Note: Descriptions are shown in the official language in which they were submitted.
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-1-
APPARATUS AND METHOD FOR DEWATERING LOW
PRESSURE GRADIENT GAS WELLS
CROSS REFERENCE TO RELATED APPLICATIONS
This application claims the benefit of priority to U.S. Provisional
Application No.
s 60/559,647, filed April 5, 2004, and U.S. Provisional Application No.
601589,302, filed July 20,
2004, which are both herein incorporated by reference in their entirety.
BACKGROUND OF THE INVENTION
In a typical oil or natural gas recovery process, after a well has been
drilled, a tubular
io casing is lowered into and cemented within the wellbore. Cementing of the
casing string usually
includes lowering the casing to a desired depth and displacing a desired
volume of cement down
the inner diameter of the casing. Cement is displaced downward into the casing
until it exits the
bottom of the casing and moves up into the annular space between the outer
diameter of the
casing and the wellbore. The cement cures to firmly anchor the casing to the
walls of the
is wellbore and seal off the well.
To access the oil or natural gas through the now sealed well casing, both the
casing and
concrete are perforated at a predetermined downhole location. The oil or
natural gas moves from
the formation into the well casing via the perforations due to the difference
in pressure between
the formation and the well casing interior. This pressure differential carries
the oil or natural gas
ao to the surface where it is collected.
With regard to the production of natural gas, many such wells produce small
amounts of
liquid along with the gas. Initially, when the pressure differential is
significant, the liquid is
carried to the surface with the natural gas. In addition, the well production
tubulars are sized to
maintain a practical flow velocity to keep the well unloaded during much of
its producing life.
as However, as the formation pressure decreases, it becomes increasingly
difficult for the gas
velocity to carry the associated liquid to the surface. Accordingly, the well
begins to load up
with liquid, which has a negative impact on natural gas production.
Several methods have been developed to alleviate the problems associated with
this
liquid loading. One method involves intermittent production and unloading
cycles (e.g., plunger
30 lift), while another employs reduced sized tubulars (e.g., velocity
strings) to increase gas velocity
to a level sufficient to carry the liquid out of the well. Yet another method
uses a capillary string
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-2-
to inject foamer into the well, which can improve the transport of liquid.
While all are somewhat
beneficial, each of these methods generally results in a lower gas production
rate than if the well
was allowed to produce gas without having to also carry the liquid.
Many gas wells are originally fitted, or re-completed, with relatively small
production
s tubing in an attempt to maintain velocities sufficient to unload produced
liquids. Accordingly,
the introduction of any device into the production tubing capable of removing
the unwanted
liquid further limits the area in which natural gas can flow to the surface.
The present invention
minimizes this problem, removing the extraneous liquid from a natural gas well
using a
miniaturized jet pump assembly attached to an undersized concentric coiled
tubing string.
io The use of jet pumps for removing large amounts of liquid from wellbores is
well known
in the prior art. Briefly, jet pumps generally include a power fluid line
operably coupled to the
entrance of the jet pump, and a return line coupled to receive fluids from a
discharge end of the
pump. As the pressurized power fluid is forced, by a pump at the surface, down
through the jet
pump, the power fluid draws in and intermixes with the produced fluid. The
power fluid and
is produced fluid are then returned to the surface through the return line.
Down-hole jet pumps are
advantageous because they have no moving parts, which increase their
reliability over the more
conventional mechanical pumps.
Many jet pump installations incorporate removable sub-assemblies that enable
the sub-
assembly to be removed remotely from the jet pump body while leaving the jet
pump body intact
ao in the well. Such jet pump sub-assemblies, also called "carriers," can be
installed for operation
by pumping the "carrier" down the tubing, and may also be removed by reversing
the flow of the
power fluid. Hence, the "removable" jet pump may be adjusted and/or replaced
without
requiring that the tubing be pulled from the well.
Concentric coiled tubing or coiled-in-coiled tubing is also known in the prior
art.
as Concentric coiled tubing strings provide two channels for fluid
communication downhole,
typically with one channel, such as the inner channel, used to pump fluid
(liquid, gas, or
multiphase fluid) downhole with a second channel, such as the annular channel
formed between
the concentric strings, used to return fluid to the surface. Which channel is
used for which
function is a matter of design choice. Both concentric coiled tubing channels
could be used to
3o pump up or down.
