FIELD OF INVENTION
[0001] Methods and apparatus are presented for selective treatment of a wellbore or
formation. More specifically, the inventions relate to methods and apparatus for selective fluid
communication between a work string and wellbore utilizing a sliding-sleeve, bypass valve
device.
BACKGROUND OF INVENTION
[0002] The present inventions relate, generally, to apparatus and methods used in well
servicing and treatment operations. More specifically, these inventions relate to downhole
apparatus used to selectively provide a flow passage from a tubular string into the wellbore
annulus between the tubular string and the casing (or open hole) in which it is run.
[0003] As is common in the art, nozzles or ports can be utilized to inject fluid into the
annulus surrounding a tubing string to clean various components in the wellbore. For example,
cleaning of subsea surfaces and profiles of subsea wellheads, blowout preventers (BOPs) and the
like, lifting fluid above liner tops and the like to increase annular flow, etc. In other applications,
fluids are injected into the annulus to assist circulation. In a staged fracturing operation, multiple
zones of a formation need to be isolated sequentially for treatment. Fracturing valves typically
employ sliding sleeves, usually ball-actuated. The sleeves can be one-way valves or can be
capable of shifting closed after opening. Initially, operators run the string in the wellbore with
the sliding sleeves closed. A setting ball close the interior passageway of the string by seating on
a ball seat. This seals off the tubing string so, for example, packers can be hydraulically set. At
this point, fracturing surface equipment pumps fluid to open a pressure actuated sleeve so a first
zone can be treated. As the operation continues, successively larger balls are dropped down the
string to open separate zones for treatment.
[0004] Despite the general effectiveness of such assemblies, practical limitations restrict
the number of balls that can be run in a single tubing string. Moreover, depending on the
formation and the zones to be treated, operators may need a more versatile assembly that can suit
their immediate needs. Further, staged sliding sleeves can tend to "skip" positions in response to
raised tubing pressure, creating issues with opening a zone to treatment, etc.
SUMMARY OF THE INVENTION
[0005] The disclosed downhole bypass valve utilizes a stationary sleeve defining an
interior ball-seat. When a dropped ball is seated, fluid differential pressure is diverted to an
annular area adjacent a first sliding sleeve. The sleeve slides in response to the pressure
differential upon shearing of a shear pin, or similar, and opens ports to the wellbore annulus.
Treatment or maintenance operations can then occur through the ports, which can be fitted with
nozzles. A second sliding sleeve, independent from the first, is operated in response to dropping
a second ball into the device. The second ball diverts fluid differential pressure to an annular area
adjacent the second sleeve and movement occurs when a shear pin shears. The second sleeve
covers the ports to the wellbore annulus and closes the valve. After a sliding sleeve shifts,
pressure across the sleeve is equalized, allowing reverse flow without risk of accidental sleeve
actuation. Accidental shifting or "skipping" of sleeve positions is reduced as the sleeves are
independently operated.
[0006] The tool is limited to one full cycle (close-open-close), however, different
diameter inner sleeves and ball seats can be used to accept different ball sizes, allowing multiple
tools to be stacked vertically for additional cycles.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] For a more complete understanding of the features and advantages of the present
invention, reference is now made to the detailed description of the invention along with the
accompanying figures in which corresponding numerals in the different figures refer to
corresponding parts and in which:
[0008] FIG. 1 is a schematic view of an exemplary embodiment of a work string having a
plurality of valve assemblies thereon according to an aspect of the invention;
[0009] FIG. 2 is a cross-sectional schematic of an exemplary valve device according to an
aspect of the invention with the valve in an initial closed, or run-in, position;
[0010] FIG. 3 is a cross-sectional schematic of the exemplary valve device of FIG. 2, with
the valve in an actuated open position;
[0011] FIG. 4 is a cross-sectional schematic of the exemplary valve device of FIG. 2, with
the valve in a final closed position.
