Note: Descriptions are shown in the official language in which they were submitted.
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KOBE SUB WITH INFLOW CONTROL, WELLBORE TUBING STRING AND
METHOD
Field
The invention is directed to a wellbore apparatus and method and, in
particular a kobe sub,
wellbore tubing string and method.
Background
In wellbore operations, tubing strings are used having walls with one or more
ports extending
therethrough. The ports permit fluid access between the tubing string inner
diameter and the
tubing string's outer surface, which is open to the wellbore.
A kobe, also called a break-off plug or a kobe plug, is a closure that can be
mounted at its base
over a port with a cap portion extending from the base. A channel extends
through the base into
the cap, but is closed off at the cap. The cap portion protrudes from the port
and is openable to
open the port to fluid flow through the channel. A kobe is installed in a port
through the wall of
a tubular housing, together called a kobe sub, that can be installed into a
wellbore tubing string.
The cap portion of the kobe often protrudes into the inner bore of the tubing
string.
Generally, the kobe is opened by running a tool through the inner bore of the
string to break off
the cap portion. The tool may be a drop bar, a cutter tool, etc.
Tubing strings may handle fluid flows into and out of the wellbore. For
example, an oil or gas
well relies on inflow of petroleum products to the tubing string and toward
surface. It may be
advantageous in certain circumstances to control the inflow of produced
fluids. For example, it
may be advantageous to screen the produced fluids before they enter the tubing
string. In
addition or alternately, the produced fluids may require flow rate control, as
by use of chokes
including devices called inflow control devices (ICD).
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SUMMARY
In accordance with a broad aspect of the present invention, there is provided
a kobe sub
comprising: a tubular body connectable into a wellbore tubing string, the
tubular body including
a wall including an outer surface and an inner surface defining an inner bore
and a port through
the wall; a kobe installed in the port with a cap portion accessible in the
inner bore, a base
mounted in the port and connected to the cap portion, a channel extending
through the base and
closed by the cap portion; and an inflow controller positioned to control
fluid flowing through
the channel toward the inner bore when the cap portion is opened.
In accordance with another broad aspect of the present invention, there is a
provided a method
for forming a fluid channel through a tubing string wall, the method
comprising: installing a
tubing string in a wellbore, the tubing string including a tubular wall
including an outer surface
and an inner surface defining an open inner bore and a port through the wall;
a kobe installed in
the port with a cap portion accessible in the inner bore, a base mounted in
the port and connected
to the cap portion, a channel extending through the base and closed by the cap
portion; and an
inflow controller positioned to control fluid flowing through the channel
toward the inner bore
when the cap portion is opened; manipulating a port opening tool in the inner
bore to open the
cap portion and to allow fluid flow through the inflow controller and the
channel into the inner
bore.
In accordance with another broad aspect of the present invention, there is a
provided a tubing
string system for installation in a wellbore comprising: a tubular body
including a tubular wall
with an outer surface and an inner surface defining an inner bore and a port
through the tubular
wall; a kobe installed in the port with a cap portion accessible in the inner
bore, a base mounted
in the port and connected to the cap portion, a channel extending through the
base and closed by
the cap portion; and an inflow controller positioned to control fluid flowing
through the channel
toward the inner bore when the cap portion is opened; and a port opening tool
for opening the
cap portion.
In accordance with another broad aspect, there is provided a method for fluid
treatment of a
borehole, the method comprising: running a tubing string into a wellbore to a
desired position for
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treating the wellbore; opening a frac port by application of a force to a
closure for the frac port;
injecting stimulating fluids through the frac port; closing the frac port;
opening a fluid inflow
control port by opening an inner cap over the fluid inflow control port; and
permitting fluid to
pass from the wellbore into the tool through the fluid inflow control port.
It is to be understood that other aspects of the present invention will become
readily apparent to
those skilled in the art from the following detailed description, wherein
various embodiments of
the invention are shown and described by way of illustration. As will be
realized, the invention
is capable for other and different embodiments and its several details are
capable of modification
in various other respects, all without departing from the spirit and scope of
the present invention.
Accordingly the drawings and detailed description are to be regarded as
illustrative in nature and
not as restrictive.
