Note: Descriptions are shown in the official language in which they were submitted.
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PAR'T'IAL COQ.IN-COII. TUBING
Field of Invention
The invention relates to coiled tubing strings, and in particular to at least
partial dual tubing strings, including methods for assembling such strings.
BACKGROUND OF INVENTION
This invention is tangentially related to U.S. Patent No. 5,638,904 -
Safeguarded Method and Apparatus for Fluid Communication Using Coiled
Tubing, With Application to Drill Stem Testing - Inventors Misselbrook et al.;
PCT Application US 97/03563 filed 3/5/97 for Method and Apparatus using Coil-
in-Coil Tubing for Well Formation, Treatment, Test and Measurement Operations
- Inventors Misselbrook et al; and US SN 08/564,357 entitled Insulated and/or
Concentric Coiled Tubing.
The instant invention relates to apparatus and assembly for at least a partial
dual tubing or "coil-in-coil" tubing string, sometimes referred to as PCCT,
wherein an inner tubing is sealed within an outer coiled tubing. It is to be
understood that although the term coil-in-coil may be used, the "inner tubing"
need not necessarily be "coiled tubing", or "coiled tubing" as it is known or
practiced today. Standard "coiled tubing" as the "inner tubing" does afford a
practical solution for first embodiments. The inner tubing, however, could
comprise a liner, for instance. Further. there may or may not be an annulus
per se
defined between the inner and the outer tubing, in whole or in part. Any
annulus
formed is preferably narrow.
Since providing dual tubing in a string should raise the cost of a string,
there may be a cost advantage to. minimizing the length of the dual portion.
Hence, "partial" coil-in-coil strings, or PCCT, may have cost advantages. A
general purpose multi-use partial dual string should have enough dual length
to
cover the anticipated length of well interval to be serviced. The overall
length of
the PCCT string will be chosen to service a typical depth range of wells in a
particular location. But, coiled tubing may be added or removed from the
bottom
of the outer coiled tubing string to suit wells outside of the standard depth
range.
A full dual tubing string, of course, would perform adequately but would be
more
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expensive. Alternately, a partial dual string could be formed by connecting a
full
dual portion with a single portion. Such a partial dual string could be pre-
formed
and transported to a job or formed at a job site.
A key purpose for using an at least partial dual string is to provide a
protective barrier at the surface to enable,safe pumping of well fluids up or
down.
(Surface is used generally herein to .refer to above the wellhead.) To provide
this.
benefit, a dual string has a sealed annulus or the tubings are sealed
together, in
whole or in part. A dual tubing string annulus preferably would be sealed at
or
proximate a lower end of the inner tubing. and the seal is preferably .located
across
the annulus between the inner and outer coiled tubing, most preferably within
the
outer coiled tubing. Preferably also, any annulus would be=narrow, to maximize
working space. Means can be provided to monitor fluid status, such as fluid
flow
or pressure, within any annulus. formed. A pressurized fluid such as nitrogen
could be injected, for instance, into the annulus, or existing fluid within an
annulus could be pressured up.
Coiled tubing is commonly utilized in well servicing for working over
wells. In a workover, a continuous coiled tubing string is injected into a
live well
using an associated stuffing box located over the wellhead. Many coiled tubing
workovers take place under live well conditions. Coiled tubing has proven
particularly useful when working through production tubing or
eompletion.tubing.
In normal operations coiled tubing is over-pressured vis a vis well pressure.
This insures that were any leaks to develop in the tubing, they would.result
in flow
out of the tubing rather than the reverse, which is important for safety
reasons.
Pressure in the coiled tubing also keeps well fluids from backing up the
tubing
bore. Well fluids are relegated to the. annular space. between the coiled
tubing and
the production tubing or completion tubing. If produced up the annular space
outside the coiled tubing, well fluids can be handled in the usual safe manner
at a
wellhead.
Fluids pumped down through a coiled tubing string typically enter the
tubing at a valve located upon an axle of the reel. carrying the string. The
fluids
run through the remaining tubing wound around the reel, over the gooseneck,
down the injector, through the stuffing box, through the wellhead and down the
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wellbore. Any fluids pumped down a coiled tubing string thus may traverse a.
significant length of tubing on the surface.
The instant invention anticipates that some live well applications could be
more effectively performed with coiled tubing if well fluids were permitted to
be
circulated up through the tubing rather than up the annulus. For some
applications, for instance, the annulus outside of the tubing provides a more
effective path for pumping down, leaving the bore for reverse circulating up.