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-3-
While both of these concepts are known in the prior art, the two have not been
combined,
reduced significantly in size, and employed to remove small amounts of
extraneous liquid from a
deep, undersized natural gas well. The rising price of natural gas has made
such a system viable.
Accordingly, the following invention demonstrates such.
s
SUMMARY OF THE INVENTION
This invention relates to a method of removing extraneous fluid from a
subterranean
petroleum reservoir. More particularly, this invention relates to a method of
removing water
from a natural gas well using a miniaturized jet pump assembly attached to an
undersized
io concentric coiled tubing string.
In one embodiment of the present invention, a miniaturized jet pump assembly
is attached
to a concentric coiled tubing string at the surface and is run in the well as
one unit. The jet pump
assembly is typically placed below the formation perforations, in an area
adjacent the extraneous
water. Once correctly positioned, a power fluid is pumped down the concentric
coiled tubing
is and used to activate the functional portion of the jet pump assembly. When
activated, the jet
pump assembly creates an area of low pressure that draws the extraneous water
into the
assembly. This extraneous water is intermixed with the power fluid and
returned to the surface
via the concentric coiled tubing, where it can be collected or reused.
More often than not, the functional portion of the jet pump assembly wears out
with
Zo extensive use. Rather than remove the entire concentric coiled string and
assembly from the well
to replace the worn-out components, the functional portion can be removed from
the jet pump
assembly by "reversing" the power fluid flow within the concentric coiled
tubing. Once the
worn portion of the jet pump assembly has been replaced, the new components
are pumped
downhole to their appropriate location.
as The dimensions of the jet pump apparatus and concentric coiled tubing
string are an
important part of the present invention. Many wells have relatively small
production tubing at
that portion of the wellbore that is producing the natural gas. Accordingly,
the introduction of
concentric coiled tubing into the production tubing further limits the area in
which natural gas
can flow to the surface. Therefore, it is desirable to utilize the smallest
tubing possible. Small
so tubing necessarily requires a small jet pump to allow passage of the
"carrier" sub-assembly
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-4-
through the inner coiled tubing string. As opposed to similar systems in the
prior art, the present
invention requires the concentric coiled tubing string to be small enough to
fit inside undersized
production tubing (typically with an outer diameter as small as 2-3/8" and 2-
7/8"), and the
attached jet pump apparatus to be effectively miniaturized.
s Another embodiment of the present invention is directed to an assembly and
method for
removing produced water essentially identical to the embodiment described
above, except that a
jointed tubing string is used for the outer tubing string instead of the
previously referenced coiled
tubing string. In this embodiment, the outer jointed tubing string may be
comprised of a
corrosion-resistant material. The corrosion-resistant material may extend the
entire length of the
io outer jointed tubing string, or it may be included only in those portions
of the jointed tubing
string that will be adjacent to the perforations in the wellbore.
Still another embodiment of the present invention is directed to a method of
installing the
jet pump assembly and concentric coiled tubing string in a wellbore. This
method includes
running an outer coiled tubing string into a wellbore, cutting the outer
tubing string and hanging
is it off in a "Christmas tree," running an inner coiled tubing string (with
the jet pump assembly
attached) through the outer tubing string, cutting the inner tubing string,
landing the jet pump
assembly in a specially designed seating assembly (attached to the bottom of
the previously run
outer coiled tubing string), and finally hanging off the inner string in the
Christmas tree on the
surface. This method is particularly well suited for offshore use where
lifting a spool of
zo concentric coiled tubing is not feasible.
To ensure oil and/or natural gas cannot flow freely to the surface when a
wellbore is open
to the atmosphere, certain jurisdictions require one or more mechanical flow
barriers to be
maintained in the wellbore. The act of placing an inner coiled tubing string
inside of an outer
coiled tubing string and hanging it off (as referenced above) results in just
such a situation where
zs the wellbore is open to the atmosphere. Thus, when running a concentric
coiled tubing string
into a well it is usually necessary to include at least one mechanical barrier
below the
aforementioned jet pump assembly.
The permutation of a check valve, a blow out plug, an extended seal bore, a
nipple
profile, and a seating assembly attached to the outer coiled tubing string,
together with the use of
3o a dummy carrier set in the jet pump assembly and attached to the inner
concentric coiled tubing
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-5-
string, provides a means of installing a concentric coiled tubing jet pump
dewatering system in a
natural gas well while maintaining one or more mechanical barriers during the
process.