BRIEF DESCRIPTION OF THE DRAWINGS
A further, detailed, description of the invention, briefly described above,
will follow by reference
to the following drawings of specific embodiments of the invention. These
drawings depict only
typical embodiments of the invention and are therefore not to be considered
limiting of its scope.
In the drawings:
Figure 1 is a sectional view along the long axis of kobe sub;
Figure 2 is a sectional view along the kobe sub of Figure 1 undergoing a port
opening operation;
Figure 3 is a perspective view of a fluid control port insert useful in the
present invention;
Figure 4 is a sectional view along the kobe sub of Figure 1 undergoing another
type of port
opening operation;
Figure 5a is a sectional view along a kobe sub undergoing another type of port
opening
operation;
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Figures 5b to 5d are a series of drawings showing a kobe opening operation;
Figure 6 is a sectional view along the kobe sub of Figure 5 with its ports
open;
Figure 7 is a sectional view along the long axis of another kobe sub;
Figure 8 is a sectional view along the kobe sub of Figure 7 undergoing a port
opening operation;
Figure 9 is a sectional view along the kobe sub of Figure 7 with its ports
open;
Figure 10 is a sectional view along the long axis of a frac tool in the form
of a tubing string sub
containing a sleeve in a closed port position;
Figure 11 is a sectional view along the sub of Figure 10 with the sleeve in a
position allowing
fluid flow through injection ports;
Figure 12 is a sectional view along the sub of Figure 10 allowing fluid flow
through fluid inflow
control ports; and
Figure 13 is a sectional view along a tubing string in a wellbore.
DETAILED DESCRIPTION
The description that follows, and the embodiments described therein, is
provided by way of
illustration of an example, or examples, of particular embodiments of the
principles of various
aspects of the present invention. These examples are provided for the purposes
of explanation,
and not of limitation, of those principles and of the invention in its various
aspects. The drawings
are not necessarily to scale and in some instances proportions may have been
exaggerated in
order more clearly to depict certain features. Throughout the drawings, from
time to time, the
same number is used to reference similar, but not necessarily identical,
parts.
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A method and apparatus has been invented which provides for flow control of
produced fluids.
The apparatus and methods of the present invention can be used in various
borehole conditions
including open holes, cased holes, vertical holes, horizontal holes, straight
holes or deviated
holes.
Figure 1 illustrates a kobe sub 10 that includes kobes 12 as closures for
ports 16 through the sub
wall.
Kobe sub 10 may have a tubular form and include an upper end 10a, a lower end
10b and a wall
18 defining the subs inner bore ID and its outer surface 20. At least one
fluid outlet port 16
extends through the wall to provide fluid communication between inner bore ID
and outer
surface 20. In wellbore operations, kobe sub 10 may be installed in a wellbore
and, as such,
outer surface 20 becomes open to an annulus in communication with the wellbore
wall.
In some embodiments, there may be a plurality of fluid ports 16 through the
wall of the sub. As
shown for example, ports 16 may extend through the wall and may be spaced
circumferentially
and/or axially along the sub wall.
Ports 16 may each be closed by kobes to permit isolated control of the fluid
conditions in inner
bore ID and may be selectively openable, when desired, to permit fluid access
between the inner
bore and the outer surface.
Each kobe includes a cap portion 12a, a base 12b attached to the cap portion,
and a channel 12c
that extends through the base. The kobe can be mounted at its base 12b in a
port with its cap
portion 12a protruding beyond the surrounding wall surface defining inner
diameter ID. The
base can be sealed to the port walls, such that channel 12c creates the flow
path through the port.
Cap portion 12a, however, while it is in place on the base, seals channel 12c
against fluid flow
therethrough. Cap portion 12a, therefore, must be opened to open the port to
fluid flow. The cap
portion can be opened by removing, shearing, breaking off, compromising,
breaching, breaking
open, pushing through the wall, etc, which may be collective referred to
herein as "opened".
Sometimes, the kobe includes a weakened area 12d between cap portion 12a and
base 12b that
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facilitates opening removal by separation of the cap portion from the base,
when force is applied
to cap portion 12a.
Kobe sub 10 may be connected into a wellbore string for installation into a
well. For example,
its ends 10a, 10b may be formed for connection in line with other tubulars.
