U.S. patent application number 13/745116 was filed with the patent office on 2014-07-24 for well intervention pressure control valve.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Eric BIVENS, Timothy Holiman HUNTER, Takao STEWART.
Application Number | 20140202713 13/745116 |
Document ID | / |
Family ID | 51206833 |
Filed Date | 2014-07-24 |
United States Patent
Application |
20140202713 |
Kind Code |
A1 |
STEWART; Takao ; et
al. |
July 24, 2014 |
Well Intervention Pressure Control Valve
Abstract
A system comprising a control valve comprising a flapper either
activated or inactivated, when activated the flapper may be closed
or open and, when inactivated the flapper is open, a first sleeve
transitional from a first to a second position, and a second sleeve
transitional from a first to a second position, when the first and
second sleeves are in the first position, the flapper is activated,
when the first sleeve is in the second and the second sleeve is in
the first position, the flapper is inactivated, when the first and
second sleeves are in the second position, the flapper is
activated, the application of pressure to the first sleeve via a
first member transitions the first sleeve from the first to the
second position, and the application of pressure to the second
sleeve via a second member transitions the second sleeve from the
first to the second position.
Inventors: |
STEWART; Takao; (Chickasha,
OK) ; BIVENS; Eric; (Seacliff, AU) ; HUNTER;
Timothy Holiman; (Duncan, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
51206833 |
Appl. No.: |
13/745116 |
Filed: |
January 18, 2013 |
Current U.S.
Class: |
166/386 ;
166/319 |
Current CPC
Class: |
E21B 34/103 20130101;
E21B 34/14 20130101; E21B 34/06 20130101; E21B 34/102 20130101;
E21B 34/12 20130101; E21B 2200/05 20200501 |
Class at
Publication: |
166/386 ;
166/319 |
International
Class: |
E21B 34/06 20060101
E21B034/06 |
Claims
1. A wellbore servicing system comprising: a work string; and a
pressure control valve tool incorporated within the work string and
comprising: a housing generally defining an axial flowbore; a
flapper valve disposed within the axial flowbore and configurable
between an activated state and an inactivated state, wherein, in
the activated state the flapper valve is free to move between a
closed position in which the flapper valve blocks the axial
flowbore and an open position in which the flapper valve does not
block the axial flowbore, and wherein, in the inactivated state the
flapper valve is retained in the open position; a first sleeve
slidably positioned within the housing and transitional from a
first position to a second position with respect to the housing;
and a second sleeve slidably positioned within the first sleeve and
transitional from a first position to a second position with
respect to the first sleeve; wherein, when the first sleeve is in
the first position with respect to the housing and the second
sleeve is in the first position with respect to the first sleeve,
the flapper valve is in the activated state; wherein, when the
first sleeve is in the second position with respect to the housing
and the second sleeve is in the first position with respect to the
first sleeve, the flapper valve is in the inactivated state;
wherein, when the first sleeve is in the second position with
respect to the housing and the second sleeve is in the second
position with respect to the first sleeve, the flapper valve is in
the activated state; and wherein, engagement of a first obturating
member with the first sleeve and the application of a pressure of
at least a threshold pressure onto the first obturating member
causes the first sleeve to transition from the first position to
the second position with respect to the housing and such that the
engagement of a second obturating member with the second sleeve and
the application of a pressure of at least a threshold pressure onto
the second obturating member causes the second sleeve to transition
from the first position to the second position with respect to the
first sleeve.
2. The wellbore servicing system of claim 1, wherein when the first
sleeve is in the first position, the first sleeve is releasably
coupled to the housing via a first retaining device comprising a
shear pin, a snap ring, a biased pin, or combinations thereof.
3. The wellbore servicing system of claim 2, wherein when the first
sleeve is in the second position, the first sleeve is coupled to
the housing via a snap ring.
4. The wellbore servicing system of claim 1, wherein when the
second sleeve is in the first position, the second sleeve is
releasably coupled to the first sleeve via a second retaining
device comprising a shear pin, a snap ring, a biased pin, or
combinations thereof.
5. The wellbore servicing system of claim 4, wherein when the
second sleeve is in the second position, the second sleeve is not
coupled to the first sleeve.
6. The wellbore servicing system of claim 1, wherein the first
obturating member may be sized to engage the first sleeve and not
the second sleeve.
7. The wellbore servicing system of claim 6, wherein the second
obturating member may be sized to engage the second sleeve and not
the first sleeve.
8. The wellbore servicing system of claim 1, wherein the pressure
control valve tool comprises two or more flapper valves disposed
within the axial flowbore and configurable between the activated
state and the inactivated state.
9. A wellbore servicing method comprising: positioning a work
string comprising a pressure control valve tool (PCVT) in a first
configuration incorporated therein within a wellbore, wherein in
the first configuration the PCVT provides unidirectional fluid flow
through the work string; introducing of a first obturating member
within the PCVT and applying at least a pressure threshold onto the
first obturating member thereby allowing bidirectional fluid
communication through the work string; introducing of a second
obturating member within the PCVT and applying of at least a
pressure threshold onto the second obturating member thereby
allowing unidirectional fluid communication; and removing the
working string comprising the PCVT from the wellbore.
10. The wellbore servicing method of claim 9, wherein the PCVT
further comprises: a housing generally defining an axial flowbore;
a flapper valve disposed within the axial flowbore and configurable
between an activated state and an inactivated state; wherein, in
the activated state the flapper valve is free to move between a
closed position in which the flapper valve blocks the axial
flowbore and an open position in which the flapper valve does not
block the axial flowbore; and wherein, in the inactivated state the
flapper valve is retained in the open position; a first sleeve
slidably positioned within the housing and transitional from a
first position to a second position with respect to the housing;
and a second sleeve slidably positioned within the first sleeve and
transitional from a first position to a second position with
respect to the first sleeve; wherein, when the first sleeve is in
the first position with respect to the housing and the second
sleeve is in the first position with respect to the first sleeve,
the flapper valve is in the activated state; wherein, when the
first sleeve is in the second position with respect to the housing
and the second sleeve is in the first position with respect to the
first sleeve, the flapper valve is in the inactivated state;
wherein, when the first sleeve is in the second position with
respect to the housing and the second sleeve is in the second
position with respect to the first sleeve, the flapper valve is in
the activated state; and wherein, engagement of a first obturating
member with the first sleeve and the application of a pressure of
at least a threshold pressure onto the first obturating member
causes the first sleeve to transition from the first position to
the second position with respect to the housing and such that the
engagement of a second obturating member with the second sleeve and
the application of a pressure of at least a threshold pressure onto
the second obturating member causes the second sleeve to transition
from the first position to the second position with respect to the
first sleeve.
11. The wellbore servicing method of claim 10, wherein when the
first sleeve is in the first position, the first sleeve is
releasably coupled to the housing via a first retaining device
comprising a shear pin, a snap ring, a biased pin, or combinations
thereof.
12. The wellbore servicing method of claim 11, wherein when the
first sleeve is in the second position, the first sleeve is coupled
to the housing via a snap ring.
13. The wellbore servicing method of claim 10, wherein when the
second sleeve is in the first position, the second sleeve is
releasably coupled to the first sleeve via second retaining device
comprising a shear pin, a snap ring, a biased pin, or combinations
thereof.
14. The wellbore servicing method of claim 13, wherein when the
second sleeve is in the second position, the second sleeve is not
coupled to the first sleeve.
