiveness of fluids in well bore or pumped through tubing
o Tubing ovality condition and mechanical damage
The key factor determining pipe life is known as ‘fatigue' and is illustrated in Figure 716. It is primarily
the cumulative effect of cold work on the coiled tubing pipe cycling over the reel and the injector head.
Every time the pipe bends, regardless of the pressure, fatigue will increase. If the bending occurs in the
presence of pressure, the fatigue increase will be directly proportional. Fatigue is quite important,
because it affects the physical properties of the tubing. Therefore, the tensile strength for a totally used
tubing will be lower than for new pipe with the same characteristics. A fatigued pipe will be more likely
to fail than a newer, less fatigued pipe, under the same working conditions moving forward. There are
different approaches on how to calculate fatigue but all of them use statistical models based on tests
and experience. Fatigue will be calculated (usually in real time) using variables collected and recorded
during the job in order to keep track of the useful life still available on every pipe. In any case, this is the
primary indicator of pipe suitability for a particular job.
7

Additionally, some inspection devices mounted on the work reel can be used to monitor pipe
dimensions and superficial damage that cannot be simulated/tracked by fatigue algorithms. Such is not

A database should be maintained on each coiled tubing pipe describing its historical record of service so
that it can be retired when it can no longer be safely run in the well.
8

Documents

Design Process for Completion and Workovers – Coiled