For example, its ends
may be threaded and formed as pins or boxes for typical threaded connection to
other tubulars.
Kobe sub 10 illustrated in Figure 1 has ports 16 particularly suited to
controlling fluid flows
therethrough. For example, each port 16 has a fluid inflow controller 24
installed therein. Fluid
inflow controller 24 may be selected to control any of various features of the
fluid passing
therethrough. For example, the fluid inflow controller may be a screen, as
shown, for filtering
out oversize solids from the fluid, and/or may a choke for controlling the
pressure drop and/or
flow rate of the fluid passing through port 16. One type of choke is commonly
known as an
inflow control device (ICD). ICDs use various mechanisms to control velocity,
flow rate and
pressure drop such as labyrinths, surface roughening, passage arrangements,
nozzles, gates, etc.
For each port, when cap portion 12a is in place, flow is prevented through
channel 12c and
therefore controller 24 is inactive. However, when cap portion 12a is opened,
the fluid inflow
controller acts on the fluids passing inwardly through the port through
channel 12c.
Figure 1 shows sub 10 with all ports 16 closed by their kobes. This is the run
in state of the tool.
In this condition, controllers 24, in this embodiment screen inserts, are
installed with kobes 12
sealing them from the ID of the tubing. In this state, the tubing at the
location of sub 10 has a
full pressure rating, substantially equal to a section of standard tubing
without ports. In this
condition, an operator can circulate fluid through the inner diameter ID of
sub 10, which may be
needed for example to run the tubing string in the hole. The sub is also able
to hold higher
pressures, such that the operator may pressure up the string at the sub to use
tubing pressure to
set packers or treat the formation through the string.
When a controlled, for example screened, return flow is desired, the kobes can
be opened to
permit flow through the ports. Various methods can be employed to open the
ports to flow
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therethrough. For example, the cap portions can be opened by: (i) milling
through the inner
diameter, (ii) abutment by a string conveyed tool, or (iii) abutment by an
unconnected tool, such
as a gravity or fluid conveyed tool.
For example, Figure 2 shows sub 10 after it has been connected into a tubing
string and installed
in a wellbore, as indicated by wall 26. After the tubing string is installed
and before or after
other wellbore operations of interest are conducted, the operator may wish to
open the ports by
opening cap portions 12a. In this illustrated embodiment, a shifting tool 50
on a string 52, such
as for example, slickline, coiled tubing or threaded pipe, is run to the
bottom of the well,
activated and pulled (arrow P) back toward the surface. Tool activation
releases the tool's keys
54 to expand so they abut against and shear off the kobe cap portions 12a as
the keys pass ports
16. Shearing cap portions 12a', which are accessible in the ID of the tubing
string, from their
bases 12b, opens channels 12c for fluid communication between the ID and an
annulus 56
between wall 26 and outer surface 20 of the tubing string. When opened, for
example, produced
fluids, arrows F, may flow through screen 24 and through channel 12c into the
inner diameter ID
of the tubing string and be produced to surface.
Of course this process could also be done running from the top of the well to
the bottom, but
typically it is easier to pull with force then to push with force. The sheared
off cap portions 12a'
of the kobes are shown released into the ID of the tubing string and may be
produced to the
surface when the well goes on production. However, if desired, the cap
portions can be stored in
the tubing string or captured such that they do not become freed in the inner
diameter, as
described in applicant's corresponding PCT application no. WO 2012/065259.
Also or
alternatively in some embodiments, there they may be a concern of a cap
portion being
inadvertently opened by abutment by an actuator, a treatment string or tool
head, as they are
passed thereby. In such an embodiment, measures can be taken to protect the
cap against
accidental opening. Measures may include recessing the port or the cap,
providing protectors,
etc.
The kobes can have various constructions and be installed in various ways, as
also shown in the
above-noted PCT application. For example, in one embodiment, the port 16 in
which the kobe is
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installed can be a hole formed through the wall of the tubular body and the
kobe cap, base, etc.
can be formed as an insert 2 such as that shown in Figure 3 and the insert can
be installed in port.