E.g.,
a gravel pack might be more effective if a gravel slurry, were pumped down the
broader production tubing - coiled tubing annular region than down the
narrower
coiled tubing bore. Higher circulation rates might be achieved by pumping the
slurry down the annulus. This is particularly true because fluid pumped down
the
bore must pass through a crossover tool near the bottom. Coiled tubing pack-
off
and crossover tools can be expensive, and the narrow flow paths inherent in
miniature tools offer potential sites for blockages. A potential benefit of
the
proposed system lies in the elimination of the need for complex combination
pack-
off and crossover tools. Eliminating coiled tubing crossover tools and their
associated packers could lead to improved reliability of operations. The
proposed
system could also alleviate bridging and lead to improved sand pack
uniformity.
Another application where a coiled tubing bore offers a more efficient
channel for circulating well fluids up a well than the completion-coiled
tubing
annulus is a well cleanout. Well cleanout requires raising sand, gravel or
particulate matter collected at the bottom of a wellhole. Raising particulate
matter, without it settling out, necessitates establishing an upward flow
velocity
that is a certain multiple of the settling velocity of the particles in the
liquid.
Additional difficulty and complexity occurs when raising particulate matter in
deviated wells. As a result quite high flow rates may be needed to effect a
sufficient liquid velocity in an annulus to carry particles up. Sometimes the
flow
rates required are only achievable using the larger sizes of coiled tubing
which can
be impractical or else uneconomic. Since the annulus between a coiled tubing
and
completion typically has a larger cross-sectional area than the tubing bore
itself, a
lesser flow rate pressure would be needed to achieve the same fluid velocity
up the
bore.
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A third live well application for a dual coiled tubing string in accordance
with the instant invention lies in using potentially readily available natural
gas to
unload liquid from live wells. When natural gas is available at a wellhead,
from
either the same or neighboring wells, such gas may be quite cost effective as
a gas
lift fluid.. However, pumping natural gas down through coiled tubing must be
protected at the surface above the wellhead. Personnel and the environment
must
be safeguarded from leaks that could develop in the coil before the gas passes
below the wellhead.
Historically, transporting well fluids at the surface above a wellhead
through normal coiled tubing has been deemed hazardous. Such is currently
banned for most offshore operations and is generally unacceptable for
many.land
operations. Coiled tubing becomes bent beyond its yield point when moved off a
reel and over a gooseneck by an injector. This plastic bending activity
typically
takes place with a high pressure applied to the interior of the tubing. A
pressure
differential across the tubing wall during bending increases stress levels in
the
tubing and accelerates the onset of fatigue cracking. Chemicals used in well
operations occasionally tend to pit and corrode tubing material. Chemical
corrosion and accumulated fatigue can ultimately lead to small cracks in the
wall
of the tubing, culminating in a "pin-hole" in the tubing. While it is possible
to
limit the incidence of "pure fatigue pin holes" by careful management of the
fatigue cycles experienced by the tubing, other stress in the tubing can lead
to
unexpected and premature pin-holes. Today most pin-holes in coiled tubing
propagate from stress risers caused by corrosion, the most common cause of
such
pin-holes being internal pitting from chloride corrosion. Because chlorides
are
common in the oilfield (seawater, NCI, CaCI,, etc.) it is almost impossible to
eliminate the possibility of a corrosion pit. The second most common corrosion
mechanism is stress corrosion cracking (SCC) arising from exposure to hydrogen
sulfide.
A leak of well fluid through a crack or a pinhole in a string between the
wellhead and a reel endangers life and the environment. A small hole or crack
functions as an atomizer, spraying pressurized fluid from within the tubing
to.the
surroundings above ground. A pooling of leaked gas could be ignited by a
spark.
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Hydrogen sulfide or the like might be contained within the well fluid, to
mention
another danger.
The crux of the problem with the transportation of well fluids on the surface
in
coiled tubing is that between the wellhead and the reel valve there is no
protective
barrier for the crew and the environment against leaks from the tubing. The
possibility
of leaks is not sufficiently remote. A dual tubing string, or an at least
partial coil-in-
coil tubing, as taught by the present invention, can cost-effectively provide
the needed
double barrier to permit well fluids to be safely circulated up or down on the
surface
through coiled tubing as may be particularly suitable in certain operations.
Since a double barrier is crucial when the well fluids travel between the
wellhead and the surface valve, an inner tubing in a dual string should be at
least long
enough, taking into account the wells and their intended applications, to
extend on the
surface from a reel connection through a wellhead during the critical pumping
or
"reverse circulation" operation.