Another embodiment of the present invention is directed to a method of
removing the jet
pump assembly and concentric coiled tubing string from the wellbore. This
method includes
s replacing a working carrier in the jet pump assembly with a dummy carrier,
removing the inner
coiled tubing string from within the outer coiled tubing string, placing a
wireline plug in the
lower end of the outer coiled tubing, pressure testing the wireline plug, and
thereafter removing
the outer coiled tubing string from the well. As with installing the
concentric coiled tubing string
and jet pump assembly in the wellbore, it is necessary maintain one or more
mechanical barriers
io during the process of removing the concentric coiled tubing string and jet
pump assembly. The
method outlined above (and described in more detail below) accomplishes this
objective.
Additional objects and advantages of the invention will become apparent as the
following
detailed description of the preferred embodiment is read in conjunction with
the drawings. It
should be noted that terminology such as "up," "down," "above," "below," and
the like are used
is herein for convenience. These terms may not be technically accurate, as
when an embodiment of
the present invention is used in a horizontal wellbore. The terms "up" and
"above" and the like
generally refer to a direction toward the surface of a wellbore, while the
terms "down" and
"below" and the like generally refer to a direction away from the surface of a
wellbore.
zo BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 shows a longitudinal cross section of a jet pump assembly of the
present
invention.
FIG. 2 shows an alternative view of a longitudinal cross section of a jet pump
assembly
of the present invention.
Zs FIG. 3 illustrates surface equipment used in a method according to one
embodiment of
the invention wherein the concentric coiled tubing string is assembled in the
well bore. The
outer coiled tubing string is illustrated being run into the existing
production tubing in the well.
FIG. 4 illustrates the bottom hole assembly attached to the bottom of the
outer coiled
tubing string according to the method of one embodiment of the present
invention.
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-6-
FIG. 5 illustrates the outer coiled tubing string having been cut according to
the method
of one embodiment of the present invention.
FIG. 6 illustrates the installation of the slip bowl on the outer coiled
tubing string
according to the method of one embodiment of the present invention.
s FIG. 7 illustrates the landing of the slip bowl on the outer coiled tubing
string according
to the method of one embodiment of the present invention.
FIG. 8 illustrates the outer coiled tubing string landed in the Christmas tree
spool
according to the' method of one embodiment of the present invention.
FIG. 9 illustrates the jet pump assembly attached to the inner coiled tubing
string
io according to the method of one embodiment of the present invention.
FIG. 10 illustrates the installation of the slip bowl on the inner coiled
tubing string
according to the method of one embodiment of the present invention.
FIG. 11 illustrates the location of the jet pump assembly during the step of
removing the
blow out plug from the bottom sub of the seating assembly according to the
method of one
is embodiment ofthe present invention.
FIG. 12 illustrates the lowering of the inner coiled tubing string according
to the method
of one embodiment of the present invention.
FIG. 13 illustrates the passing of the stinger on the jet pump assembly
through the flapper
valve and landing of the jet pump assembly in the seating assembly according
to the method of
ao one embodiment of the present invention.
FIG. 14 illustrates a plug set in the nipple profile of the jet pump assembly
according to
the method of one embodiment of the present invention.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
as FIGS. 1 and 2 illustrate a jet pump apparatus (1) in accordance with the
present
invention. In the embodiment disclosed in FIGS. 1 and 2, the jet pump
apparatus (1) is
comprised of an outer tubular member, referred to herein as the "shroud" (2).
The shroud (2) is
attached to an outer coiled tubing string (not shown) by any suitable means,
but preferably by
welding. Welding the shroud (2) to the outer coiled tubing string allows for a
smooth connection
3o profile between the coiled tubing and the shroud (2), thereby simplifying
the surface installation
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
_7_
and preventing any hang-ups when running the jet pump apparatus (1) into the
wellbore. In an
alternative embodiment, the outer tubing string (not shown) is a jointed
tubing string. With a
jointed tubing string, the shroud (2) may be threaded onto the lower end of
the jointed tubing
string.
s Contained within the shroud (2) is an inner tubular member referred to as
the pump
housing (3). The pump housing (3) is attached to the inner coiled tubing
string (not shown) by
any suitable means, but preferably by means of a threaded connection. A first
annulus (4) is
formed between the inner surface of the shroud (2) and the outer surface of
the pump housing
(3). The first annulus (4) is in fluid communication with both the wellbore
and any surface
io equipment.