15. The wellbore servicing method of claim 14, wherein the first
obturating member may be sized to engage the first sleeve and not
the second sleeve.
16. The wellbore servicing method of claim 15, wherein the second
obturating member may be sized to engage the second sleeve and not
the first sleeve.
17. The wellbore servicing method of claim 9, wherein the pressure
control valve tool comprises two or more flapper valves disposed
within the axial flowbore and configurable between the activated
state and the inactivated state.
18. A wellbore servicing method comprising: positioning a work
string comprising a pressure control valve tool (PCVT) in a first
configuration incorporated therein within a wellbore, wherein, the
PCVT is configurable from the first configuration to a second
configuration and from the second configuration to a third
configuration, wherein, when the PCVT is in the first
configuration, the PCVT is configured to allow a route of fluid
communication in a down-hole direction and to disallow a route of
fluid in an up-hole direction via the PCVT, wherein, when the PCVT
is in the second configuration, the PCVT is configured to allow
bidirectional fluid communication via the PCVT, and wherein, when
the PCVT is in the third configuration, the PCVT is configured to
allow a route of fluid communication in a down-hole direction and
to disallow a route of fluid in an up-hole direction via the PCVT;
transitioning the PCVT from the first configuration to the second
configuration thereby allowing bidirectional fluid communication
through the work string; transitioning the PCVT from the second
configuration to the third configuration thereby allowing
unidirectional fluid communication; and removing the working string
comprising the PCVT from the wellbore.
19. The wellbore servicing method of claim 18, wherein the PCVT
transitions from the first configuration to the second
configuration upon the introduction of a first obturating member
within the PCVT and the application of at least a pressure
threshold onto the first obturating member.
20. The wellbore servicing method of claim 19, wherein the PCVT
transitions from the second configuration to the third
configuration upon the introduction of a second obturating member
within the PCVT and the application of at least a pressure
threshold onto the second obturating member.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
REFERENCE TO A MICROFICHE APPENDIX
[0003] Not applicable.
BACKGROUND
[0004] Hydrocarbon-producing wells often are stimulated by
hydraulic fracturing operations, during which a servicing fluid
such as a fracturing fluid or a perforating fluid may be introduced
into a portion of a subterranean formation penetrated by a wellbore
at a hydraulic pressure sufficient to create or enhance at least
one fracture therein. Such a subterranean formation stimulation
treatment may increase hydrocarbon production from the well.
[0005] A work string (e.g., tool string, coiled tubing string,
and/or segmented tool string) is often used to communicate fluid to
and from the subterranean formation, for example, during a wellbore
stimulation (e.g., a hydraulic fracturing) operation. For example,
jointed tubing may be used to form at least a portion of the work
string. Additionally or alternatively, coiled tubing may also be
used to form at least a portion of the work string.
[0006] Sometimes, during the performance of a wellbore servicing
operation, it may be desirable to fluidicly isolate two or more
sections of the work string (e.g. between a coiled tubing string
and a jointed tubing string), for example, so as to close off fluid
and/or pressure communication through the work string flowbore in
at least one direction. For example, closing off fluid
communication through a work string flowbore may allow, as an
example, for the isolation of well pressure within the work string
flowbore during run-in and/or run-out of a work string (e.g.,
facilitating connection and/or disconnection of one or more work
string sections, such as a jointed tubing section and a coiled
tubing section, two or more sections of jointed tubing, or
combinations thereof). As such, there is a need for apparatuses,
system, and methods of selectively allowing and/or preventing fluid
communication through the flowbore of a work string during the
performance of a wellbore servicing operation.
SUMMARY
[0007] Disclosed herein is a wellbore servicing system comprising a
work string, and a pressure control valve tool incorporated within
the work string and comprising a housing generally defining an
axial flowbore, a flapper valve disposed within the axial flowbore
and configurable between an activated state and an inactivated
state, wherein, in the activated state the flapper valve is free to
move between a closed position in which the flapper valve blocks
the axial flowbore and an open position in which the flapper valve
does not block the axial flowbore, and wherein, in the inactivated
state the flapper valve is retained in the open position, a first
sleeve slidably positioned within the housing and transitional from
a first position to a second position with respect to the housing,
and a second sleeve slidably positioned within the first sleeve and
transitional from a first position to a second position with
respect to the first sleeve, wherein, when the first sleeve is in
the first position with respect to the housing and the second
sleeve is in the first position with respect to the first sleeve,
the flapper valve is in the activated state, wherein, when the
first sleeve is in the second position with respect to the housing
and the second sleeve is in the first position with respect to the
first sleeve, the flapper valve is in the inactivated state,
wherein, when the first sleeve is in the second position with
respect to the housing and the second sleeve is in the second
position with respect to the first sleeve, the flapper valve is in
the activated state, and wherein, engagement of a first obturating
member with the first sleeve and the application of a pressure of
at least a threshold pressure onto the first obturating member
causes the first sleeve to transition from the first position to
the second position with respect to the housing and such that the
engagement of a second obturating member with the second sleeve and
the application of a pressure of at least a threshold pressure onto
the second obturating member causes the second sleeve to transition
from the first position to the second position with respect to the
first sleeve.
[0008] Also disclosed herein is a wellbore servicing method
comprising positioning a work string comprising a pressure control
valve tool (PCVT) in a first configuration incorporated therein
within a wellbore, wherein in the first configuration the PCVT
provides unidirectional fluid flow through the work string,
introducing of a first obturating member within the PCVT and
applying at least a pressure threshold onto the first obturating
member thereby allowing bidirectional fluid communication through
the work string, introducing of a second obturating member within
the PCVT and applying of at least a pressure threshold onto the
second obturating member thereby allowing unidirectional fluid
communication, removing the working string comprising the PCVT from
the wellbore.
[0009] Further disclosed herein is a wellbore servicing method
comprising positioning a work string comprising a pressure control
valve tool (PCVT) in a first configuration incorporated therein
within a wellbore, wherein, the PCVT is configurable from the first
configuration to a second configuration and from the second
configuration to a third configuration, wherein, when the PCVT is
in the first configuration, the PCVT is configured to allow a route
of fluid communication in a down-hole direction and to disallow a
route of fluid in an up-hole direction via the PCVT, wherein, when
the PCVT is in the second configuration, the PCVT is configured to
allow bidirectional fluid communication via the PCVT, and wherein,
when the PCVT is in the third configuration, the PCVT is configured
to allow a route of fluid communication in a down-hole direction
and to disallow a route of fluid in an up-hole direction via the
PCVT, transitioning the PCVT from the first configuration to the
second configuration thereby allowing bidirectional fluid
communication through the work string, transitioning the PCVT from
the second configuration to the third configuration thereby
allowing unidirectional fluid communication, and removing the
working string comprising the PCVT from the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] For a more complete understanding of the present disclosure
and the advantages thereof, reference is now made to the following
brief description, taken in connection with the accompanying
drawings and detailed description:
[0011] FIG. 1 is a partial cutaway view of an embodiment of an
operating environment associated with a pressure control valve
tool;
[0012] FIG. 2 is a cutaway view of an embodiment of a pressure
control valve tool in a first configuration;
[0013] FIG. 3 is a cutaway view of another embodiment of a pressure
control valve tool in a first configuration;
[0014] FIG. 4 is a partial cutaway view of an embodiment of a
pressure control valve tool in a first configuration;
[0015] FIG. 5 is a cutaway view of an embodiment of a pressure
control valve tool in a second configuration comprising a first
obturating member;
[0016] FIG. 6 is a cutaway view of an embodiment of a pressure
control valve tool in a second configuration;
[0017] FIG. 7 is a cutaway view of an embodiment of a pressure
control valve tool in a second configuration comprising a second
obturating member; and
[0018] FIG. 8 is a cutaway of an embodiment of a pressure control
valve tool in a third configuration.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0019] In the drawings and description that follow, like parts are
typically marked throughout the specification and drawings with the
same reference numerals, respectively. In addition, similar
reference numerals may refer to similar components in different
embodiments disclosed herein. The drawing figures are not
necessarily to scale. Certain features of the invention may be
shown exaggerated in scale or in somewhat schematic form and some
details of conventional elements may not be shown in the interest
of clarity and conciseness. The present invention is susceptible to
embodiments of different forms. Specific embodiments are described
in detail and are shown in the drawings, with the understanding
that the present disclosure is not intended to limit the invention
to the embodiments illustrated and described herein. It is to be
fully recognized that the different teachings of the embodiments
discussed herein may be employed separately or in any suitable
combination to produce desired results.