SUMMARY OF THE INVENTION
In accordance with one embodiment of the present invention, there is provided
a coiled tubing system for circulating fluids in a wellbore comprising:
a coiled tubing string;
a check valve attached to the coiled tubing string, the check valve having a
fluid passageway therethrough and a biased flapper wherein the flapper is
biased to
close the fluid passageway to prevent fluid flow up through the check valve
and into
the coiled tubing string, the biasing force may be overcome to allow fluid
flowed down
the coiled tubing string and through the check valve; and
a shiftable sleeve located in the fluid passageway of the check valve wherein
the sleeve is shiftable from a first position where the sleeve prevents the
flapper from
closing the fluid passageway to allow reverse circulating through the valve
and a
second position where the biasing force may bias the flapper to close the
fluid
passageway.
In accordance with another embodiment of the present invention, there is
provided a method of circulating fluids through a coiled tubing string
comprising the
steps of:
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providing a cyclic check valve in the coil tubing string;
positioning the coil tubing string in a wellbore wherein an annulus is created
about the outer diameter of the coiled tubing string;
circulating fluid down the annulus and up through the check valve and into the
coiled tubing string; and
cycling the check valve to prevent fluid flow from flowing up through the
valve
and into the coiled tubing.
In accordance with a further embodiment of the present invention, there is
provided a coiled tubing assembly for circulating fluid in a wellbore
comprising:
a coiled tubing string, the string having a first end attached to a reel and a
distal
end for lowering into the wellbore;
a cyclic check valve attached proximate to the distal end of the coiled tubing
string, the check valve having a fluid passageway therethrough and a valve
closure
means for preventing fluid flow up through the fluid passageway of the check
valve and
into the coiled tubing string; and
a means for activating the valve closure means.
The instant invention of an at least partial dual tubing string comprises an
inner
tubing within an outer coiled tubing for at least an upper portion of the
string.
Preferably the inner tubing is equal to or less than 80% of the length of the
outer tubing.
Preferably also the outside diameter of the inner tubing is greater than or
equal to 80%
of the inside diameter of the outer tubing. The inner tubing is sealed against
the outer
tubing at at least a lower portion of the inner tubing.
In one embodiment a seal is structured to permit some longitudinal movement
between an end of the inner tubing and the outer tubing. Preferably the seal
is located
within the outer tubing. Alternately a seal may fix, or cooperate with an
element that
fixes, the relative location of an end portion of the inner tubing with
respect to the outer
tubing.
An upset or stop maybe attached or formed onto an inner wall of the outer
tubing. The stop may be positioned to limit longitudinal movement of an end of
the
inner tubing relative to outer tubing. The inner tubing may be inserted such
that it is
compressed against and biased against the stop within the outer tubing.
Preferably any
annulus defined between the inner tubing and the outer tubing is
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quite narrow. The inner tubing could be of the same or of different material
as the
outer string. Conveniently, the inner tubing could be coiled tubing of
slightly
smaller diameter. Preferred materials for the inner tubing include aluminum,
titanium, beryllium-copper, corrosion resistant alloy materials, plastics with
or
without reinforcement, composite materials and any other suitable material.
In some embodiments, an inner tubing would run at least 1/2 of the length
of the outer tubing, and preferably approximately 1/4 to 1/3 of the length of
the
outer tubing.
Fluid or pressurized fluid may be inserted in a defined annulus between the
tubings and its status or pressure monitored. A fluid, such as nitrogen gas
may be
provided in the annulus. Changes in the pressure of this annulus fluid would
indicate a leak in either the inner tubing or the outer tubing. In either case
the
well could be shut in and work stopped to maximize the safety. of the crew and
the
environment.
As a further safety measure, a safety check valve may be attached to a
lower end of the string.
It is possible to construct a "composite" string out of single coil and full
or
partial coil-in-coil by prejoining them or by delivering both on one spool to
a job
and joining them together into one string with a connector or a weld as they
are
being run into the well.
The invention further includes a method for assembling partial coil-in-coil
or dual tubing. In one embodiment a tubing string may be assembled by
inserting
an upper end of an inner tubing into a lower end of an outer tubing and moving
the
upper end of the inner tubing to an upper end of the outer tubing. This method
may include reeling the assembled string onto a first reel and then re-reeling
the
string onto a second reel. An advantage of such method of assembly is that a
directional sliding seal may be attached to the lower end of the inner tubing
prior
to inserting that lower end into the lower end of the outer tubing. This
directional
seal may slide relatively easily in one direction, e.g. the direction of
insertion, but
resist sliding and rather vigorously against the inside wall of the outer
tubing
when the inner tubing is attempted to be moved in the opposite direction.
In another embodiment, the inner tubing may be welded or connected at its
lower end to a sealing section, such as a slip mandrel. The sealing may be
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designed to be swaged out, or forced out by a slip, to form a mechanical fixed
connection between the tubings. Fluid seals can back up the mechanical
connection.