Contained within the pump housing (3) is the functional portion of the jet
pump apparatus
(1) referred to, in total, as the carrier (5). A second annulus (6) is formed
between the inner
surface of the pump housing (3) and the outer surface of the carrier (5). As
with the first annulus
(4), the second annulus (6) is in fluid communication with both the wellbore
and any surface
is equipment.
Moving from the top of the carrier (5) downward, the carrier (5) essentially
comprises a
jet nozzle (7), a throat (~), and the uppermost portion of a diffuser (9a).
Near the jet nozzle
. portion (7) of the carrier (5) is located a series of first sealing members
(10), which in this
embodiment take the form of three O-rings. These first sealing members (10)
create a seal
ao between the outer surface of the carrier (5) and the inner surface of the
pump housing (3).
Located near the uppermost portion of the diffuser (9a) is a second series of
sealing members
(17), which in this embodiment take the form of two O-rings. These second
sealing members
(17) create a seal between the outer surface of the carrier (5) and the
lowermost portion of the
diffuser (9b).
is Below the carrier (5) is located a one-way check valve (11). The check
valve (11) can be
any suitable one-way-type valve, but is preferably a ball valve. The check
valve (11) only allows
fluid to enter the jet pump apparatus (1), rather than exit. Therefore, any
fluid located within the
concentric coiled tubing string is prohibited from draining out of the bottom
of the tool and into
the wellbore. As with the carrier (5), the check valve (11) is located inside
the pump housing
30 (3).
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
_g_
Below the check valve (11) is located a third series of sealing members (12),
which in
this embodiment again take the form of three O-rings. These sealing members
(12) create a seal
between the outer surface of the pump housing (3) and the inner surface of the
shroud (2).
At the very bottom of the jet pump apparatus (1) is located a boot sub (13).
The boot sub
s (13) is essentially attached to both the shroud (2) and the pump housing (3)
- the attachment
preferably consisting of one threaded connection and two shoulders. The dual
shoulders help to
maintain the positional integrity of the shroud (2) and the pump housing (3)
as the inner
concentric coiled tubing string attempts to expand and shift due to pressure
and temperature
changes. The boot sub contains a bore (14) in the lower portion thereof, which
provides fluid
io communication between the wellbore and the inner components of the jet pump
apparatus (1).
In operation, the embodiment of the jet pump apparatus (1) disclosed in FIGS.
1 and 2 is
attached to concentric coiled tubing (not shown) at the surface as described
above. Because the
jet pump apparatus (1) is made up entirely at the surface, it can be tested
and checked prior to
placing the apparatus downhole. Once tested, the jet pump apparatus (1) and
concentric coiled
is tubing string are run into the wellbore together. Typically, the complete
apparatus is run in such
that the jet pump apparatus (1) is placed below the perforations, at or near
the location of
extraneous water.
It is a well-known practice in the art to avoid running standard steel coiled
tubing across
natural gas perforations. Natural gas production can corrode that portion of a
standard steel
ao coiled tubing that is adjacent to the perforations. This "jet impingement"
corrosion can vary
based on the concentration and type of dissolved solids, formation brine, and
acid gases.
Accordingly, one embodiment of the present invention includes utilizing a
corrosion-resistant
material for the outer coiled tubing string (not shown). Typically, a
corrosion resistant alloy
(CRA) is used. In laboratory tests, Nitronic 30 stainless steel has proved to
be corrosion resistant
Zs under simulated downhole conditions, although any suitable CRA can be used.
The CRA
material can extend the entire length of the outer coiled tubing string, or it
may be included only
in those portions of the coiled tubing that will be adjacent to the
perforations (as a cost savings
measure). If the CRA material is only included in a section of the outer
coiled tubing string, it
may be connected to the standard section by any suitable means, including
welding or threaded
3o connections.
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-9-
In an alternative embodiment, a jointed tubing string (not shown) is used for
the outer
tubing string instead of the previously mentioned coiled tubing string. The
outer jointed tubing
string is made of the corrosion-resistant material referenced above. As with
the coiled tubing
string, the CRA material can extend the entire length of the outer jointed
tubing string, or it may
s be included only in those portions of the jointed tubing string that will be
adjacent to the
perforations in the wellbore (as a cost savings measure). Nitronic 30
stainless steel has proved to
be corrosion resistant when used with a jointed tubing string, although any
other suitable CRA
can be used. If the CRA material is only included in a section of the outer
jointed tubing string,
it may be connected to the standard section by any suitable means, including
welding or threaded
io connections.