In the illustrated embodiment of Figure 3, insert 2 includes the kobe
structures: cap portion 2a,
base 2b, a channel through the base, which opens at openings 2c on the base
and a shear plane 2d
between the cap portion and the base. Cap portion 2a is positioned on one end
of the insert and
the channel openings 2c are on the opposite end. Insert 2 also includes the
inflow controller 4.
In this embodiment, controller 4 includes two components. First, filter media
4a is installed in
the channel. The filter media can include, for example, screen, fibers, mesh,
etc. As well, fluid
control is provided in part by the shape and size of the channel openings 2c.
For example, as
shown, the one or more openings may be formed on the end opposite the cap that
provides a path
for fluid flow into channel of the insert. The openings may themselves provide
for inflow
control, as by sizing, gates, nozzles or other rate controllers or filter
media.
Insert 2 may be installable in a port hole by various means such as, for
example, by threaded
engagement, using threads 2e as shown, or by other means such as welding such
as inertia
welding. Inertia welding welds two pieces of material by creating significant
frictional forces
between the pieces that the contacting surfaces of the parts are caused to
melt and fuse together.
For example, the insert may be rotated along its long axis xi at high speed
and may be placed into
contact with a port hole of a tubular, which is held substantially stationary,
such that the
contacting surfaces may be welded together.
It will be appreciated, therefore, that the kobe construction and its mode of
installation can be
modified in various ways.
Figure 4 shows another method to open the kobes, this embodiment using a mill
60. If a milling
operation is employed to remove ball seats in sliding sleeve valves or other
inner diameter ID
constrictions or debris, then mill 60 can at the same time be employed to open
channels 12c of
the kobes by removing cap portions 12a. Of course, mill 60 could also be run
through tubing
string 10 solely for the purpose of opening kobes 12. Once opened, produced
fluids can flow
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through the controller, illustrated here as a screen insert 24, and through
opened channel 12c into
the tubing string for flow to surface.
Figures 5a to 5d show another way of opening kobes 112 in a tubing string 110.
A plug can be
pumped down to engage against and remove the kobe caps 112a as it passes. The
plug in this
illustrated embodiment is a ball-activated cutting sleeve including a cutting
sleeve 172 that can
be activated into a form of piston when a ball 174 is landed onto an upper end
172a of the sleeve.
Downhole end 172b of the sleeve may have a tapered edge that acts as a cutter
to shear off the
caps 112a' as it contacts them. Sleeve 172 can reside in the tubing string
inner diameter ID and
wellbore operations can be conducted through the bore 176 of the sleeve.
Sleeve 172 is
unaffected by wellbore operations and pressures, until ball 174 is seated
therein.
This embodiment relies on pressure, arrows A, to move the plug along and,
therefore, to cut off
the kobe caps 112a' from their bases 112b. Thus, unless measures are taken to
address pressure
loss, there may be a limit to the number of kobes that can be opened by the
plug until too much
pressure is released through the opened kobes that the plug can't be pushed
down anymore.
Therefore, ports 116 may include an obstruction to at least temporarily hold
pressure even after
the kobes are opened. For example, limited entry nozzles or removable plugs
may be employed
to permit pressure to be maintained in the inner diameter ID of tubing string
10 even after a
number of kobe caps 112a' are removed. Plugs may include burst plugs, erodible
discs, etc.
If the ports are suitably obstructed, such as for example, by small plugging
pins 178, then the
pressure drop through the exposed channel 112c of the kobe will be minimized,
therefore the
pressure driven plug can work for long distances.
A plugging pin 178 is a form of plug operated by pressure differentials.
Figure 5b shows a kobe
112 in a run in position in a tubing string 110, wherein base 112b of the kobe
is installed in port
116 and cap portion 112a is secured on base 112b such that channel 112c is
closed. Port 116
also has a fluid flow controller, such as an amount of screening material 124,
installed therein.
Plugging pin 178 is installed in channel 112c. Plugging pin 178 creates a seal
with the inner
walls of channel 112c and for example, may be sized and/or carry an o-ring 179
to seal with the
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inner walls. Plugging pin 178 resists fluid flows outwardly from inner
diameter ID to outer
surface 120 of the tubing string 110 (where P1>P2), but can be expelled from
channel 112c in
response to pressures differentials wherein the pressure about outer surface
P2 is greater than the
pressure P1 in inner diameter. In the illustrated embodiment, when P1 is
greater than P2
plugging pin is held in channel 112c by butting against the screening material
124.