[0012] It should be understood by those skilled in the art that the use of directional terms
such as above, below, upper, lower, upward, downward and the like are used in relation to the
illustrative embodiments as they are depicted in the figures, the upward direction being toward
the top of the corresponding figure and the downward direction being toward the bottom of the
corresponding figure. Where this is not the case and a term is being used to indicate a required
orientation, the Specification will state or make such clear.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0013] While the making and using of various embodiments of the present invention are
discussed in detail below, a practitioner of the art will appreciate that the present invention
provides applicable inventive concepts which can be embodied in a variety of specific contexts.
The specific embodiments discussed herein are illustrative of specific ways to make and use the
invention and do not limit the scope of the present invention. The description is provided with
reference to a horizontal wellbore. However, the inventions disclosed herein can be used in
horizontal, vertical, or deviated wellbores. As used herein, the words "comprise," "have,"
"include," and all grammatical variations thereof are each intended to have an open, non-limiting
meaning that does not exclude additional elements or steps. The terms "uphole," "downhole,"
and the like, refer to movement or direction closer and farther, respectively, from the wellhead,
irrespective of whether used in reference to a vertical, horizontal or deviated borehole. The terms
"upstream" and "downstream" refer to the relative position or direction in relation to fluid flow,
again irrespective of the borehole orientation. Those of skill in the art will recognize where the
inventions disclosed herein can be used in conjunction with jointed tubing string, coiled tubing,
or wireline. The inventions herein can also be used with on-shore rigs, off-shore rigs, subsea and
deep-sea rigs, etc.
[0014] FIG. 1 is a schematic view of a typical tubing string positioned in a subterranean
wellbore. As used herein, "tubing string," "work string," and the like are used interchangeably
and are to be construed as inclusive of various types of string or strings for various operations,
such as work strings, work-overs, servicing, production, injection, stimulation, etc. The tool can
also be used as a jetting and bypass tool in various operations, including BOP jetting, bore
cleaning, fluid displacements, drilling and displacement boosting, as a drain sub, etc. The
apparatus is useful for stimulation of a formation, using stimulation fluids, such as for example,
acid, gelled acid, gelled water, gelled oil, nitrogen, or proppant laden fluids. The apparatus may
also be useful to open the tubing string to production fluids. Further, the device can be used in
injection, fracturing, staged fracturing, and other treatment operations.
[0015] FIG. 1 shows a well system 10 having a wellbore 12 extending through one or
more subterranean formations or zones 11. A work string 14 is positioned in the wellbore and
has a plurality of sliding sleeve-operated valve devices 16. Other string configurations, varying
numbers and spacing of devices, etc., can be used, as will be apparent to those of skill in the art.
In the assembly illustrated, the sleeves are used to control fluid flow through the string and into
selected zones 1 1 through the wellbore 12. Tubing string 14 includes a plurality of spaced-apart,
selectively operable, sliding sleeve valve devices 16 each having a plurality of ports 17
extending through the tubing wall to selectively permit fluid flow between the tubing string inner
bore and the annulus between the work string and wellbore 12. Any number of devices 16 can be
used in each interval, grouped adjacent one or more target zones, etc. A plurality of annular
sealing devices 20 is mounted on the string between sliding sleeve devices 16. Exemplary
annular sealing devices include mechanically, hydraulically, electromechanically, chemically, or
temperature-activated packers, plugs, etc., as are known in the art. The annular sealing devices
can be used to isolate formation zones, or sections of wellbore, for interval treatment, etc. The
packers are disposed about the tubing string and selected to seal the annulus between the tubing
string and the wellbore wall, when the assembly is disposed in the wellbore. The packers divide
the wellbore into isolated sections so that fluid can be applied to selected sections of the well, but
prevented from passing through the annulus into adjacent segments. As will be appreciated, the
packers can be spaced in any way relative to the ported intervals to achieve a desired interval
length or number of ported intervals per segment.