[0020] Unless otherwise specified, use of the terms "connect,"
"engage," "couple," "attach," or any other like term describing an
interaction between elements is not meant to limit the interaction
to direct interaction between the elements and may also include
indirect interaction between the elements described.
[0021] Unless otherwise specified, use of the terms "up," "upper,"
"upward," "up-hole," "upstream," or other like terms shall be
construed as generally from the formation toward the surface or
toward the surface of a body of water; likewise, use of "down,"
"lower," "downward," "down-hole," "downstream," or other like terms
shall be construed as generally into the formation away from the
surface or away from the surface of a body of water, regardless of
the wellbore orientation. Use of any one or more of the foregoing
terms shall not be construed as denoting positions along a
perfectly vertical axis.
[0022] Unless otherwise specified, use of the term "subterranean
formation" shall be construed as encompassing both areas below
exposed earth and areas below earth covered by water such as ocean
or fresh water.
[0023] Disclosed herein are embodiments of wellbore servicing
apparatuses, systems and methods of using the same. Particularly
disclosed herein are one or more embodiments of a pressure control
valve tool (PCVT), systems, and methods utilizing the same. In one
or more of the embodiments as will be disclosed herein, the PCVT
may be generally configured to selectively transition through one
or more configurations so as to selectively allow and/or disallow
fluid communication through a tubular string (e.g., a work string)
in one or both directions, for example, during the performance of a
wellbore servicing operation (e.g., a subterranean formation
stimulation operation).
[0024] Referring to FIG. 1, an embodiment of an operating
environment in which such a PCVT and/or a wellbore servicing system
comprising such a PCVT may be employed is illustrated. As depicted
in FIG. 1, the operating environment generally comprises a wellbore
114 that penetrates a subterranean formation 102 for the purpose of
recovering hydrocarbons, storing hydrocarbons, disposing of carbon
dioxide, or the like. The wellbore 114 may be drilled into the
subterranean formation 102 using any suitable drilling technique.
In an embodiment, a drilling or servicing rig 106 disposed at the
surface 104 comprises a derrick 108 with a rig floor 110 through
which a work string (e.g., a drill string, a tool string, a
segmented tubing string, a jointed tubing string, or any other
suitable conveyance, or combinations thereof) generally defining an
axial flow bore 126 may be positioned within or partially within
wellbore 114. In an embodiment, such a work string may comprise two
or more concentrically positioned strings of pipe or tubing (e.g.,
a first work string may be positioned within a second work string).
The drilling or servicing rig may be conventional and may comprise
a motor driven winch and other associated equipment for lowering
the work string into wellbore 114. Alternatively, a mobile workover
rig, a wellbore servicing unit (e.g., coiled tubing units), or the
like may be used to lower the work string into the wellbore 114. In
such an embodiment, the work string may be utilized in drilling,
stimulating, completing, or otherwise servicing the wellbore, or
combinations thereof.
[0025] The wellbore 114 may extend substantially vertically away
from the earth's surface over a vertical wellbore portion, or may
deviate at any angle from the earth's surface 104 over a deviated
or horizontal wellbore portion 118. In alternative operating
environments, portions or substantially all of wellbore 114 may be
vertical, deviated, horizontal, and/or curved and such wellbore may
be cased, uncased, or combinations thereof. In some instances, at
least a portion of the wellbore 114 may be lined with a casing 120
that is secured into position against the formation 102 in a
conventional manner using cement 122. In this embodiment, the
deviated wellbore portion 118 includes casing 120. However, in
alternative operating environments, the wellbore 114 may be
partially cased and cemented thereby resulting in a portion of the
wellbore 114 being uncased. In an embodiment, a portion of wellbore
114 may remain uncemented, but may employ one or more packers
(e.g., mechanical and/or swellable packers, such as
Swellpackers.TM., commercially available from Halliburton Energy
Services, Inc.) to isolate two or more adjacent portions or zones
within wellbore 114. It is noted that although some of the figures
may exemplify a horizontal or vertical wellbore, the principles of
the apparatuses, systems, and methods disclosed may be similarly
applicable to horizontal wellbore configurations, conventional
vertical wellbore configurations, and combinations thereof.
Therefore, the horizontal or vertical nature of any figure is not
to be construed as limiting the wellbore to any particular
configuration.
[0026] Referring to FIG. 1, a wellbore servicing system 100 is
illustrated. In the embodiment of FIG. 1, the wellbore servicing
system 100 comprises a PCVT 200 incorporated with a work string 112
and positioned within the wellbore 114. Additionally, in an
embodiment the wellbore servicing system 100 may further comprise a
wellbore servicing tool 150. In such an embodiment, the wellbore
servicing tool 150 may be incorporated within the work string 112,
for example, at a position relatively downhole from the PCVT 200.
Also, in such an embodiment, the work string 112 may be positioned
within the wellbore 114 such that the wellbore servicing tool 150
is positioned proximate and/or substantially adjacent to one or
more zones of the subterranean formation 102.
[0027] The wellbore servicing tool 150 may be generally configured
to deliver a wellbore servicing fluid to the wellbore 114, the
subterranean formation 102 and/or one or more zones thereof, for
example, for the performance of one or more servicing operations.
For example, the wellbore servicing tool 150 may generally comprise
a stimulation tool (such as a fracturing, perforating tool, and/or
acidizing tool), a drilling tool (such as a drill bit), a wellbore
cleanout tool, or combinations thereof. While this disclosure may
refer to a wellbore servicing tool 150 configured for a stimulation
operation (e.g., a perforating and/or fracturing tool), as
disclosed herein, a wellbore servicing tool incorporated with the
wellbore servicing system may be configured for various additional
or alternative operations and, as such, this disclosure should not
be construed as limited to utilization in any particular wellbore
servicing context unless so-designated. In an embodiment, the
wellbore servicing tool 150 may be selectively actuatable, for
example, being configured to provide or not provide a route of
fluid communication from the wellbore servicing tool 150 to the
wellbore 114, the subterranean formation 102, and/or a zone
thereof. In such an embodiment, the wellbore servicing tool 150 may
be configured for actuation via the application of fluid pressure
to the wellbore servicing tool 150, via the operation of a ball or
dart, via the operation of a shifting tool (e.g., a wireline tool),
or combinations thereof, as will be appreciated by one of skill in
the art upon viewing this application. Although the embodiment of
FIG. 1 illustrates a single wellbore servicing tool 150 (e.g.,
being positioned substantially proximate or adjacent to a
formation), one of skill in the art viewing this disclosure will
appreciate that any suitable number of wellbore servicing tools may
be similarly incorporated within a work string 112, for example, 2,
3, 4, 5, 6, 7, 8, 9, 10, etc. wellbore servicing tools.