Another method for assembling partial coil-in-coil tubing may include
affixing a stop on an inside wall portion of the outer tubing. The stop would
be
fixed at a location suitable to limit longitudinal motion of an end of an
inner
tubing within he outer tubing. A stop may be readily introduced on to the flat
steel strip at the time of manufacture of the outer coiled tubing string. A
stop
could be useful if a fixed seal were to be effected between the inner tubing
and
outer tubing, or if relative movement between the tubings is to be restricted.
The
inner tubing could be assembled in the outer tubing so as to be compressed
against
and bias against the stop.
In a further method for assembling a working coiled tubing string, a length
of regular coil and full coil-in-coil length can be welded or connected or
delivered to a job unconnected, including on one reel. A single coil and a
double
coil can be made into one string on a job by manually joining a stringer with
a
connector as they are run into a well.
Seals may be activated by mechanical means, chemicals, radiation, or heat.
The inner tubing may be a liner glued, secured by adhesive, or fused in place.
A
liner might even be formed in place within the outer tubing.
In accordance with an aspect of the present invention, there is provided a
coiled tubing system for circulating fluids in a wellbore comprising:
a coiled tubing string;
a check valve attached to the coiled tubing string, the check valve having a
fluid passageway therethrough and a biased flapper wherein the flapper is
biased to
close the fluid passageway to prevent fluid flow up through the check valve
and into
the coiled tubing string, the biasing force may be overcome to allow fluid
flowed
down the coiled tubing string and through the check valve; and
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a shiftable sleeve located in the fluid passageway of the check valve, wherein
the sleeve is shiftable from a first position, where the sleeve prevents the
flapper from
closing the fluid passageway, to allow reverse circulating through the valve
and a
second position where the biasing force may bias the flapper to close the
fluid
passageway;
wherein the shiftable sleeve includes a ball seat for receiving a ball, and
wherein the sleeve is shiftable from the first position to the second position
by
fluid pressure applied to the ball when the ball is located in the ball seat.
In accordance with another aspect of the present invention, there is provided
a
method of circulating fluids through a coiled tubing string comprising the
steps of.
providing a cyclic check valve in the coil tubing string;
positioning the coil tubing string in a wellbore wherein an annulus is created
about the outer diameter of the coiled tubing string;
circulating fluid down the annulus and up through the check valve and into the
coiled tubing string; and
cycling the check valve to prevent fluid flow from flowing up through the
valve and into the coiled tubing string; and
shifting a sleeve from a first position to a second position by hydraulic
pressure acting on a ball and ball seat arrangement on the sleeve.
In accordance with a further aspect of the present invention, there is
provided
a coiled tubing assembly for circulating fluid in a wellbore comprising:
a coiled tubing string, the string having a first end attached to a reel and a
distal end for lowering into the wellbore;
a cyclic check valve attached proximate to the distal end of the coiled tubing
string, the check valve having a fluid passageway therethrough and a valve
closure
means for preventing fluid flow up through the fluid passageway of the check
valve
and into the coiled tubing string; and
a means for activating the valve closure means, including a shiftable sleeve,
wherein the sleeve comprises a ball seat for receiving a ball, and
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wherein the sleeve may be shifted from the first position to the second
position
by fluid pressure applied to the ball when the ball is located in the ball
seat.
BRIEF DESCRIPTION OF THE DRAWINGS
A better understanding of the present invention can be obtained when the
following detailed description of the preferred embodiment is considered in
conjunction with the following drawings, in which:
Figure 1 illustrates a partial coil-in-coil tubing string in a well.
Figures 2 and 2A illustrate a coiled tubing reel and valving associated
therewith for coil-in-coil or a dual tubing string.
Figures 3A-3D illustrate fixed seal systems.
Figure 4 illustrates sealing an inner tubing within a coiled tubing string
including stops on an inside wall of the tubing string.
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Figures 5 illustrates movable seals for sealing an annulus between an inner
tubing and a coiled tubing string proximate an end of the inner tubing.
Figures 6 illustrates a deformable seal system.
Figures 7A-7C illustrate a safety valve sub appropriate for use at the end of
a coiled tubing string.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
Narrow, when used herein to refer to a narrow annulus, is intended to refer
to a dual tubing or coil-in-coil annulus wherein the OD of an inner tubing is
slightly smaller than the ID of an outer tubing. The difference between the OD
and ID might be 1/10" of an inch or even less. Lower, as used herein in
reference
to coiled tubing, refers to portions of a string toward a distal end of the
string, the
end not connected to the reel in use. Upper refers to tubing portions
proximate a
string end connected to the reel in use. A tendency for longitudinal movement
of
an inner tubing relative to an outer tubing during reeling out and in is
discussed
below. It should be understood that a seal that is structured to permit and
cooperate with such longitudinal movement might also permit axial or
rotational
or other sorts of movement as well. Such other movement is not intended to be
excluded. Generally, the phrase "on the surface" refers to above the wellhead.