[0016] Sliding sleeve devices 16 are disposed along the tubing string to selectively
control the opening and closing of the ports. A sliding sleeve is mounted to control flow through
each ported valve. In a preferred embodiment, the valve devices are closed during run-in and can
be opened, and later closed, to allow and stop fluid flow into the wellbore. The assembly is runin
and positioned downhole with the sliding sleeve devices in closed positions. The sleeves are
selectively moved to an open position when the tubing string is ready for use in fluid treatment
of the wellbore. The sliding sleeve valve devices 16 for each isolated section can be opened
individually and sequentially to permit fluid flow to the wellbore.
[0017] The sliding sleeve valve devices are each moveable between closed and open
positions by selective application of tubing pressure and without having to run a line for
manipulation. The valve devices are actuated by a dropped ball (not shown). The term "ball" as
used herein includes alternates such as darts, bars, or other plugging device, which can be
conveyed by gravity or fluid flow through the tubing string. The dropped ball engages a seat
positioned in the valve device and plugs fluid flow through the interior bore of the string. When
pressure is applied through the tubing string bore, the ball creates a pressure differential across
the valve. This pressure differential is used to operate the valve, sliding a sleeve in the valve and
opening the associated ports. Fluid flows into the wellbore annulus and into contact with the
formation.
[0018] Multiple sliding sleeve valve devices 16 can be used by dropping sequentially
larger diameter balls which mate with sequentially larger ball seats. In particular, the lower-most
device has the smallest diameter seat and each device progressively closer to surface has a larger
diameter seat. The preferred embodiment disclosed herein also provides for the selective closing
of the sliding sleeve valve device by dropping of a subsequent ball.
[0019] At the surface is an appropriate rig, 15 derrick or the like, and various other
surface equipment 19, such as pumping equipment, etc., as in known in the art for well servicing
and treatment operations.
[0020] The lower end 28 of the tubing string 14 can be open, closed, or fitted in various
ways, depending on the operational characteristics of the tubing string that are desired. Further
components and tools can be used in conjunction with the tubing string, such as additional
sealing devices, connection joints, measuring and sensing equipment, downhole pumps, valves,
tool actuators, communication lines, transmission devices, etc., as those of skill in the art will
recognize.
[0021] FIG. 2 is a cross-sectional schematic of an exemplary valve device according to
an aspect of the invention with the valve in an initial closed, or run-in, position. FIG. 3 is a crosssectional
schematic of the exemplary valve device of FIG. 2, with the valve in an actuated open
position. FIG. 4 is a cross-sectional schematic of the exemplary valve device of FIG. 2, with the
valve in a final closed position. The figures will be discussed together with specific references to
particular figures as necessary. The exemplary embodiment shown here is of particular use in
jetting and bypass operations, such as BOP jetting, bore cleaning, etc. Variations known in the
art to practitioners can be employed for use of the device for fluid displacements, drilling and
displacement boosting, as a drain sub, stimulation, fracturing, production, etc.
[0022] The tool embodiment shown is a downhole, ball-actuated, jetting or bypass valve.
The valve is ball-actuated and provides for one complete cycle (closed-open-closed). The tool
preferably has four sleeves positioned in a tool body or housing: two sliding or shifting sleeves,
one for opening the valve and one for closing the valve, a stationary ball-seat sleeve, and a
retaining sleeve. When a dropped or pumped ball lands on the seat in the seat sleeve, a pressure
differential is created on an upwardly-facing annular area of the first sliding sleeve. When the
differential is high enough, a shear pin is sheared and the first sliding sleeve shifts, uncovering
ports and opening the tool to fluid flow into the wellbore annulus. Similarly, dropping a second
ball acts on the second sliding sleeve, shifting the second sleeve to a closed position and shutting
off flow to the wellbore annulus.
[0023] Both opening and closing sleeves are fully independent, eliminating any concerns
of double-shifting or "skipping" the open position. Following activation and deactivation, both
shifting sleeves are pressure equalized, meaning full reverse circulation can occur without
concerns of reverting back to a previous position. Internal sleeves can be assembled outside of
the main body for ease of assembly. Flow area after activation is preferably equal to or greater
than before activation. The open-bore design allows wireline tools to be run in conjunction with,
and through, the device prior to activation.