Figure 5c shows a kobe after cap portion 112a is removed from its base 112b,
but plugging pin
178 remains plugging fluid flow through channel 112c of the kobe. Plugging pin
178 therefore
substantially holds pressure across port 116. The pressure in inner diameter
P1 can exceed P2,
but plug remains in channel 112c as it is stopped against screening material
124. Figure 4c shows
a kobe in which the production pressure P2 is greater than pressure P1 and
produced fluids,
arrows F, have forced plugging pin 178 from the channel, thereby opening port
116 to
production flow.
Utilizing any of the various options for opening the kobes such as for example
any of those
shown in Figures 2, 4 and 5a, ports 116 can be opened to permit production of
fluids arrows F
through the opened ports, including through fluid flow controllers, shown in
Figure 6 as screens
124, and opened channels 112c, into the tubing string inner diameter ID.
Screens 124 present a
larger flow area that is reduced by the inner diameter IDk across the kobe
port channel 112c to
balance the flow across the wall of tubing string 110. This IDk of the kobe
can be adjusted
during assembly by selection of the kobes installed in the base tubing string
wall.
While Figures 1, 2 and 4 to 6 show flow through individual spaced apart ports
116, a kobe sub
can include various other port configurations such as those including annular
port sections,
headers, etc. For example, Figure 7 shows a kobe sub 210 a port configuration
including a
plurality of exterior port openings 216a on outer surface 224. Exterior port
openings 216a open
into an annular header area 216b and inner port openings 216c extend from
annular header area
216b to inner diameter ID of the sub. The flow area is reduced significantly
from area 216b to
openings 216c and the lateral flow required to pass through the ports creates
a pressure drop
effect. Such an arrangement of reduced and indirect flow creates a fluid flow
controller termed
inflow control device (ICD). Port openings 216a also have screen inserts 224
installed therein
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such that the fluid flow inwardly through the ports is also controlled to
remove oversize
materials therefrom.
Kobes 212 are installed in inner port openings 216c and control the open and
closed condition of
ports 216. Kobes 212 can be opened by opening their cap portions 212a.
Sub 210 can be installed in a tubing string 210a and run into a wellbore 226.
As noted above,
kobes 212 can be opened by various methods such as by use of a mill 260 passed
through the
inner diameter ID (Figure 8) to remove cap portions 212a and expose channels
212c to inner
diameter ID. As shown in Figure 9, when channels 212c of the kobes are opened,
the production
flow can be screened as it passes from the annulus around the subs outer
surface 220 through
screen inserts 224 into the annular area 216b. Once in the annular area, the
fluid then flows to
channels 212c of kobes 212 and into the inner diameter ID of the sub.
Other variations are possible. For example, while the exterior port openings
216a are shown as
spaced apart ports, annular openings may be employed for example one or more
axially
extending, annular openings, as in a wrapped or a sleeve-type screen.
The tubing string referenced above can be a production string, casing, liner,
work string, etc.
The string may include other components such as frac tools, packers,
centralizers, etc. The
packers can be of any desired type to seal between the wellbore and the tubing
string. In one
embodiment, at least one of the first, second and third packer is a solid body
packer including
multiple packing elements. In such a packer, it is desirable that the multiple
packing elements are
spaced apart. The apparatus and methods of the present invention can be used
in various
borehole conditions including open holes, cased holes, vertical holes,
horizontal holes, straight
holes or deviated holes.
When natural inflow from the well is not economical, the well may require
wellbore treatment
termed stimulation. This is accomplished by pumping stimulation fluids such as
fracturing fluids,
acid, cleaning chemicals and/or proppant laden fluids to improve wellbore
inflow.
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For example, sometimes the well is isolated in segments and one or more
segments are
individually treated so that concentrated and controlled fluid treatment can
be provided along the
wellbore by injecting the wellbore stimulation fluids from a tubing string
through a port in the
segment and into contact with the formation. After wellbore fluid treatment,
fluids are
sometimes allowed to flow back into the string. The produced fluids may
include stimulation
fluids and thereafter, fluids produced from the formation.