Once the jet pump apparatus (1) is lowered to the desired depth, a power fluid
is pumped
from the surface, down the inner coiled tubing (not shown) toward the jet pump
apparatus (1).
The power fluid can be any suitable substance, although produced water is
preferred for cost
savings. The power fluid is pumped into the pump housing (3) and eventually
reaches the carrier
is (5). Once the power fluid reaches the carrier (5), it is initially forced
through the jet nozzle (7).
The power fluid exists the jet nozzle (7) at a high rate of speed and travels
downward into the
throat (8). From there, the power fluid moves into the uppermost portion of
the diffuser (9a) and
subsequently into the lowermost portion of the diffuser (9b). The power fluid
is then forced out
of the lowermost portion of the diffuser (9b) via the diffuser opening (15).
At this point, the
ao power fluid is forced into the first annulus (4) between the inner surface
of the shroud (2) and the
outer surface of the pump housing (3). The power fluid is then returned to the
surface via the
first annulus (4) to be re-circulated or collected.
The act of pumping the power fluid from the surface down to the jet pump
apparatus (1)
and through the jet nozzle~(7), throat (8), and diffuser portions (9a and b),
creates an area of low
is pressure within the pump housing (3). As noted previously, fluid
communication is provided
between the pump housing (3) and the wellbore via the bore (14) of the boot
sub (13).
Accordingly, any extraneous fluid (e.g., water) that is present in the
wellbore near the boot sub
(13) will be sucked into the jet pump apparatus (1) due to the area of low
pressure created by the
power fluid stream.
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-10-
The extraneous water is sucked into the bore (14) of the boot sub (13) and
past the one-
way check valve (11) located at the top of the bore (14). The extraneous water
then moves up
the second annulus (6) until it reaches a port (16) near the jet nozzle (7) of
the carrier (5). As
noted earlier, the flow of the power fluid through the jet nozzle (7) creates
an area of low
s pressure in the immediate vicinity. Accordingly, the extraneous water is
sucked through the port
(16) where it intermixes with the power fluid. Thereafter, the extraneous
water and power fluid
move through the carrier (5) and back to the surface as described previously.
The jet pump apparatus (1) of the present invention requires a relatively low
amount of
operational horsepower in comparison with prior art jet pump systems. As an
example, ignoring
io friction, the removal of 20 barrels of produced water a day from an 8,000
ft. well only requires
an output of approximately 1.2 horsepower from an operating jet pump assembly
(1). Because
the present invention is designed to remove only a relatively small amount of
produced water
from the wellbore, the surface equipment (not shown) operating the jet pump
apparatus can be
relatively small (e.g. 10 horsepower) and can function economically even
though the jet pump
is may be operating inefficiently (e.g., at approximately 20% efficiency or
less). Accordingly, the
jet pump assembly (1) of the present invention is financially viable.
In a typical oilfield application, certain portions of the jet pump apparatus
(1) wear out or
corrode with extensive use. This wear usually occurs with regard to the
carrier (5) and its sub-
components. Instead of removing the entire concentric coiled tubing string and
jet pump
zo apparatus (1) from the well bore, which is time consuming and costly, the
present invention
allows for the removal of the worn parts without removing the entire apparatus
from the
wellbore.
To remove the carrier (5) from the jet pump apparatus (1), power fluid is
"reverse
circulated" down the first annulus (4) formed between the inner surface of the
shroud (2) and the
is outer surface of the pump housing (3). The power fluid is prevented from
exiting the jet pump
apparatus (1) by the one-way check valve (11), which only allows fluid to flow
into the tool,
rather than out. Pressure builds up against the carrier (5) to the point where
the entire assembly,
including the first and second sealing members (10 and 17) are removed from
the jet pump
apparatus (1) and forced towards the surface. A tool trap (not shown) or
similar device is then
3o employed to retrieve the carrier (5). Once the worn carrier (5) is removed,
a new carrier (5) is
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-11-
pumped back downhole through the inner coiled tubing (not shown) until it
reaches the
appropriate location in the jet pump apparatus (1).
If, for any reason, it is impossible to generate enough pressure to force the
worn carrier
(5) to the surface, a back up system is included on the jet pump apparatus
(1). A fishing neck
s (18) is included on the top of the carrier (5). If the carrier (5) cannot be
removed by reverse
circulation, a wire-line fishing tool can be lowered into the inner coiled
tubing, stabbed into the
fishing neck (18), and utilized to remove the carrier mechanically.