[0024] An exemplary sliding sleeve device 30 is attached to, and forms part of, a work
string. The work string has a fluid flow passageway 32, typically a central bore, for passing fluid
between downhole locations and the surface. The fluid flow passageway includes a fluid
passageway 34 defined in the device 30. Fluid can be flowed through the device to locations
downhole or uphole when the device is in its run-in or initial position, as seen in FIG. 2.
[0025] The device 30 has a generally tubular housing 36 which is attachable to a work
string by methods known in the art. A plurality of radial ports 38 extend through the housing,
providing fluid communication between the wellbore annulus and the interior of the device. The
ports 38 are shown extending radially at a right angle to the longitudinal axis of the device,
although alternate orientations can be used. The ports 38 can be altered or designed for the
specific use of the device. For example, as shown, the ports 38 are fitted with jetting nozzles 40,
which can be selected based on expected use and which are preferably exchangeable for different
nozzles 40 of varying size, for more or less flow splitting, for jetting velocity and spray pattern,
etc. In a preferred embodiment, the nozzles 40 are inserted through aligned holes or ports 38 and
54 in the housing 36 and retaining sleeve 42, serving to orient the internal parts of the device and
to lock the housing and retaining sleeve axially and radially.
[0026] The exemplary valve device 30 has a retaining sleeve 42 and a stationary
internal sleeve or ball- seat sleeve 44. Defined between, and preferably by the surfaces of, the
retaining sleeve 42 and ball-seat sleeve 44 is an annular space 46 for two sliding sleeves, a first
or lower sliding sleeve 48 and a second or upper sliding sleeve 50. The retaining sleeve 42 is
positioned in the housing and remains stationary in use. The retaining sleeve can be attached to
the housing by means known in the art. Similarly, the interior ball-seat sleeve 44 remains
stationary in use and can be attached to the housing, the retaining sleeve, or both, by means
known in the art. In the embodiment shown, the lower end of the ball-seat sleeve abuts a
shoulder 52 defined by the housing. The retaining sleeve has radial ports 54 which align with
ports 38 of the housing to allow fluid communication radially across the retaining sleeve. Where
nozzles 40 are employed, they can extend into and attach to the ports 54, align the ports 54 and
38, and position and/or lock the retaining sleeve radially and axially to the housing.
[0027] The inner sleeve 44 has a generally open interior passageway 34 and defines
several radial ports extending through the sleeve wall and providing fluid communication
between the passageway and the exterior of the sleeve. As best seen in FIG. 2, the various ports
include upper pressure ports 56, lower pressure ports 58, flow ports 60, and pressure equalization
ports 62. The upper pressure ports 56 provide fluid communication between the interior
passageway 34 and the upper annular chamber 64. Lower pressure ports 58 provide fluid
communication between the interior passageway and the central annular chamber 66. Flow ports
60 provide fluid communication between the interior passageway and the lower annular chamber
68. Finally, the pressure equalization ports 62 provide fluid communication between the interior
passageway and the lower annular chamber 68.
[0028] The inner sleeve 44 has, or defines, a ball seat 70 operable to catch an
appropriately sized ball. That is, the ball seat has a diameter slightly smaller than the cooperating
ball diameter. The inner sleeve can also have a second ball seat defined therein (not shown) for
catching a second ball of slightly larger size. In the preferred embodiment, a second ball seat is
unnecessary as the first dropped ball 72 acts to "catch" or stop the second dropped ball 74.
[0029] The lower sliding sleeve 48 moves between an initial or closed position, as seen
in FIG. 2, and an actuated or open position, as seen in FIG. 3. The lower sliding sleeve is initially
held in place by one or more selective release mechanisms, such as a shear ring, shear pin, snapring,
etc. In a preferred embodiment, the sleeve is held in place by shear pin 76.
[0030] The upper sliding sleeve 50 moves between an initial or first position, as seen in
FIG. 3, and an actuated or closed position, as seen in FIG. 4. The lower sliding sleeve is initially
held in place by one or more selective release mechanisms, such as a shear ring, shear pin, snapring,
etc. In a preferred embodiment, the sleeve is held in place by shear pin 78.