[0028] In the embodiment of FIG. 1, the work string 112 comprises
at least one segment of jointed tubing 20 (e.g., a "joint"). For
example, in the embodiment of FIG. 1, the jointed tubing 20 may be
coupled to the PCVT 200 and may comprise a portion of the work
string 112 relatively downhole from the PCVT 200. Not intending to
be bound by theory, the jointed tubing 20 may provide a relatively
strong, reliable work string flowbore 126 at the location of the
stimulation operation. For example, the wellbore servicing tool 150
may be incorporated within the jointed tubing 20 portion of the
work string 112. Additionally, in an embodiment, the wellbore
servicing system 100 may further comprise at least one segment of
coiled tubing 80. For example, in the embodiment of FIG. 1, the
coiled tubing 80 may be coupled to the PCVT 200 and may comprise a
portion of the work string 112 relatively uphole from the valve
tool 200. Not intending to be bound by theory, the coiled tubing 80
may allow for the work string 112 to be quickly and easily moved
uphole or downhole within the wellbore 114 (e.g., to be quickly and
easily "run-in" or "run-out" of the wellbore 114). While in the
embodiment of FIG. 1, jointed tubing 20 is coupled to and located
downhole from the PCVT 200 and coiled tubing 80 is coupled to and
located uphole from the PCVT 200, in other embodiments, various
suitable additional or alternative configurations may be similarly
employed. For example, in alternative embodiments, jointed tubing
20 may be located uphole from the PCVT 200 and/or coiled tubing 80
may be located downhole from the valve tool 200. Furthermore, in
yet another embodiment, the jointed tubing 20 or coiled tubing 80
may be located both uphole and downhole from the PCVT 200 (e.g.,
comprising substantially all of the work string 112).
[0029] Additionally, although the embodiment of FIG. 1 illustrates
a wellbore servicing system 100 comprising the PCVT 200
incorporated within a work string 112, a similar wellbore servicing
system may be similarly incorporated within any other suitable type
of string (e.g., a drill string, a tool string, a segmented tubing
string, a jointed tubing string, a casing string, a coiled-tubing
string, or any other suitable conveyance, or combinations thereof),
working environment, or configuration, as may be appropriate for a
given servicing operation. Also, although the embodiment of FIG. 1
illustrates a single PCVT 200, one of skill in the art viewing this
disclosure will appreciate that any suitable number of PCVTs, as
will be disclosed herein, may be similarly incorporated within a
work string 112, for example, 2, 3, 4, 5, etc. PCVTs.
[0030] In one or more of the embodiments disclosed herein, one or
more PCVTs 200 may be configured to be activated while disposed
within a wellbore like wellbore 114. In an embodiment, a PCVT 200
may be transitionable from a first configuration to a second
configuration and from the second configuration to a third
configuration.
[0031] Referring to FIG. 2, an embodiment of a PCVT 200 is
illustrated in the first configuration. In an embodiment, when the
PCVT 200 is in the first configuration, also referred to as a
run-in or installation position, the PCVT 200 may be configured so
as to allow for fluid communication therethrough in a first
direction (e.g., downward fluid communication) and to not allow
fluid communication therethrough in a second direction (e.g.,
upward fluid communication), as is described herein. In an
embodiment, as is disclosed herein, the PCVT 200 may be configured
to transition from the first configuration to the second
configuration upon the introduction of a first obturating member to
the flowbore of the PCVT 200 and the application of a pressure of
at least a threshold pressure to the first obturating member and/or
the flowbore of the PCVT 200, as will be disclosed herein. For
example, the PCVT 200 may be configured to transition from the
first configuration to the second configuration upon experiencing
an application of a threshold pressure onto the first obturating
member. In such an embodiment, the threshold pressure may be at
least about 500 psi, alternatively, about 750 psi, alternatively,
about 1,000 psi, alternatively, about 1,500 psi, alternatively,
about 2,000 psi, alternatively, about 2,500 psi, alternatively,
about 3,000 psi, alternatively, about 4,000 psi, alternatively,
about 5,000 psi, alternatively, about 6,000 psi, alternatively,
about 7,000 psi, alternatively, about 8,000 psi, alternatively,
about 10,000 psi, alternatively, alternatively, about 12,000 psi,
alternatively, about 14,000 psi, alternatively, about 16,000 psi,
alternatively, about 18,000 psi, alternatively, about 20,000 psi,
alternatively, any suitable pressure. As will be appreciated by one
of skill in the art upon viewing this disclosure, the threshold
pressure may depend upon various factors, for example, including,
but not limited to, the type of wellbore servicing operation being
implemented.
[0032] Referring to FIG. 5, an embodiment of the PCVT 200 is
illustrated in the second configuration. In an embodiment, when the
PCVT 200 is in the second configuration, the PCVT 200 may be
configured so as to allow for fluid communication therethrough in
both the first direction (e.g., downward fluid communication) and
in the second direction (e.g., upward fluid communication), as will
be described herein. In an embodiment, the PCVT 200 may be
configured so as to be retained in the second configuration (e.g.,
via a snap ring, a ratchet, etc.), as will be disclosed herein. In
an embodiment, as will also be disclosed herein, the PCVT 200 may
be configured to transition from the second configuration to the
third configuration upon introducing a second obturating member and
applying a pressure of at least a threshold pressure to the second
obturating member and/or the flowbore of the PCVT 200. For example,
the PCVT 200 may be configured to transition from the second
configuration to the third configuration by applying a pressure to
the PCVT 200 of at least about 500 psi, alternatively, about 750
psi, alternatively, about 1,000 psi, alternatively, about 1,500
psi, alternatively, about 2,000 psi, alternatively, about 2,500
psi, alternatively, about 3,000 psi, alternatively, about 4,000
psi, alternatively, about 5,000 psi, alternatively, about 6,000
psi, alternatively, about 7,000 psi, alternatively, about 8,000
psi, alternatively, about 10,000 psi, alternatively, alternatively,
about 12,000 psi, alternatively, about 14,000 psi, alternatively,
about 16,000 psi, alternatively, about 18,000 psi, alternatively,
about 20,000 psi, alternatively, any suitable pressure. As will be
appreciated by one of skill in the art upon viewing this
disclosure, the threshold pressure may depend upon various factors,
for example, including, but not limited to, the type of wellbore
servicing operation being implemented.
[0033] Referring to FIG. 8, an embodiment of the PCVT 200 is
illustrated in third configuration. In an embodiment, when the PCVT
200 is in the third configuration, also referred to as the pull-out
position, the PCVT 200 may be configured so as to allow for fluid
communication therethrough in a first direction (e.g., downward
fluid communication) and to not allow fluid communication
therethrough in a second direction (e.g., upward fluid
communication), as will be described herein. In an embodiment, the
PCVT 200 may be configured to remain in the third configuration
upon transitioning to the third configuration.