In an alternative embodiment of the jet pump apparatus (1) disclosed in FIGS.
l and 2,
the one-way check valve (11) can be omitted from the design of the jet pump
apparatus (1).
io Without the one-way check valve (11) in place, the power fluid will drain
out of the bottom of
the jet pump apparatus (1) and into the wellbore when the surface pump is
switched off. This
design would allow for a corrosion inhibitor to be added to the power fluid
and subsequently
introduced into the wellbore. Of course, without the one-way check valve (11)
in place, the
carrier (5) cannot be "reverse circulated" as described above. A wire-line
unit (not shown)
is would be required to accomplish such a task.
The dimensions of the jet pump apparatus and concentric coiled tubing string
are an
important part of the present invention. Many wells have relatively small
production tubing at
that portion of the wellbore that is producing the natural gas. Accordingly,
the introduction of
concentric coiled tubing into the production tubing further limits the area in
which natural gas
ao can flow to the surface. Therefore, it is desirable to utilize the smallest
tubing/tools possible that
will remove the extraneous water and still provide sufficient flow area for
natural gas production.
Assuming that production tubing has an outer diameter of 2-7/8 inches, the
corresponding
inner diameter would only be approximately 2-2/5 inches. The concentric coiled
tubing and
attached jet pump assembly of the present invention must be small enough to be
run inside the
as production tubing and still leave adequate annular space to produce the
natural gas.
Additionally, there must be adequate annular space within the concentric
coiled tubing to remove
any extraneous water as described in the method above.
Therefore, as opposed to similar systems in the prior art, the present
invention requires
the concentric coiled tubing string to be extremely small, and the attached
jet pump apparatus (1)
3o to be effectively miniaturized. By way of example, the concentric coiled
tubing may be
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-12-
assembled using 2", 1 '/4", or even 1 '/2" coiled tubing for the outer string
and 1" or 7/8" coiled
tubing for the inner string. The jet pump apparatus (1) may be approximately 1
'/4" in diameter
with a "carrier" in the approximate range of 5/8" to 3/4" depending on the
inner string size.
Intermediate sizes of coiled tubing can be manufactured to further optimize
performance if
s demand warrants it.
As opposed to assembling the concentric coiled tubing string at the surface
(as described
above), there may be circumstances that require the assembly of the concentric
coiled tubing
string in the wellbore. An example of this would be an offshore installation
where the existing
platform crane has insufficient capacity to lift the weight of a pre-assembled
concentric coiled
io tubing reel. Therefore, another embodiment of the present invention (as
described in more detail
below) includes a method of running an outer coiled tubing string into a
wellbore, cutting the
outer tubing string and hanging it off in the "Christmas tree," running an
inner coiled tubing
string (with the jet pump assembly attached) through the outer tubing string,
cutting the inner
tubing string, landing the jet pump assembly in a specially designed seating
assembly (attached
is to the bottom of the previously run outer coiled tubing string), and
finally hanging off the inner
string in the Christmas tree on the surface.
FIG. 3 illustrates some of the surface equipment used to assemble the
concentric coiled
tubing string and lower it into the wellbore. Prior to lowering the outer
coiled tubing (25) into
the wellbore, a new spool piece (30) is installed between a master valve (35)
and the remainder
zo of the Christmas tree (34). A coiled tubing blow out preventer ("BOP")
stack (40) is installed on
top of the master valve (35). The BOP stack (40) includes a plurality of
hydraulically actuated
rams such as shear rams, slip rams, and/or tubing or pipe rams. A
hydraulically actuated work
window (45) is attached between the BOP stack (40) and a lubricator (50). A
stuffing box (55) is
located above the lubricator and beneath an injector head (60). The devices
above (e.g., injector
zs head, stuffing box, lubricator, work window, and BOP stack) and their
respective uses are well
known in coiled tubing applications.
At the surface, a bottom hole assembly ("BHA") (75) is assembled and attached
to the
bottom of the outer coiled tubing (25), preferably by a threaded connection.