[0031] When the lower sleeve is in the closed position, fluid flow through the ports 38 is
blocked. When the lower sliding sleeve is moved to the open position (and the upper sleeve
remains in its initial position), as in FIG. 3, fluid is free to flow from interior passageway 34,
through lower pressure ports 58, through annular chamber 66, and exit the device and work
string into the wellbore annulus through ports 38 and, if present, nozzles 40. When the upper
sleeve is moved to its closed position, FIG. 4, fluid is once again blocked from flowing from the
interior passageway to the wellbore annulus.
[0032] In use, the valve device is attached to a work (or other) string and run-in to the
wellbore hole. Typically, the device is run-in in a closed position, such that fluid is blocked from
flowing from the interior passageway to the exterior of the device. Once positioned where
desired and, if necessary, after other operations have occurred, such as setting isolation devices,
etc., the device is ready for use. Fluid flows through the interior passageway 34 which makes up
a part of a longer interior passageway 32 of the string. Fluid can be flowed downhole or uphole
through the passageway 34 without actuating either sliding sleeve at this point. Further, the
interior passageway 34 is sufficiently free of obstructions to allow use of wireline conveyed
tools.
[0033] When it is desired to open the valve device, a ball (or other similar object) is
dropped or flowed into the interior passageway. The ball seats on a cooperating ball seat 70
defined in the interior passageway 34 of the device, preferably on the interior surface of the inner
or ball-seat sleeve. The seated ball 72 remains stationary, as does the inner sleeve 44, and blocks
or restricts fluid flow through the passageway 34 and creates a pressure differential across the
ball. The differential pressure is diverted by the blockage of the passageway, through the
pressure ports 58 in the inner sleeve 44, to annular chamber 66, where the pressure acts with
downward force on an upper surface of the lower sliding sleeve 48. The sliding sleeve 48,
slidingly positioned between the inner sleeve 44 and the retaining sleeve 42, is forced downward,
shearing the shear pin 76. Upon shearing of the pin 76, the lower sliding sleeve 48 moves from
its initial position, wherein the sleeve blocks fluid flow through ports 38 to the wellbore annulus
exterior to the device, to an open position, wherein such flow is allowed. Fluid can now flow
from the interior passageway 35 above the first ball 72, through lower pressure ports 58, along
annular chamber 66, and through the external ports 38. Fluid is flowed or jetted out of the device
through ports 38 and nozzles 40 (if present). Flow can also be allowed from the annular chamber
66 through the flow ports 60 and back into the interior passageway 34 below the first ball 72.
Additionally, in a preferred embodiment, flow is allowed between the inner passageway 34 and
an annular chamber 68 defined below the lower sliding sleeve 48, through pressure equalization
ports 62, such that pressure is equalized across the lower sliding sleeve.
[0034] Various wellbore operations can then be performed. For example, nozzles 40,
positioned in or adjacent ports 38, can be used for BOP jetting, bore cleaning, and the like. The
open ports can be used for fluid displacements, drilling and displacement boosting, as a drain
sub, for stimulation, injection, fracturing, production, etc., operations.
[0035] When it is desired to close the device, a second ball 74 is dropped into the
passageway and seats itself on, or is stopped by contact with, the first ball 72. The second ball 74
blocks fluid flow from the interior passageway 34 through the lower pressure ports 58. As a
differential pressure is built across the second ball, the pressure is diverted through the upper
pressure ports 56 to annular chamber 64. The seated and stationary ball 72 blocks fluid flow
across the device, creating a pressure differential across the device. The differential pressure is
diverted through the upper pressure ports 56 in the inner sleeve 44, to annular chamber 64, where
the pressure acts with downward force on an upwardly facing surface 80 of the upper sliding
sleeve 50. The sliding sleeve 50, slidingly positioned between the inner sleeve 44 and the
retaining sleeve 42, is forced downward, shearing the shear pin 78. Upon shearing of the pin 78,
the upper sliding sleeve 50 moves from its initial position, wherein the sleeve does not block
fluid flow through ports 38 to the wellbore annulus exterior to the device, to a closed position,
wherein such flow is blocked. Fluid can now flow from the interior passageway 34 above the
second ball 74, through upper pressure ports 56, along annular chamber 64, and through the flow
ports 60 back into the interior passageway 34 below the first ball 72. Additionally, in a preferred
embodiment, fluid is allowed between the inner passageway 34 and annular chamber 66 (now
defined between adjacent upper and lower sliding sleeves), such as through flow ports 60, such
that pressure is equalized across the upper sliding sleeve.