[0034] Referring to FIGS. 2-8, in an embodiment the PCVT 200
generally comprises a housing 210, a first sleeve 206, a second
sleeve 204, and a valve 212. Additionally, the PCVT 200 may also be
characterized as at least a partial continuation of the flowbore
126 of the work string 112. While an embodiment of the PCVT 200 is
disclosed with respect to FIGS. 2-8, one of skill in the art upon
viewing this disclosure, will recognize suitable alternative
configurations. As such, while embodiments of a PCVT may be
disclosed with reference to a given configuration (e.g., PCVT 200
as will be disclosed with respect to FIGS. 2-8), this disclosure
should not be construed as limited to such embodiments.
[0035] In an embodiment, the housing 210 may be characterized as a
generally tubular body having a first terminal end 210a (e.g., an
up-hole end) and a second terminal end 210b (e.g., a down-hole
end), for example as illustrated in FIG. 2. The housing 210 may
also be characterized as generally defining a longitudinal, axial
flowbore 130. In an embodiment, the housing 210 may be configured
for connection to and/or incorporation within a string, such as the
work string 112. For example, the housing 210 may comprise a
suitable means of connection to the work string 112 (such as the
jointed tubing 20 and/or the coiled tubing 80 as illustrated in
FIGS. 2-8). For instance, in an embodiment the first terminal end
210a of the housing 210 may comprise internally and/or externally
threaded surfaces as may be suitably employed in making a threaded
connection to the work string 112 (e.g., to a coiled tubing
segment, such as coiled tubing segment 80, for example, via a
coiled tubing adapter). In an additional or alternative embodiment,
the second terminal end 210b of the housing 210 may also comprise
internally and/or externally threaded surfaces as may be suitably
employed in making a threaded connection to the work string 112
(e.g., to a segment of jointed tubing 20). Alternatively, a PCVT
like PCVT 200 may be incorporated within a work string like work
string 112 by any suitable connection, such as, for example, via
one or more quick-connector type connections. Suitable connections
to a work string member will be known to those of skill in the art
viewing this disclosure. In an embodiment, the PCVT 200 may be
integrated and/or incorporated with the work string 112 such that
the axial flowbore 130 may be in fluid communication with the axial
flowbore 126 defined by work string 112, for example, such that a
fluid communicated via the axial flowbore 126 of the work string
112 will flow into and through the axial flowbore 130 of the PCVT
200.
[0036] In an embodiment, the housing 210 may be configured to allow
one or more sleeves (e.g., the first sleeve 206 and the second
sleeve 204) to be slidably positioned therein. For example, in an
embodiment, the housing may generally comprise a first cylindrical
bore surface 210c and a second cylindrical bore surface 210d. In an
embodiment, the first cylindrical bore surface 210c may generally
define an upper interior portion of the housing 210, for example,
extending from the first terminal end 210a (e.g., an uphole end) of
the housing 210. Additionally, in an embodiment, the second
cylindrical bore surface 210d may generally define an interior
portion of the housing 210 below the first cylindrical bore surface
210c. In an embodiment, the first cylindrical bore surface 210c may
be generally characterized as having a diameter greater than the
diameter of the second cylindrical bore surface 210d.
[0037] Additionally, in an embodiment, the housing 210 may further
comprise a lower contact surface 210e, for example, circumferential
shoulder, protrusion, or lug. In an embodiment, the lower contact
surface 210e may be disposed along a lower interior portion of the
housing 210. In such an embodiment, the lower contact surface 210e
may be configured to restrict and/or substantially restrict the
motion of one or more sleeves in the direction of the second
terminal end 210b (e.g., a lower end), as will be disclosed
herein.
[0038] In an embodiment, the valve 212 may be generally configured,
when activated, as will be disclosed herein, to close and/or seal
the axial flowbore 130 of the PCVT 200 to fluid communication
thereby prohibiting fluid communication in one direction (e.g.,
upward fluid communication) and allowing fluid communication in the
opposite direction (e.g., downward fluid communication). In an
embodiment, the valve 212 may be characterized as one-way or
unidirectional valve, that is, configured to allow fluid
communication therethrough in only a single direction (e.g., when
activated). For example, in an embodiment, the valve 212 may
comprise a flapper valve. In such an embodiment, each of the
activatable flapper valves may comprise a flap or disk movably
(e.g., rotatably) secured within the housing 210 (e.g., directly or
indirectly) via a hinge. In an embodiment, the flapper may be
hinged to the housing 210, alternatively, to a body which may be
disposed within the housing 210. For example, in the embodiments of
FIGS. 2-8, the flapper 212 is hinged to a body 250 disposed within
the interior of the housing 210 and comprises one or more contact
surfaces (e.g., a sliding surface 213 and an upper contact surface
211), for example, for the purpose of engaging one or more sleeves
(e.g., the first sleeve 206 and the second sleeve 204), as will be
disclosed herein. Optionally, in the embodiment where the flapper
is hinged to a body 250 disposed within the housing 210, the body
250 may be retained in a longitudinal position within the housing
210 via one or more positioning members (e.g., one or more spacers
252).
[0039] In an embodiment, the flapper may be rotatable about the
hinge from a first, closed position in which the flapper extends
across the axial flowbore 130 to a second, open position in which
the flapper does not extend across the axial flowbore 130. In an
embodiment, the flapper may be biased, for example, biased toward
the first, closed position via the operation of any suitable
biasing means or member, such as a spring-loaded hinge. In an
embodiment, when the flapper is in the second position, the flapper
may be retained within a recess within the longitudinal bore of the
housing 210, such as a depression (alternatively, a groove,
cut-out, chamber, hollow, or the like). Also, when the flapper is
in the first position, the flapper may protrude into the axial
flowbore 130, for example, so as to sealingly engage or rest
against a seat or sealing surface of the body 250 and/or a portion
of the housing 210 (for example, so as to engage a shoulder, a
mating seat, the like, or combinations thereof). The flapper may be
round, elliptical, or any other suitable shape.
[0040] In an embodiment, as will be disclosed herein, the valve 212
may be activated and/or inactivated through an interaction with the
movement of one or more sleeves (e.g., the first sleeve 206 and the
second sleeve 204). As used herein, reference to the valve 212 as
being in an "activated" state may mean that the valve 212 is free
to move between the first, closed position and the second, open
position. Also, as used herein, reference to the valve 212 as being
in an "inactivated" state may mean that the valve 212 is not free
to move between the first, closed position and the second, open
position.
[0041] In the embodiments illustrated in FIGS. 2 and 4-8, the PCVT
may comprise a single valve. In an embodiment as illustrated in
FIG. 3, the PCVT 200 may comprise two valves (e.g., a first valve
212a and a second valve 212b), in alternative embodiments, an PCVT
may similarly comprise three valves, alternatively, four valves,
alternatively, any suitable number of valves.