Coiled tubing, as known in the art, is coiled upon a truckable reel. An upset
on a
tubing inner surface may be generally referred to as a stop. A weld bend is a
prime example of such a stop. Circulating well fluid through a string includes
moving any potentially hazardous well fluid up or down coiled tubing where.
the
fluid traverses tubing portions on the surface, which is where protection
afforded
by a double tubing or double wall could be important.
Figure 1 illustrates in general a coiled tubing strings, and in particular a
partial coil-in-coil string embodiment, PCCT, inserted in a well. Truck T (not
shown) carries reel R having string S. String S carried on reel R contains,
for a
portion of its upper length, inner tubing IT within outer tubing OT. As
deployed,
inner tubing IT extends beneath wellhead WH in wellbore WB. Seal SL seals the
annulus between inner tubing IT and string S proximate an end of inner tubing
IT.
Subsequent figures illustrate favored sealing systems in detail. Of course
PCCT
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could be formed by connecting a sealed full dual coil, at SL, with a lower
length
of single coil.
Preferably, the outer diameter of inner tubing IT is only slightly smaller
than the inside diameter of outer tubing OT of string S, yielding a narrow
annulus.
For instance a 1 3/16 inch OD inner coiled tubing string might be inserted
into an
approximately 1 1/2 inch OD outer coiled tubing string. In attempting to
create
coil-in-coil with such a narrow annulus, considerations of the possible
ovality of
each tubing should be taken into account, as well as wall thickness and
available
methods and techniques forinsertion.
The wellbore WB in Figure 1 illustrates production tubing PT within the
well together with a coiled tubing string, although not to scale. In practice,
operating coiled tubing through production tubing places a significant
constraint
on the maximum outside diameter of a string that can be used, in general.
As is known in the art, in Figure 1 coiled tubing string S is shown winding
from reel R over gooseneck G, through injector head I, through stuffing box
SB,
through wellhead WH and then downhole. Figure 1 also illustrates a safety
valve
sub SV attached to the bottom of coiled tubing string S. Operating in a live
well
suggests that not only should there be a double barrier between the wellhead
and a
tubing valve, which is located typically on a reel, when producing up the
tubing or
flowing well fluids in the string, but also that there possibly should be an
extra
safety factor such as a safety valve at the end of the coiled tubing string.
The
safety valve is particularly useful when the coiled tubing string is being
pulled out
of the hole and the end of any inner tubing is reeled up past the wellhead. A
safety valve sub compliments the functionally of an at least partial dual
tubing
string.
Figures 2 and 2A illustrate valving mechanism systems that can be located
on coiled tubing reel R. Rotating joint valving mechanisms for normal coiled
tubing are known in the art and are indicated but not shown in detail. The
tubing
string reeled on reel R in Figures 2 and 2A is indicated as having outer
tubing OT
and within it inner tubing IT. At the reel, inner tubing IT could be conveying
well
fluid WF in accordance with the instant invention, and thus inner tubing IT
should
extend through the reel to a valve such as a conventional rotating joint
valve.
Outer tubing OT may be terminated at a convenient point on the reel, as at
pack-
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off assembly V. Pressurized gas container 26 is illustrated as available for
pressuring up annulus 21 between the inner tubing IT and outer tubing OT. Gage
20 is illustrated on reel R, attached and located for indicating the pressure
being
maintained in the annulus between inner tubing IT and outer tubing O.T.
Annulus
21 might be pressured up to 500 psi with nitrogen in practice. Preferably,
gage 20
would transmit signals to a cab or the like on truck T for convenient readout,
or at
least be easily visible. Preferably the operator of truck T could conveniently
monitor the pressure on gage 20.
It should be understood that the inner tubing could be a liner. and not even
coiled tubing. The liner could define an annular space within the outer tubing
or
fit against, in whole or in part, the outer tubing wall. The liner could be
preformed or could actually be formed in place in the first instance within
the
outer tubing. A liner could be fused, glued, or secured by adhesive, in whole
or in
part, to the outer tubing. Cryogenic methods could be used to shrink a liner
during
installation. Heat, chemicals or radiation could be used to effect a seal.
Any seal of an inner tubing, be it coiled tubing, liner or otherwise, that
significantly increases the stiffness of even a portion of a string may
adversely
affect string lifetime. The choice of seal between the tubing, thus, must take
into
account the effect of the seal on the practical lifetime of the string or it
is coiled
and uncoiled.
It should further be taken into account when designing seals that coiled
tubing, although coilable on a truckable reel, is yet relatively stiff.