The BHA, as shown
in FIG. 4, comprises a seating assembly (80), a valve body (85), and a bottom
sub (90). The
3o seating assembly (80) further comprises a landing shoulder (81), an
extended seal bore (82), and
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-13-
a nipple profile (83). The valve body (85) is connected to the lower end of
the seating assembly
(80) by any suitable means such as a threaded connection. In a preferred
embodiment, the valve
body (85) houses a spring-biased flapper (87), which, in the closed position,
will prevent the
flow of well bore fluids up through the valve and into the outer coiled
tubing. For those
s jurisdictions that require double mechanical barriers to be in place when
the well is open to the
atmosphere, dual flapper valves (not shown) can be utilized:
The bottom sub (90) is preferably threaded to the lowermost end of the valve
body (85)
and includes a profile (92) for receiving a removable blow out plug (95),
which can be pre-
installed in the bottom sub. While a variety of well-known blow out plugs may
be used with this
io invention, the blow out plug disclosed in FIG. 4 includes a plurality of
"dogs" that extend
radially into the aforementioned profile (92): Once installed in the bottom
sub (90), the blow out
plug may be pressure tested while still on the surface.
After the BHA is connected to the outer coiled tubing string (25), the string
is fed through
the surface equipment by the injector head (60) and into existing natural gas
production tubing
is (70), as illustrated in FIG 3. The outer coiled tubing string (25) is
lowered through the
production tubing (70) until it reaches the desired depth in the wellbore. The
flapper valve (87)
and blow out plug (95) serve as dual mechanical barriers to fluid flow when
the outer coiled
tubing (25) is being run into the well.
Once the outer coiled tubing string (25) has been lowered to the desired
depth, it is
ao landed in the spool (30). This can be accomplished by closing slip rams
(41) in the BOP stack to
grip the outer coiled tubing (25) and closing tubing rams (42) to seal the
annulus around the
tubing (25), as illustrated in FIG. 5. The work window (45) is then opened and
the outer coiled
tubing (25) is cut by any suitable means such as a mechanical pipe cutter.
With the window (45) still open, a hang-off bushing or "slip bowl" (100) may
be attached
as to the top of the severed tubing (25) by any suitable means. Preferably,
the slip bowl (100) is
bolted to the outer coiled tubing string (25) and includes one or more seals
(105). The slip bowl
(100) includes a profile (106) for receiving and connecting to an "overshot"
(110). The overshot
(110) is attached to the end of the severed outer coiled tubing (25A), as
shown in FIG. 6.
The severed coiled tubing (25A) is then lowered until the overshot (110)
latches onto the
so profile of the slip bowl (100). In the latched position, the overshot (110)
can support the weight
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-14-
of the suspended outer coiled tubing string (25) and the BHA (75). After
closing the work
window (45), tubing rams (42) and slip rams (41) are opened and the outer
coiled tubing (25) is
lowered until the bowl (100) lands on the lowermost shoulder in the bore of
the spool (30), as
shown in FIG. 7. Once landed, the spool (30) supports the weight of the outer
tubing string (25).
s Seals (105) seal against the internal bore of the spool (30). A latch (not
shown) is then released
from the profile (106) of the slip bowl (100) by any suitable means such as
fluid pressure. FIG.
8 illustrates the outer tubing string (25) landed in the spool (30). The
severed coiled tubing
(25A) is then removed from the surface equipment.
Once the outer coiled tubing string (25) has been landed and the severed
tubing (25A) has
io been removed, the master valve (35) is closed and the BOP stack (40) is
changed out in
preparation for running the inner string (125) of the concentric coiled tubing
string. An inner
string BHA (130), shown in FIG. 9, preferably comprises a jet pump assembly
(135), a standing
or check valve (140), a landing shoulder (145), a seal assembly (150), and a
stinger (155). For
added safety, a dummy carrier (not shown) may be installed in the jet pump
assembly as an
is additional mechanical barrier.
The BHA (130) can be connected together by any suitable means such as by
threaded
connections between the components. Preferably, the BHA (130) is threaded to
the bottom of
the inner coiled tubing (125) after the inner coiled tubing (125) has been
aligned with and
lowered into the surface equipment. After the BHA (130) is assembled and
connected to the
Zo inner coiled tubing (T25), the inner coiled tubing is lowered into the
outer coiled tubing (25) by
the injector head (60). One of skill in the art will recognize that the
injector head (60) can be
adapted to handle the smaller diameter inner coiled tubing (125).
The inner coiled tubing (125) may be lowered into the outer coiled tubing (25)
until the
inner BHA (130) reaches the outer BHA (75). The inner coiled tubing (125) may
be cut in the
is same manner as the outer coiled string (25). Specifically, the slip rams
(41) and tubing rams (42)
are closed about the inner tubing string (125). After the pressure is bled off
from above the
tubing rams (42), the work window (45) is opened and the tubing is cut with an
appropriately
sized pipe cutter.