[0036] Note that in a preferred embodiment, the flow area (which governs flow rate)
available after the lower sliding sleeve shift is the same or even greater than the flow area
available in the initial or run-in position. The counter-bored portion of the housing 36 and the
movement of the sleeve to its open position, opens up an annular flow area between the inner
sleeve 44 and retaining sleeve 42. Similarly, after the second ball 74 is dropped and the upper
sliding sleeve 50 is shifted, closing (blocking) the ports 38, an annular flow area is opened which
is, preferably, as large as or larger than the initial flow area through the passageway 34. The
annular flow area is defined between the inner sleeve 44 and the interior surface of the upper
sliding sleeve 50. (Alternately, the annular area can be defined in part by the retaining sleeve.)
The upper sliding sleeve 50 can have a radially enlarged annular area defined on its upper inner
surface for this purpose. These relatively large annular flow areas allow for a greater flow rate
through the device than is typical in such bypass valves of similar diameter.
[0037] The valve device is limited to a single closed-open-closed cycle. However,
multiple devices can be stacked along the work string, with successive uphole devices having
successively larger diameter ball seats for use with cooperating dropped balls. In this manner,
multiple cycles along a single isolated section is possible, or multiple isolated zones can be
treated sequentially.
[0038] Upon closure of the valve device, fluid can be flowed and reverse flowed through
the device passageway. The upper and lower sliding sleeves will not shift positions as they are
pressure balanced. For example, fluid can be produced from the formation into the tubing string,
the wellbore can be drained or flushed of fluids, etc. It is also possible to provide for locking of
the sliding sleeves in their activated positions, such as by cooperating profiles, snap rings, etc.
[0039] Also note that the device is designed such that a valve assembly, comprising the
retaining sleeve, two sliding sleeves and inner sleeve, can be assembled into a unit, and then
inserted into (or removed from) a counter-bored housing. This eases assembly, disassembly,
allows for interchangeable units of varying diameter seats, etc.
[0040] For further disclosure regarding bypass valves and the like, see the following
references, all of which are incorporated herein by reference in their entirety for all purposes:
U.S. Patent Nos. 8,215,411 to Flores, et al.; 7,201,232 to Turner, et al.; 7,150,326; 6,877,566;
6,467,546 to Allamon, et al.; 6,253,861; and 6,065,541; and U.S. Pat. App. Pub. No.
2011/0278017 to Themig, et al. Also see, for example, commercial bypass valve tools, such as
the Jet Tech (trade name) tool available commercially from Halliburton Energy Services, Inc.,
and Bico Drilling Tools, Inc., Multiple Activation Bypass Tool (see, on-line literature at
bicodrilling.com, Multiple Activation Bypass Tool, etc.) also available commercially.
[0041] In the preferred and exemplary methods presented hereinabove, various method
steps are disclosed, where the steps listed are not exclusive, can sometimes be skipped, or
performed simultaneously, sequentially, or in varying or alternate orders with other steps (i.e.,
steps XYZ can be performed as XZY, YXZ, YZX, ZXY, etc.) (unless otherwise indicated), and
wherein the order and performance of the steps is disclosed additionally by the claims appended
hereto, which are incorporated by reference in their entirety into this specification for all
purposes (including support of the claims) and/or which form a part of this specification, the
method steps presented in the following text. Exemplary methods of use of the invention are
described, with the understanding that the invention is determined and limited only by the
claims. Those of skill in the art will recognize additional steps, different order of steps, and that
not all steps need be performed to practice the inventive methods described.