Experience
indicates that an inner tubing, where the inner tubing. also comprises coiled
tubing,
will tend to assume a maximum possible diameter when coiled on a reel R inside
of an outer tubing OT. Thus, the mean diameter of an inner coil IT would
likely
be slightly larger than the mean diameter of an outer coil OT when the string
is
coiled on a reel. Hence, per coil on the reel, inner coil IT will be slightly
longer
than outer coil OT. When such a coil-in-coil string S is straightened out, as
when
injecting the string into a wellbore, the inner coil, being slightly longer,
should
tend, to want to move longitudinally down with respect to the outer coil and
should
press against elements impeding such movement. Alternately, the inner coil may
tend to retreat within the outer coil when reeled in.
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With the above in mind, as illustrated the in embodiments of Figures 3, 4, 5
and 6. several sealing systems are particularly considered for use in an at
least
partial dual tubing string. A seal isolates from fluid communication at least
one
end of, if not the whole of, an annulus or space formed between an inner
tubing
and an outer coiled tubing. Preferably, the seal is at least attached
proximate to
the lower end of the inner tubing and preferably seals against the ID of an
outer
coiled tubing.
Seals with low mechanical strength may not anchor themselves against an
outer coiled tubing string. Methods to reduce or restrict relative movement of
the
tubings, including seals or means that anchor and other elements such as
deformable tubes or slips that anchor, may be desirable. It is important,
however,
that any sealing and/or fixing mechanism retain itself sufficient flexibility
to
withstand repeated coiling and uncoiling of the string as it spools on and off
a
reel. Thus, methods to fix or reduce tubing movement should not significantly
compromise the bending flexibility of the string and seal.
A simple internal upset or stop in an outer coiled tubing may be arranged
(such as by a miniature weld bead). The inner tubing could then be landed
against
this upset. By further ensuring that the inner tubing is slightly longer than
the
measured. length of the space it is to occupy within the outer coiled tubing,
elastic
deformation of the string can help ensure that the inner tubing is always
positively
engaged against this upset, thus reducing possibility of relative longitudinal
movement, at least at the inner tubing distal end.
Alternatively, seals maybe chosen that can themselves be mechanically
deformed to a certain extent while retaining a fixed relationship at their
ends to
tubing wall surfaces. A bellows seal is a prime example. Friction can help
limit
relative tubing surface-seal movement, while some relative tubing movement is
absorbed by deformable portions of a seal.
One method to seal an at least partial dual tubing string entails drilling a
small hole in the outer tubing and either welding, brazing, soldering or
gluing the
two tubings together. The method could include inserting a screw to
mechanically
restrict movement. Similarly, a hole could be drilled in the outer tubing to
allow
the injection of a sealing compound after a liner has been inserted. A
disadvantage of drilling holes, however, is the necessity to ensure that the
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subsequent repair of the hole eliminates all stress risers which otherwise
would
limit the plastic fatigue life of a coiled tubing string.
Conventional self-energized seals that permit movement may be utilized
between the tubings, as listed below. One should be careful to control damage
to
such a seal when installing the inner tubing and seal into the outer coiled
tubing.
Elastomer Seals Including:
O-Rings, Vee or U Packing, PolyPaks, T Seals, Cup Seals
With and without backup rings
Spring Energized seals including:
Variseal, Canted Spring Seals
With and without backup rings
Self Lubricating Seals including:
Kalsi Seals
With and without backup rings
Chemically set seals are possible, in particular as listed below. This type of
seal is energized chemically once the seal is set in position. In this way the
seal is
less likely to be damaged when an inner tubing is installed in an outer coiled
tubing. Care should be taken in achieving consistent mixing of appropriate
chemical compounds in order to make the seal reliable.
Elastomer solvent combinations;
Epoxy systems;
Soldering or Brazing the inner string to the outer string; and
Welding the inner string to outer string.
Elastomers subjected to radiation are also a possible choice. With this type
of sealing system, a seal is energized by radiating the seal once it is in
position. In
this way again the seal would be less likely to be damaged when the inner
tubing
is installed in the outer coiled tubing. Use in the field, however, could
place
practical limitations upon the use of this technique.
Heat set seals are possible, in particular as listed below. This type of seal
is energized by heating the seal once it is in position. In this way the seal
would
not be damaged when the inner tubing is installed in the outer coiled tubing.
To
be practical to use in the field, materials are preferably be selected such
that
energizing temperatures are moderate.
Elastomer subjected to heat;
Elastomer soaked in appropriate chemical and subsequently warmed/heated
after installation.
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Memory metals
Alternately cryogenic methods could be utilized to shrink tubing or tubing
portions or a seal during insertion, such than a tight fit results when the
elements
return to ambient temperatures.