[0042] In an embodiment, the first sleeve 206 and/or the second
sleeve 204 may generally comprise concentric cylindrical or tubular
structures. Referring to FIG. 4, in an embodiment, the first sleeve
206 may comprise a first contact surface 206a, a second contact
surface 206b, an outer cylindrical surface 206c, and an inner bore
surface 206d. In such an embodiment, the first sleeve 206 may be
positioned such that the outer cylindrical surface 206c is slidably
fitted against at least a portion of an interior bore surface
(e.g., the first cylindrical bore surface 210c) of the housing 210
in a fluid-tight or substantially fluid-tight manner. Additionally,
the first sleeve 206 may further comprise one more suitable seals
(e.g., an O-ring, a T-seal, a snap ring, a gasket, etc.) disposed
along the outer cylindrical surface 206c of the first sleeve 206,
for example, for the purpose of prohibiting and/or restricting
fluid movement via such an interface. In an embodiment, the second
sleeve 204 may comprise a first contact surface 204a, a second
contact surface 204c, and an outer cylindrical surface 204b. In an
embodiment, the diameter of the outer cylindrical surface 204b may
be less than the diameter of the of the inner bore surface 206d of
the first sleeve 206, the second cylindrical bore surface 210d of
the housing 210, and the sliding surface 213 of the flapper, if
present. Additionally, the second sleeve 204 may further comprise
one more suitable seals (e.g., an O-ring, a T-seal, a snap ring, a
gasket, etc.) disposed along the outer cylindrical surface 204b of
the second sleeve 204, for example, for the purpose of prohibiting
and/or restricting fluid movement via such an interface.
[0043] Referring to the embodiments of FIGS. 2-8, the first sleeve
206 and/or the second sleeve 204 may each be slidably positioned
within the housing 210. For example, the first sleeve 206 and the
second sleeve 204 may each be slidably movable between various
longitudinal positions with respect to the housing 210 and/or with
respect to each other. Additionally, the relative longitudinal
position of the first sleeve 206 and/or the second sleeve 204 may
determine if the one or more valves are in the first position or
the second position and/or in an activated state or an inactivated
state.
[0044] Referring to the embodiment of FIGS. 2-4, when the PCVT 200
is configured in the first configuration, the first sleeve 206 is
in a first position with respect to the housing 210. In such an
embodiment, the first sleeve 206 may be coupled to the housing 210,
for example, via a shear pin, a snap ring, etc., for example, such
that the first sleeve 206 is fixed relative to the housing 210. For
example, in the embodiments of FIGS. 2-4, the first sleeve 206 is
coupled to the housing 210 via a shear pin 207. Additionally, in
such an embodiment, the second sleeve 204 may be in a first
position with respect to the first sleeve 206, wherein at least a
portion of the outer cylindrical surface 204b of the second sleeve
204 may be slidably fitted against the inner bore surface 206d of
the first sleeve 206 and may be coupled to the first sleeve 206,
for example, via a shear pin, a snap ring, etc., for example, such
that the second sleeve 204 is fixed relative to the first sleeve
206. For example, in the embodiments of FIGS. 2-4, the second
sleeve 204 is coupled to the first sleeve 206 via a shear pin 208.
Additionally, in such an embodiment, the second sleeve 204 may be
configured and/or positioned such that the first contact surface
204a of the second sleeve 204 is offset from the first contact
surface 206a of the first sleeve 206 away from the first terminal
end 210a (e.g., up-hole end) of the housing 210. For example as
illustrated in FIG. 4, the first sleeve 206 and the second sleeve
204 may be positioned such that an obturating member 202 may engage
the first sleeve 206 and not the second sleeve 204. In an
embodiment, the second sleeve 204 may be configured to selectively
engage the flapper 212 (e.g., via the second contact surface 204c).
Additionally, in such an embodiment, the valve 212 may be
configured to be in the first position (e.g., a closed position)
and/or in an activated state, thereby prohibiting fluid
communication in one direction (e.g., upward fluid communication)
and allowing fluid communication in the opposite direction (e.g.,
downward fluid communication). For example, a fluid may be
communicated in the downward direction (e.g., from the surface to
down-hole) and may not be communicated in the upward direction
(e.g., from down-hole to the surface).
[0045] Referring to the embodiment of FIGS. 5-7, when the PCVT 200
is configured in the second configuration, the first sleeve 206 is
in a second position with respect to the housing 210 and the second
sleeve 204 is in the first position with respect to the first
sleeve 206 (e.g., the second sleeve 204 remains fixed to the first
sleeve 206). In an embodiment, when the first sleeve 206 is in the
second position, the first sleeve 206 may be configured to engage
the upper contact surface 211 of the housing of the flapper 212
and, thereby restricting and/or substantially restricting the first
sleeve 206 from moving longitudinally in the direction of the
second terminal end 210b (e.g., a lower end). In an embodiment,
when the first sleeve 206 is in the second position, the second
sleeve 204 maintains the flapper 212 within a recess within the
longitudinal bore of the housing 210, such as a depression
(alternatively, a groove, cut-out, chamber, hollow, or the like),
which may be provided by the valve body 250. Additionally, in such
an embodiment, the valve 212 may be configured to be in the second
position (e.g., an open position) and/or in an inactivated state,
thereby allowing bidirectional fluid communication via the axial
flowbore 130 of the PCVT 200. In an embodiment, the first sleeve
206 may be retained in the second position with respect to the
housing 210, for example, via a snap ring 209, alternatively, a
ratchet mechanism or a biased pin.
[0046] Referring to the embodiment of FIG. 8, when the PCVT 200 is
configured in the third configuration, the first sleeve 206 is in
the second position with respect to the housing 210 and the second
sleeve 204 is in a second position with respect to the first
sliding sleeve 206. In an embodiment, when the second sleeve 204 is
in the second position, the second sleeve 204 may no longer be
coupled to the first sleeve 206. Also, in the second position, the
second sleeve 204 does not (i.e., no longer) retains the flapper
212 within the recessed chamber of the housing 210. Additionally,
when the second sleeve 204 is in the second position, the second
sleeve 204 may be configured to engage the lower contact surface
210e of the housing 210 and, thereby restricting and/or
substantially restricting from the second sleeve 204 moving
longitudinally in the direction of the second terminal end 210b
(e.g., a lower end). Additionally, in such an embodiment, the valve
212 may be configured to be in the first position (e.g., a closed
position) and/or in an activated state, for example, a fluid may be
communicated in the downward direction (e.g., from the surface to
down-hole) and may not be communicated in the upward direction
(e.g., from down-hole to the surface).
[0047] In an embodiment, the first sleeve 206 and the second sleeve
204 may each be configured so as to be selectively moved downwardly
(e.g., toward the second terminal end 210b). For example, in an
embodiment, the first sleeve 206 and the second sleeve 204 may each
be configured such that when engaged by an obturating member the
application of a fluid and/or hydraulic pressure (e.g., a hydraulic
pressure exceeding a threshold pressure) to the axial flowbore 130
and onto the obturating member will cause the first sleeve 206
and/or the second sleeve 204 to move in the downward direction
(e.g., toward the second terminal end 210b). For example, in such
an embodiment, PCVT 200 may be configured such that following the
engagement of an obturating member by the PCVT 200 (e.g., the first
sleeve or the second sleeve), an application of fluid pressure of
at least the threshold pressure to the axial flowbore 130 (e.g.,
via, the flowbore 126) results in a net hydraulic force applied to
the first sleeve 206 and/or the second sleeve 204 (e.g., via the
obturating member) in the axially downward direction (e.g., in the
direction towards the second terminal end 210b). In such an
embodiment, the force applied to the first sleeve 206 and/or the
second sleeve 204 as a result of the application of such a fluid or
hydraulic pressure to the PCVT 200 may be greater in the axial
direction toward the second terminal end 210b (e.g., downward
forces) than the sum of any forces applied in the opposite axial
direction, for example, in the axial direction toward the first
terminal end 210a (e.g., upward forces).