[0042] While this invention has been described with reference to illustrative
embodiments, this description is not intended to be construed in a limiting sense. Various
modifications and combinations of the illustrative embodiments as well as other embodiments of
the invention, will be apparent to person skilled in the art upon reference to the description. It is,
therefore, intended that the appended claims encompass any such modifications or embodiments.

It is claimed:
1. A method for servicing a subterranean wellbore extending through a formation, the
method comprising the steps of:
a) positioning at a downhole location a sliding sleeve valve device, the device having an
inner sleeve defining a longitudinal passageway therethrough, the inner sleeve
positioned in, and stationary with respect to, a generally tubular housing, and first and
a second sliding sleeve positioned for sliding movement in an annular space between
the inner sleeve and housing;
b) flowing fluid through the device passageway;
c) positioning a first ball on a ball seat defined in the inner sleeve;
d) blocking fluid flow through the device passageway using the first ball;
e) building a first differential pressure across the first ball;
f applying the first differential pressure, through a first pressure port extending through
the wall of the inner sleeve, to a surface of the first sliding sleeve;
g) slidingly moving the first sliding sleeve in response to the first differential pressure;
h) opening radial housing ports through the housing by movement of the first sliding
sleeve;
i) flowing fluid through the housing ports from the device passageway to a wellbore
annulus defined between the housing and the wellbore;
j ) positioning a second ball in the inner sleeve;
k) blocking fluid flow through the device passageway using the second ball;
1) building a second differential pressure across the device;
m) applying the second differential pressure, through a second pressure port extending
through the wall of the inner sleeve, to a surface of the second sliding sleeve;
n) slidingly moving the second sliding sleeve in response to the second differential
pressure;
o) closing the radial housing ports by movement of the second sliding sleeve; and
p) flowing fluid through the device passageway.
2. The method of claim 1, wherein step a) further comprises the steps of attaching the
device to a tubing string.
3. The method of claim 1, wherein the first and second balls are generally spherical.
4. The method of claim 1, further comprising the step of moving wireline tools
through the device passageway prior to step d).
5. The method of claim 1, further comprising the step of setting annular isolation
devices positioned in the wellbore prior to step d).
6. The method of claim 1, wherein steps g) and n) further comprise the step of
shearing a shearing mechanism to allow sliding movement of the sliding sleeve.
7. The method of claim 1, wherein differential pressure is built by pumping fluid
downhole and into the device passageway in steps e) and 1).
8. The method of claim 1, wherein the radial housing ports further include fluid
nozzles.
9. The method of claim 1, wherein the device further comprises a retaining sleeve
positioned between the sliding sleeves and the housing, the retaining sleeve having radial
retaining sleeve ports aligned with the radial housing ports.
10. The method of claim 9, wherein the radial housing ports are fitted with nozzles, and
wherein the nozzles maintain the retaining sleeve and housing aligned axially and rotationally.
11. The method of claim 1, wherein the first ball remains stationary with respect to the
inner sleeve and housing during at least steps d) through h).
12. The method of claim 1, wherein the second ball remains stationary with respect to
the inner sleeve and housing during at least steps k) through o).
13. The method of claim 11, wherein the second ball remains stationary with respect to
the inner sleeve and housing during at least steps k) through o).
14. The method of claim 1, further comprising the step of equalizing pressure across the
first sliding sleeve in response to step g).
15. The method of claim 14, further comprising the step of equalizing pressure across
the second sliding sleeve in response to step n).
16. The method of claim 14, wherein the step of equalizing pressure comprises the step
of allowing fluid communication, through pressure equalization ports in the inner sleeve, from
the device passageway below the first ball to an annular space below the first sliding sleeve.