A slip bowl (175) is connected to the top end of the suspended inner coiled
tubing string
30 (125), as shown in FIG. 10. The slip bowl (175) includes an outer diameter
that will allow the
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-15-
bowl to land on the upper shoulder of the spool (30) and has a suitable seal
assembly, such as
plurality of o-ring seals, that will seal against the upper seal bore of the
spool (30). An overshot
(180) is attached to the lower end of the severed tubing (125A). The overshot
(180) is lowered
over and latched to the upwardly extending profile on the slip bowl (175). The
slip rams (41)
s and tubing rams (42) are then opened.
The inner string (125) may then be slowly lowered until the blow out plug (95)
is tagged
to verify the location of the BHA (130). However, before landing the inner
coiled tubing string
(125) in the spool (30), the inner string is picked up a short distance to
verify that the seal
assembly (150) is not engaged in the seal bore (82), as shown in FIG. 11. When
the lower BHA
io (130) is in the position shown in FIG. 11, the position of the slip bowl
(175) relative to the spool
(30) is illustrated in FIG. 12. Pressure may then be applied via a jet pump
circulating port (32) to
the annulus (151) between the inner coiled tubing (125) and the outer coiled
tubing (25). The
pressure opens the flapper (87) and is applied against the blow out plug (95).
The pressure is
increased until the plug (95) is expelled from the bottom sub (90).
is The release of the plug (95) from the bottom sub will be indicated by a
sudden reduction
in surface pressure. As soon as the plug (95) has been released, the inner
tubing string (125) is
lowered and landed in the spool (30). Thus, for a moment, there will be only
one mechanical
barrier (i.e., the flapper (87)) downhole.
As the inner string (125) is lowered, a stinger (155) will pass through the
flapper (87),
Zo holding the flapper in the open position, and will extend past the bottom
sub (90) as shown in
FIG 13. However, the seal assembly (150) will encounter the seal bore (82)
prior to the opening
of the flapper (87), thereby providing another downhole barrier. A shoulder
(145) on the inner
string BHA (130) will land on the landing shoulder (81) to give a positive
indication that the seal
assembly (150) and the stinger (155) are properly located within the outer BHA
(75). Shoulders
zs (145) and (81) may also be used to properly space out the inner tubing
string (125) prior to
cutting the inner coiled tubing and installing the slip bowl (175), as is well
understood in the art.
After the inner string (125) has been landed, the severed coiled tubing (125A)
is removed
from the surface equipment. The master valve (35) is closed and the BOP (40),
work window
(45), lubricator (50), stuffing box (55), and injector head (60) are nippled
down and removed. If
CA 02562085 2006-10-04
WO 2005/100744 PCT/US2005/010725
-16-
a dummy carrier has been installed in the jet pump assembly, a working carrier
may be pumped
down and installed after the dummy carrier has been reverse circulated out of
the well.
When the jet pump assembly is activated by fluid flow pumped down the inner
coiled
tubing (125), water will be sucked into the stinger (155) and on to the jet
pump assembly where
s it will be pumped out of the hole. In a preferred embodiment, a strainer
serves as the stinger
(155) and prevents large debris from plugging the jet pump assembly. The
strainer may be a
sucker rod strainer, a wire wrapped screen, a perforatedlslotted pipe, or any
other suitable means
that has been effectively miniaturized to fit through the outer coiled tubing
string (25).
In the event the concentric coiled tubing string needs to be removed from the
wellbore, it
io is still necessary to maintain the mechanical flow barriers. In one
embodiment, before pulling
the inner string (125), a working carrier may be reverse circulated out of the
jet pump assembly
and a dummy carrier (not shown) circulated down and installed. Alternatively,
a dummy carrier
may be installed via wireline in the jet pump assembly. The dummy carrier will
serve as a
mechanical barrier for the inner string (125) as it is removed from the well.
A wireline plug
is (175), shown in FIG. 14, may then be run into the outer coiled tubing (25)
and set in a nipple
profile (83). Unlike the aforementioned flapper (87), the wireline plug (175)
may be tested with
pressure to make sure it is holding. Once the wireline plug (175) is set and
tested, the outer
string (25) may then be removed from the well.
While preferred embodiments of the apparatus and methods have been discussed
for
Zo purposes of this disclosure, numerous changes in the construction,
installation, and function of
the jet pump apparatus and concentric coiled tubing string may be made by
those skilled in the
art. All such changes are encompassed within the scope and spirit of the
following claims.