[0048] For example, in the embodiment of FIG. 2, the first sleeve
206 may be configured to engage a first obturating member 202, for
example, via the first contact surface 206a. In such an embodiment,
the introduction of the first obturating member 202 may configure
the PCVT 200 such that a hydraulic pressure applied to the axial
flowbore 126 will apply a downward force to the first sleeve 206.
Additionally, in such an embodiment, the PCVT 200 may be configured
such that the application of a fluid or hydraulic pressure (e.g., a
fluid or hydraulic pressure exceeding a threshold pressure) to the
axial flowbore 130 onto the first obturating member 202 will cause
the first sleeve 206 to move from the first position to the second
position with respect to the housing 210.
[0049] Additionally, in the embodiment of FIG. 7, the second sleeve
204 may be configured to engage a second obturating member 203, for
example, via the first contact surface 204a. In such an embodiment,
the introduction of the second obturating member 203 may configure
the PCVT 200 such that a hydraulic pressure applied to the axial
flowbore 126 will apply a downward force to the second sleeve 206.
Additionally, in such an embodiment, the PCVT 200 may be configured
such that the application of a fluid or hydraulic pressure (e.g., a
fluid or hydraulic pressure exceeding a threshold pressure) to the
axial flowbore 130 onto the second obturating member 203 will cause
the second sleeve 204 to move from the first position to the second
position with respect to the first sleeve 206.
[0050] While one or more of the embodiments disclosed herein may
refer to the movement of one or more sleeves as a result of the
application of a given fluid pressure, it is contemplated that a
given PCVT may be configured for movement via any other suitable
method, apparatus, or system, as would be appreciated by one of
ordinary skill in the art upon viewing this disclosure.
[0051] One or more of embodiments of a PCVT (e.g., such as PCVT
200) and/or a wellbore servicing system (e.g., such as wellbore
servicing system 100) comprising such a PCVT 200 having been
disclosed, one or more embodiments of a wellbore servicing method
employing such a wellbore servicing system 100 and/or such a PCVT
200 are also disclosed herein. In an embodiment, a wellbore
servicing method may generally comprise the steps of positioning a
work string (e.g., such as work string 112) having a PCVT 200
incorporated therein within a wellbore (such as wellbore 114),
actuating the PCVT 200 for bidirectional fluid communications
through the work string 112, further actuating the PCTV 200 for
unidirectional fluid communications through the work string 112,
and removing the PCVT 200 and/or the work string 112.
[0052] As will be disclosed herein, the PCVT 200 may control fluid
movement through the work string 112 during the wellbore servicing
method. For example, as will be disclosed herein, during the step
of positioning the work string 112 within the wellbore 114, the
PCVT 200 may be configured to prohibit fluid communication out of
the wellbore 114 through the work string 112 (e.g., prohibiting
upward fluid communication through the work string 112). Also, for
example, via the step of actuating the PCVT 200 for bidirectional
fluid communicating through the work string 112, the PCVT 200 may
be configured to allow fluid communication through the work string
112 in both directions (e.g., upward and downward fluid
communication), as will disclosed herein. Also, for example, during
the step of actuating the PCTV 200 for unidirectional fluid
communications through the work string 112, the PCTV 200 may be
configured to prohibit fluid communication out of the wellbore 114
through the work string 112 (e.g., prohibiting upward fluid
communication through the work string 112), thereby disallowing
fluid communication through the work string 112 in both directions,
as will be disclosed herein.
[0053] In an embodiment, positioning the work string 112 comprising
the PCVT 200 may comprise forming and/or assembling the components
of the work string 112, for example, as the work string 112 is run
into the wellbore 114. For example, referring to the embodiment of
FIG. 1 where the work string 112 comprises a jointed tubing string
80 located down-hole from the PCVT 200, the jointed tubing segments
may be assembled as the jointed tubing is run-in. In some
embodiments as disclosed herein, a wellbore servicing tool (such as
wellbore servicing tool 150) may be incorporated within the jointed
tubing string, for example, down-hole relative to the PCVT 200. In
the embodiment of FIG. 1, the PCVT 200 is incorporated within the
work string 112 atop the jointed tubing string 80. Referring again
to the embodiment of FIG. 1, the coiled tubing may be attached atop
the PCVT 200, for example, via a suitable coiled tubing adaptor as
would be appreciated by one of ordinary skill in the art upon
viewing this disclosure.
[0054] In an embodiment, the work string 112 may be run into the
wellbore 114 with the PCVT 200 configured in the first
configuration, for example, with the first sleeve 206 in the first
position with respect to the housing 210 and the second sleeve 204
in the first position with respect to the first sleeve 206 as
disclosed herein and as illustrated in the embodiment of FIG. 2 (in
the absence of a first obturating member 202). In such an
embodiment, with the PCVT 200 configured in the first
configuration, the PCVT 200 will not allow upward fluid
communication therethrough (and, as such, will not allow upward
fluid communication through the work string 112) but will allow
downward fluid communication therethrough (and, as such, will allow
downward fluid communication through the work string 112). For
example, as shown in the embodiment of FIG. 2, when the PCVT 200 is
configured in the first configuration the one or more flapper
valves 212 may be activated, that is, free to move into the first,
closed position.
[0055] In an embodiment, the work string 112 may be run into the
wellbore 114 to a desired depth. For example, the work string 112
may be run in such that the wellbore servicing tool 150 is
positioned proximate to one or more desired subterranean formation
zones to be treated (e.g., a first formation zone).
[0056] In an embodiment, actuating the PCVT 200 for bidirectional
fluid communicating through the work string 112 may comprise
transitioning the PCVT 200 from the first configuration to the
second configuration, for example, via transitioning the first
sleeve 206 from the first position to the second position with
respect to the housing 210. In an embodiment, a first obturating
member 202 may be introduced the axial flowbore 130 of the PCVT 200
(e.g., via the axial flowbore 126 of the work string 112) and may
be pumped down-hole to engage the first sleeve 206 (e.g., via the
first contact surface 206a). Additionally, in such an embodiment,
the first obturating member 202 may not engage the first contact
surface 204a of the second sleeve 204. In an embodiment, a fluid or
hydraulic pressure may be applied to the axial flowbore 130 of the
PCVT 200 (e.g., via the axial flowbore 126 of the work string 112)
and onto the first obturating member 202. For example, in an
embodiment, a fluid may be pumped into the axial flowbore 126 of
the work string 112, for example, via one or more pumps generally
located at the earth's surface 104.
[0057] In an embodiment, the application of such a fluid or
hydraulic pressure may be effective to transition the first sleeve
206 from the first position to the second position with respect to
the housing 210. As disclosed herein, the application of fluid or
hydraulic pressure to the PCVT 200 may yield a force in the
direction of the second position. For example, in an embodiment,
the fluid or hydraulic pressure may be of a magnitude sufficient to
exert a force to shear one or more shear pins 207, thereby causing
the first sleeve 206 to move relative to the housing 210 and
transitioning the first sleeve 206 from the first position to the
second position with respect to the housing 210. In an embodiment,
as illustrated in FIG. 5, the first sleeve 206 may continue to move
in the direction of the second position until the second contact
surface 206b of the first sleeve 206 contacts and/or abuts the
upper contact surface 211 of the valve housing, thereby prohibiting
the first sleeve 206 from continuing to slide. In an additional or
alternative embodiment, the first sleeve 206 may comprise one or
more snap rings, alternatively, ratchet teeth, disposed onto the
outer cylindrical surface 206c of the first sleeve 206 which may
engage with a groove or slot on one or more interior surfaces of
the housing 210 (e.g., the first cylindrical bore surface 210c),
thereby prohibiting the first sleeve 206 from continuing to
slide.