The method and apparatus of the invention can be adapted to provide for the
injection of a
wellbore treatment fluid and then reconfiguration to control the inflow of
produced fluids.
In one embodiment shown in Figures 10 to 12, an apparatus for fluid handling
in a borehole, may
include a tubular body 310 having a long axis x, a wall 318 including an inner
wall surface
defining an inner bore ID and an outer wall surface 320 and ends 310a, 310b.
An inflow port 316 is opened through wall 318 of the tubular body. A fluid
inflow controller
324 is provided in the inflow port to control the flow of fluid into the
tubular body through the
inflow port. A kobe 312 is installed in inflow port 316 for closing the inflow
port, the kobe
includes a cap portion 312a protruding into the inner diameter. The cap
portion when intact
closes port 316 to fluid flow, but cap 312a is openable to open fluid flow
access through the
inflow port from outer wall surface 320 to inner bore ID.
An injection port 380, also called a frac port, may also be opened through
wall 318 of the tubular
body. The open and closed condition of port 380 may be controlled by a closure
382. Closure
382 may be positioned relative to injection port 380 and may be moveable from
(i) a first
position closing the injection port (Figure 10) to (ii) a second position
permitting fluid flow
through the injection port (Figure 11). The closure may be moved from the
first position to the
second position by any of various means. For example, an actuating force may
be applied to
move closure 382 from the first position to the second position.
Inflow port 316 is separate from injection port 380. For example, inflow port
316 may be axially
spaced from injection port 380.
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The inflow port is intended for permitting fluid inflow therethrough. As noted
above in respect
of Figures 1 to 10, the inflow port 316 may take various forms and include
inflow controllers 324
to control any of various features of the inflowing fluid and kobe 312 can
also have various
forms. As noted above in Figures 1 to 9, there may be a plurality of inflow
ports spaced apart on
the tubular body such that inflow may be permitted through more than one port.
For example,
there may be a plurality of ports spaced along the tubular body, each of the
plurality of ports
having an inflow controller and a sealing, openable kobe.
Injection port 380 is intended for injection of fracturing fluid therethrough
from the inner
diameter ID to the formation surrounding outer surface 320 the tubular body
when the tubular
body is installed in a well. Therefore, injection port 380 may have an open
diameter or have
fluid control means therein such as an outwardly acting nozzle, etc., as
desired.
In the illustrated embodiment, closure 382 is a sliding sleeve valve. As such
in one embodiment,
closure 382 is actuated to slide or rotate to open injection port 380. An
actuator for closure 382
in one embodiment may include a manipulation string, such as a tubing string
or a wire line, that
is run in to engage the sleeve and apply a force to the sleeve to move it to
the second position. In
yet another embodiment, the sleeve actuator is a motor drive. Of course, other
actuators are
possible. For example, to facilitate operations the sleeve may be actuated
remotely, without the
need to trip a work string. In another embodiment, therefore, closure 382 in
the form of a sliding
sleeve valve as shown, can include a seat 384 formed on an inner diameter
thereof and the
actuation force may be applied by employing a plug 385 sized to land in and
seal against seat
384. Once plug 385 lands, the sleeve and the plug become a piston, such that a
pressure
differential can be built up across the sleeve and the plug and a fluid
pressure force may be
applied to move the sleeve causing it to move to the lower pressure side. In
yet another
embodiment, the closure may be a sleeve of the pressure chamber type, where
the closure moves
in response to a pressured up condition as permitted by an oppositely acting
lower pressure, such
as an atmospheric chamber.
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The operation of closure 382 may be selected to control the open/closed
condition of injection
port 380 without affecting inflow port 316. For example, with the sleeve type
closure as shown,
the sleeve may be installed to ride in an annular recess 386 with an end wall
386a of the recess
acting to limit movement of the sleeve so that it can't move into contact with
port 316 or kobe
312.
The tubular body 310, when installed in a well, allows fluid to be injected
through injection ports
380 into a wellbore to fluid treat the wellbore and to allow backflowing
fluids to be controlled
through inflow controlled inflow ports 316. Thus the tubular body can be
configured between (i)
a run in position, with all ports closed (Figure 10), (ii) a second position
(Figure 11) with
injection port 380 open for fluid treatment of the wellbore while inflow ports
316 are closed, and
(iii) a third position (Figure 12) with inflow ports 316 open and injection
port 380 closed, for
controlled production of the wellbore.