17. The method of claim 1, wherein step i) further comprises at least one of cleaning
surfaces of a subsea wellhead, cleaning surfaces of a blowout preventer, lifting fluid to increase
annular flow, injecting treatment fluids into the wellbore, circulating fluids through the wellbore,
or fracturing at least one zone in the formation.
18. The method of claim 1, wherein step i) further comprises the step of flowing fluid
from the device passageway above the first ball to the device passage below the first ball by
flowing fluid longitudinally through an annular space defined between the inner sleeve and
housing, and wherein such fluid flow is allowed by the movement of the first sliding sleeve in
step g).
19. The method of claim 18, wherein step i) further comprises flowing fluid through
radial ports in the inner sleeve positioned longitudinally above and below the first ball.
20. The method of claim 1, wherein step p) further comprises flowing fluid in a reverse
direction through the device passageway.
21. The method of claim 20, wherein the step p) further comprises producing
hydrocarbon fluid from the formation.
22. The method of claim 1, wherein the device passageway defines a passageway flow
area, across which fluid flows when the passageway is unobstructed by a ball, and wherein a
bypass flow area is defined by the annular space between the inner sleeve and the housing, after
movement of the first sliding sleeve in step g), across which fluid flows after step g), and
wherein the bypass flow area is at least as large as the passageway flow area.
23. The method of claim 1, further comprising the step of moving a third ball,
unassociated with operation of the device, through the device passageway prior to step c), the
third ball having a smaller diameter than the ball seat diameter of the device.
24. The method of claim 1, wherein step a) further comprises positioning at a plurality
of downhole locations a corresponding plurality of sliding sleeve valve devices.
25. The method of claim 24, further comprising performing steps as described in steps
b) through o) for each of the plurality of sliding sleeve devices positioned in the wellbore,
sequentially.
26. A downhole valve device, comprising:
a housing defining an interior passageway therethrough and having a radial housing
port for fluid communication between the interior passageway and the exterior of the housing;
a ball-seat sleeve mounted in, and stationary with respect to, the housing, and
having a ball seat defined therein for catching a first dropped ball, the first dropped ball for
blocking fluid flow through the interior passageway;
a first sliding sleeve slidably mounted in a sliding sleeve annulus defined between
the housing and the ball-seat sleeve, the first sliding sleeve movable between an initial, closed
position, wherein the first sliding sleeve blocks fluid communication through the radial housing
port, and an open position, wherein fluid communication is allowed through the radial housing
port; and
a second sliding sleeve slidably mounted in the sliding sleeve annulus defined
between the housing and the ball-seat sleeve, the second sliding sleeve movable between an
initial position, wherein the second sliding sleeve does not block the radial housing port, and a
closed position, wherein the second sliding sleeve blocks fluid communication through the radial
housing port.
27. The device of claim 26, further comprising a first pressure port in the ball-seat
sleeve providing fluid communication between the interior passageway and the sliding sleeve
annulus above the first sliding sleeve when in its closed position and above the ball seat.
28. The device of claim 27, further comprising a flow port in the ball-seat sleeve
providing fluid communication between the interior passageway and the sliding sleeve annulus
below the ball seat and above the first sliding sleeve when in its open position.
29. The device of claim 28, further comprising a second pressure port in the ball-seat
sleeve providing fluid communication between the interior passageway and the sliding sleeve
annulus above the ball seat and above the second sliding sleeve.
30. The device of claim 28, further comprising a pressure equalization port in the ballseat
sleeve providing fluid communication between the interior passageway and the sliding
sleeve annulus below the first sliding sleeve when in its open position.
31. The device of claim 26, further comprising shear mechanism for releasably holding
the sliding sleeves in their initial positions.
32. The device of claim 26, wherein the interior passageway defines a passageway flow
area across which fluid flows when the passageway is unobstructed, and wherein a bypass flow
area is defined by the sliding sleeve annulus across which fluid flows when the interior
passageway is blocked by a ball, and wherein the bypass flow area is at least as large as the
passageway flow area.
33. The device of claim 26, further comprising a retaining sleeve positioned between
the housing and ball-seat sleeve.