Mechanically set seals are possible, in particular as listed below. This type
of seal is energized by mechanical means once it is in position. In such a way
the
seal is less likely to be damaged when the inner tubing is installed in the
outer
coiled tubing.
Deforming a metal backed elastomer seal into the outer string
Deforming a non elastomer, plastic or metal seal into the outer string
Sealing mechanisms, as illustrated in Figure 4 should take into account and
may even utilize a tendency of an inner coil IT to move longitudinally
downward
with respect to an outer coil OT as a dual tubing string S is unreeled and
straightened. Figure 4 illustrates upsets or stops ST formed on an inner
surface of
an outer tubing OT. One convenient means for forming stops ST is to place
beads
of weld on a strip of metal before it is formed into coiled tubing e.g. before
the
strip is curled and welded. Such stops ST placed on the inside surface of
outer
coil OT can thus be used to limit or inhibit substantial longitudinal movement
of
an end of inner tubing IT within an outer coil O.T. Such limitation of
longitudinal
movement could help support fixed seals SL, illustrated as O-rings in Figure
4.
between inner tubing IT and outer coil OT. Compression of inner coil IT within
outer coil OT, together with a tendency of coil IT to move downward upon
deployment, can both assist in biasing inner coil IT against stops ST.
Fixed seal ports P could be drilled through the outer coil to help effect or
establish a seal in practice after assembly, such as with screws, as
illustrated in
Figure 3B.
Figure 3A illustrates a seal system between inner tubing IT and outer coiled
tubing OT that is mechanically set and fixes the tubings against relative
longitudinal movement. The seal system does not permit longitudinal movement
between inner tubing IT and outer tubing OT after being set. The seal system
includes deformable tube 44 connected or welded to the bottom of inner tubing
IT
at well 42. Deformable tube 44 might have a length of 6 to 10 feet. Inserted
periodically around deformable tube 44 are elastomeric seals 46. After inner
CA 02615911 2007-12-10
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tubing IT is located within outer tubing OT, plug 48 is pressured down the
string.
Upon reaching deformable sleeve 44 plug 48 deforms tube 44 plastically outward
to compress against and fit against the inner wall of outer tubing OT,
pressing
thereby the series of elastamer seals 46 tightly against the inner wall of
outer
tubing OT.
Figure 3B illustrates a flexible liner, sealed with adhesive or melted or
sealed by other means against the wall of an outer coiled tubing. The seal
exists at
least at a lower end of the liner and might exist throughout the length of
the.liner.
The sealing system illustrated in Figure 3B involves inserting or installing a
liner
as inner tubing. IT. The liner is installed with blowout plug 54 at a lower
end. The
blowout plug is attached to the lower end of inner tubing IT by an attachment
means 52 of known shear strength. Such means are known in the art. The inside
of.the string could be pressured up to expand the liner. Flexible adhesive
layer 50
should be activated as by heat, time, temperature or other known means. Once
adhesive layer 50 has cured between liner IT and outer tubing OT pressure
inside
the string could be increased to blow blowout plug 54 out.
In the embodiment of Figure 3C, the sealing system includes a hard
connection as by welding, bracing, soldering, screws, glue or adhesive.
Porthole
68 formed in outer tubing OT forms an access point for applying the hard
connection material. Seal 66 offers an initial braze containment seal. Swage
piston 62 can deform lower tubular section 69 having gripping surface 67 out
in a
pressure fit against the inside surface of outer tubing OT. Lower tubular
section
69 is shown as welded at weld 64 to the lower portion of inner tubing IT.
Braze,
weld, glue, adhesive, or other similar material is.inserted in the annulus
between
the annulus between inner tubing IT and outer tubing OT through port 6&
Figure 3D illustrates a slip mechanism and seal. Swaging sleeve 74 is
swaged by swage piston 76 to force slip mandrel 72 having gripping teeth 75 up
against the inner wall of outer tubing OT. Inner tubing IT is connected such
as by
well 73 with slip mandrel 72. Seals such as 0-ring 71 seal against fluid
communication. Shear pins 78 hold swaging sleeve 74 in place until sheared by
the pressure of swage piston 76.
An alternate technique for sealing between inner tubing IT and outer coil
OT is illustrated in Figures 5 and 6. Figure 5 illustrates moveable seal means
SL
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as a series of sealing rings, probably O-rings. The rings might be structured
to
offer .a better seal when placed in compression in one direction and to slide
relatively freely when moved in the opposite direction. One method of assembly
of inner tubing IT within outer coiled tubing OT, when a directional seal is
envisioned, is to load the inner tubing within the outer coil by inserting the
upper
end of the inner tubing into the lower end of the outer tubing.