Tubular body 310 may be continuous or formed of a plurality of sections
connected together. In
one embodiment, the tubular body includes one or more subs with ends formed
for connection
into a tubing string, such as a production string, casing, liner, work string,
etc.
Tubular body 310 is connectable into a tubing string for placement in a
wellbore. The string may
include other components such as further frac tools, packers, centralizers,
etc. The packers can
be of any desired type to seal between the wellbore and the tubing string. In
one embodiment, at
least one of the first, second and third packer is a solid body packer
including multiple packing
elements. In such a packer, it is desirable that the multiple packing elements
are spaced apart.
With reference to Figure 13, a tubing string 410a employing this technology
may have a
multistage configuration with a plurality of packers 492 installed therealong
that are each
operable to create an annular seal about the tubing string. When installed in
a wellbore 426, the
annular seals created by packers 492 fill the annulus between the tubing
string and the wellbore
wall and create isolated wellbore segments between the packers. The tubing
string between
adjacent packers can have one or more inflow ports 416a, 416b each equipped
with kobes 412
and fluid controllers 424. In one embodiment, the inflow ports can have inlet
openings (in this
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embodiment those openings having fluid controllers installed therein) spaced
along the string
between packers such that access is provided from the annulus to the inner
diameter through the
plurality along substantially the full length of the wellbore segment. If
wellbore stimulation is
also of interest, the tubing string may include one or more injection ports
480a, 480b between
each set of adjacent packers 492. Thus, when the string is installed and the
packers are set, each
isolated wellbore segment created has one or more inflow ports and possibly
one or more
injection ports.
The injection ports and the inflow ports may be as described above, for
example, injection ports
480a, 480b can each include plug-activated closures 482 that are openable to
perform hydraulic
fracturing jobs and the kobes 412 close inflow ports 416a, 416b and provide
the tubing string
with pressure integrity from either direction during run in, during pressuring
up activities, such
as pressuring up the tubing for setting the packers, and during fracturing,
but allow the ports to
be opened selectively, for example, after fracturing is complete. The fluid
inflow controllers 424
of inflow ports 416a, 416b permit the inflows through the ports to be
controlled, for example,
with respect to removal of oversize debris and/or with respect to flow
characteristics, (i.e.
velocity, flow rate, pressure, etc.)
In view of the foregoing there is provided a method for fluid treatment of a
borehole, the method
comprising: running a tubing string into a wellbore to a desired position for
treating the wellbore;
opening a frac port by application of a force to a sliding sleeve valve for
the frac port; injecting
stimulating fluids through the frac port; closing the frac port; opening a
fluid inflow control port
by opening an inner cap over the fluid control port; and permitting fluid to
pass from the
wellbore into the tool through the fluid inflow control port.
In one method according to the present invention, the fluid treatment is
borehole stimulation
using stimulation fluids such as one or more of acid, gelled acid, gelled
water, gelled oil, CO2,
nitrogen and any of these fluids containing proppants, such as for example,
sand or bauxite. The
method can be conducted in an open hole or in a cased hole. In a cased hole,
the casing may have
to be perforated prior to running the tubing string into the wellbore, in
order to provide access to
the formation.
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16
In an open hole, the packers may include solid body packers including a solid,
extrudable
packing element and, in some embodiments, solid body packers include a
plurality of extrudable
packing elements, The first packer and the second packer can be formed as a
solid body packer
including multiple packing elements, for example, in spaced apart relation.
The present technology may be useful in wells where inflow control is of
interest. For example,
a tubing string with a plurality of packer separated string segment, an
injection port and with
screen media in inflow ports may be employed in a multi-zone fracturing system
for wells that
require some form of sand control after the frac job. For example, some
applications may
include in situ production of heavy oil, potentially for cyclic steam or SAGD
operations.