Figure 6 illustrates a form of flexible or deformable seal. Element 80
functions as a bellows seal. Element 80 is attached to element 82 which is
welded
at well 81 to inner tubing IT inside outer tubing OT. Bellows seal 83 seals at
seal
84 fixedly against the inside wall of outer tubing OT. Relative longitudinal
movement of inner tubing IT inside of outer tubing OT will deform bellow seal
83
while leaving the end of bellow seal 83 fixedly sealed at 84 against the
inside wall
of outer tubing OT. A protective sleeve such as sleeve 80 may be used for seal
installation and may be pumped out once the seal is in place.
Having devised a scheme to provide for a double barrier of safety in
operations when circulating well fluids through coiled tubing, a further issue
arises as to providing a double barrier of safety as the string is reeled into
and out
of the hole. In running out, at some point the inner coil, if it is shorter,
will be
raised above the wellhead.
For some PCCT operations it may be necessary to provide reverse flow
protection while running in hole and while pulling out of hole when the
barrier
provided by the dual string is not in effect because all the dual string is
spooled on
the reel. In this instance a device to prevent reverse flow is required.
Basically
what is needed is a cyclic check valve that can be switched on, off and then
on
again. It should be low cost, simple and reliable, especially after having
sand and
debris circulated through it. The preferred embodiment is a blowout disc and a
ball operated flapper check valve held open by a ported tube. By pressuring up
on
the CT the blowout disc can be ruptured allowing full reverse circulation. At
the
end of operations a ball can be circulated to shift the ported tube downwards
allowing the check valve to return to full operating mode. Other embodiments
include circulating a check valve down the CT after reverse operations are
concluded and arranging for the valve to latch in a profile at the top of the
reverse
washing nozzle. A more complex valve arrangement would comprise a multi-
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position valve that could be de-activated by a ball and re-activated at the
end of
operations by circulating a second ball.
Figures 7A-7C illustrates a typical embodiment of the special check valve
that might be used for regular PCCT operations in technically demanding
jurisdictions, such as the North Sea. As illustrated in Figure 7,, to provide
a
second barrier of safety sub SV can be attached at or near the bottom of
coiled
tubing string S. Safety valve sub SV might have flapper F biased to close when
fluid flows up, or when not pressured back, as is known in the industry. Such
flapper F would be biased to close against seal 38 when flow down string S is
no
longer sufficient to overcome a selected biasing force. A further refinement
includes a sleeve 34 that can be held in place by a sheer pins 38 and that
would
bias the flapper continuously open while in place. An initial burst disk 35
may be
used to seal the string as illustrated in Fig. 7A. Initial burst disk 35 may
be burst
by the application of pressure down the string as shown in Fig. 7B. When
initial
burst disk 35 is burst, as illustrated in Fig. 7C, ball 32 may be then be sent
through the coiled tubing string to land on top of sleeve 34 to shear pins 38.
The
application of pressure down the string subsequently moves sleeve 34 below
flapper F in order to allow flapper F to perform as a safety valve. When
sleeve 34
covers flapper F, flapper F would not close, whether or not fluid pressure is
sufficiently strong downhole to overcome the flapper biasing means.
In operation, an at least partial dual tubing string would be deployed down
a wellbore and most likely down production tubing. The top portion of the
tubing
string, preferably the top one-quarter to one-third of its length, would
contain an
inner tubing. Preferably the annulus, if any, between the inner tubing and the
outer tubing is narrow. Any annulus would be sealed, preferably at least at or
proximate an end portion of the inner tubing. If the annulus were sealed anew
with each job, the location of the seal may be advantageously positioned per
job
rather than fixed in the string. The seal might be a continuous substance
extending through the annulus. The seal might fill any space between the
tubings,
or the tubings might fit tightly against each other, in whole or in part. An
annulus,
if such exists, between an inner tubing and the outer tubing may be pressured
up,
such as with a high pressure gas, and the pressure monitored at the surface by
suitable equipment. With the tubing string in place and the inner tubing
extended
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below the wellhead, well fluid can be safely circulated, either up or down
through
the coiled tubing. The double barrier between the wellhead. and a valve on the
coiled tubing reel (or the like) provides a safety barrier at the surface
against leaks
in the coiled tubing string. Leaks in the coiled tubing string below the
wellhead
go into the annulus and could be controlled by the. wellhead.
The foregoing disclosure and description of the invention are illustrative
and explanatory thereof, and various changes. in the size, shape, and
materials, as
well as in the details of the illustrated system may be made without departing
from
the spirit of the invention. The invention is claimed using terminology that
depends upon a historic presumption that recitation of a single element covers
one
or more, and recitation of two elements covers two or more, and the like.