Alternately, the technology may be appropriate for any poorly consolidated,
semi-consolidated
wells. Alternately, the technology may be suitable for an application where a
hydraulic fracturing
job is performed and where formation fines, shale or frac sand may tend to
flow back into the
liner or to the borehole. In all these applications, it is desirable to
prevent the oversize solids
from being produced. It is desirable to keep the oversize solids outside in
the annulus between
the liner and the casing.
Alternately or in addition, the technology may be appropriate for a high
velocity producing well.
In this type of application, it is desirable to control the rate or volume of
fluids being produced.
It is desirable to employ a controller that meters production, creates a
pressure profile.
In a multistage tubing string, the method can be repeated for each selected
stage of the string.
For example, a frac job can be pumped through a first stage wherein, the
closure for the first
stage frac port is opened, as by launching a plug (i.e. dropping a ball) and
fluids are injected
through that first opened frac port. After that first frac job is pumped,
another plug can be
launched to open a next frac port and a frac can be pumped through that next
frac port. The
process can be continued until all of the stages of interest are fraced. The
sequence of stages can
be opened by launching progressively larger frac plugs, but using sequentially
activated seats,
etc.
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17
After all stages of interest are fraced, the operator may decide to flow the
well back through the
frac ports to recover fluid. Alternately, if sand control is of interest, the
cap portions of the
inflow controlled ports can be opened to allow screened fluid to be produced.
The original frac
ports may be closed, for example as by moving the closure sleeve or another
sleeve to a closed
position. The closure sleeves could be closeable, where the sleeve can be
actively or will
automatically close over the port after an actuating operation, such as
drilling to remove the seat.
In each stage, the injection port may be closed and the inflow port may be
opened by two
separate operations or in one operation. For example, frac port closure
sleeves may be shifted to
a closed position by a shifting tool, while the caps may be opened by another
tool (by impact,
milling, etc.). Alternately, the sleeves may be closed and the caps opened in
one operation by
one tool. For example, the tool may both open the caps and shift the sleeves
as the running tool
is moved up or down through the string's inner diameter. In one embodiment,
for example,
everything occurs as a result of a downward movement of a tool, for example, a
second sleeve
may be provided adjacent the injection port that is pushed down by a tool
moved thereby to
overlie and close the injection port and that tool may also open the kobes as
it passes by the
inflow ports. Thus, a string can have a plurality of individual stages that
can be individually
fraced, but instead of flowing back through the frac ports, flow back can be
through the fluid
inflow controllers, such as sand control media, 1CD, nozzles, gates, etc. when
the kobe cap
portions for the controllers have been opened. This allows an even
distribution of the inflow
across the entire stage, for example the entire segment between packers,
through multiple, axially
spaced apart inflow points. It allows production, while keeping the sand or
the fines outside the
easing, so that clean fluid is produced. Alternately or in addition, inflow
velocities can be
controlled at specific points to alleviate concerns, for example in very high
rate wells, of
erosional issues. Using an appropriate inflow controller, it is possible to
control how much
inflow comes into each segment of the well. In addition, if as the well is
produced, it begins to
collapse, as may occur in a SAGD application, in heavy oil or in lightly
consolidated sand, such
collapse may not have such an adverse impact, as inflow can occur through the
length of the
segment of the well, from packer to packer, and multiple joints can be run
with installed fluid
controllers such as sand control media.
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18
The previous description of the disclosed embodiments is provided to enable
any person skilled
in the art to make or use the present invention. Various modifications to
those embodiments will
be readily apparent to those skilled in the art, and the generic principles
defined herein may be
applied to other embodiments without departing from the spirit or scope of the
invention. Thus,
the present invention is not intended to be limited to the embodiments shown
herein, but is to be
accorded the full scope consistent with the claims, wherein reference to an
element in the
singular, such as by use of the article "a" or an is not intended to mean one
and only one
unless specifically so stated, but rather "one or more". All structural and
functional equivalents
to the elements of the various embodiments described throughout the disclosure
that are know or
later come to be known to those of ordinary skill in the art are intended to
be encompassed by the
elements of the claims. Moreover, nothing disclosed herein is intended to be
dedicated to the
public regardless of whether such disclosure is explicitly recited in the
claims. No claim element
is to be construed under the provisions of 35 USC 112, sixth paragraph, unless
the element is
expressly recited using the phrase "means for" or "step for".