[0058] Additionally, in an embodiment following the transition of
the PCVT 200 from the first configuration to the second
configuration, the first obturating member 202 may be removed from
the PCVT 200 and/or the work string 112. For example, in an
embodiment, a suction force may be applied to the axial flowbore
126 of the work string 112 and/or the axial flowbore 130 of the
PCVT 200 (e.g., via a suction tool at the earth's surface 104),
thereby moving (e.g., pulling via reverse flow) the first
obturating member 202 in an uphole direction (e.g., towards the
earth's surface 104) and extracting the first obturating member 202
from the PCVT 200. For example, in an embodiment the first
obturating member 202 may be flowed back to the surface via a
differential pressure between the subterranean formation 102 and
earth's surface 104. In an embodiment as illustrated in FIG. 6,
following the removal of the first obturating member 202, the PCVT
200 may be configured in the second configuration and may allow
bidirectional fluid communication (e.g., between the earth's
surface 104 and the formation 102 via the work string 112) via the
PCVT 200.
[0059] In an embodiment, actuating the PCVT 200 for unidirectional
flow may comprise transitioning the PCVT 200 from the second
configuration to the third configuration, for example, via
transitioning the second sleeve 204 from the first position to the
second position with respect to the first sleeve 206. In an
embodiment as shown in FIG. 7, a second obturating member 203 may
be introduced the axial flowbore 130 of the PCVT 200 (e.g., via the
axial flowbore 126 of the work string 112). In such an embodiment,
the second obturating member 203 may comprise a smaller diameter
than the inner bore surface 206d of the first sleeve 206. In an
embodiment, the second obturating member 203 may engage the second
sleeve 204 (e.g., via the first contact surface 204a) and not the
first contact surface 206a of the first sleeve 206. Additionally,
in an embodiment, a fluid or hydraulic pressure may be applied to
the axial flowbore 130 of the PCVT 200 (e.g., via the axial
flowbore 126 of the work string 112) and onto the second obturating
member 203. For example, in an embodiment, a fluid may be pumped
into the axial flowbore 126 of the work string 112, for example,
via one or more pumps generally located at the earth's surface
104.
[0060] In an embodiment, the application of such a fluid or
hydraulic pressure may be effective to transition the second sleeve
204 from the first position to the second position with respect to
the first sleeve 206. As disclosed herein, the application of fluid
or hydraulic pressure to the PCVT 200 may yield a force in the
direction of the second position. For example, in an embodiment,
the fluid or hydraulic pressure may be of a magnitude sufficient to
exert a force to shear one or more shear pins 208, thereby causing
the second sleeve 204 to move relative to the first sleeve 204
and/or housing 210 and transitioning the second sleeve 204 from the
first position to the second position with respect to the first
sleeve 206. In an embodiment, as illustrated in FIG. 8, the second
sleeve 204 may continue to move in the direction of the second
position until the second contact surface 204c of the second sleeve
204 contacts and/or abuts the lower contact surface 210e of the
housing 210, thereby prohibiting the second sleeve 204 from
continuing to slide. In an additional or alternative embodiment,
the second sleeve 204 may comprise one or more snap rings or
ratchet teeth disposed onto the outer cylindrical surface 204b of
the second sleeve 204 which may engage with a groove or slot on one
or more interior surfaces of the housing 210 (e.g., the second
cylindrical bore surface 210d), thereby prohibiting the second
sleeve 204 from continuing to slide.
[0061] In the embodiment of FIG. 8, the PCVT 200 is configured in
the third configuration, a pull-out position, and thereby disallows
bidirectional fluid communication (e.g., between the earth's
surface 104 and the formation 102 via the work string 112) via the
PCVT 200.
[0062] In an embodiment, and as similarly disclosed herein, the
work string 112 may be removed from the wellbore 114 while the PCVT
200 is configured in the third configuration, for example, with the
first sleeve 206 in the second position with respect to the housing
210 and the second sleeve 204 in the second position with respect
to the first sleeve 206 as disclosed herein and as shown in FIG. 8.
As disclosed herein, in such an embodiment, with the PCVT 200
configured in the third configuration, the PCVT 200 will not allow
upward fluid communication therethrough (and, as such, will not
allow upward fluid communication through the work string 112) but
will allow downward fluid communication therethrough (and, as such,
will allow downward fluid communication through the work string
112).
[0063] Additionally, in an embodiment, the PCVT 200 may be removed
from the work string 112 and serviced or reconfigured to the first
configuration. For example, in an embodiment, during a work string
break down method the PCVT 200 may be removed from the work string
112 (e.g., the coiled tubing 80 and/or jointed tubing 20), the
second obturating member 203 may be removed from the PCVT 200, and
the first sleeve 206 and the second sleeve 204 may be each
reconfigured to their first position, thereby reconfiguring the
PCVT 200 to the first configuration for future wellbore servicing
operations.
[0064] In an embodiment, a PCVT (like PCVT 200), a system utilizing
a PCVT, and/or a method utilizing such a PCVT and/or system a
system may be advantageously employed in the performance of a
wellbore servicing operation. For example, as disclosed herein, the
PCVT allows for an operator to selectively block fluid
communication upwardly through a work string (or other tubular,
wellbore string). As such, a PCVT may be employed to improve safety
in a wellbore/well site environment, for example, by providing a
means of controlling the unintended escape of fluids or pressures
from a wellbore (e.g., when the PCVT is so-configured, as disclosed
herein). Additionally, a PCVT may provide the ability to allow or
disallow bidirectional fluid communication via the PCVT (e.g., via
toggling one or more valves from an activated state to/from an
inactivated state) without the use of wire line tools and/or plugs.
As such, the PCVT may be efficiently transitioned between various
configurations, as disclosed herein, via the application of a
threshold of pressure applied onto an obturating member disposed
within the PCVT.
ADDITIONAL DISCLOSURE
[0065] The following are nonlimiting, specific embodiments in
accordance with the present disclosure:
[0066] A first embodiment, which is a wellbore servicing system
comprising:
[0067] a work string; and
[0068] a pressure control valve tool incorporated within the work
string and comprising: [0069] a housing generally defining an axial
flowbore; [0070] a flapper valve disposed within the axial flowbore
and configurable between an activated state and an inactivated
state;
[0071] wherein, in the activated state the flapper valve is free to
move between a closed position in which the flapper valve blocks
the axial flowbore and an open position in which the flapper valve
does not block the axial flowbore; and
[0072] wherein, in the inactivated state the flapper valve is
retained in the open position;
a first sleeve slidably positioned within the housing and
transitional from a first position to a second position with
respect to the housing; and a second sleeve slidably positioned
within the first sleeve and transitional from a first position to a
second position with respect to the first sleeve;
[0073] wherein, when the first sleeve is in the first position with
respect to the housing and the second sleeve is in the first
position with respect to the first sleeve, the flapper valve is in
the activated state;
[0074] wherein, when the first sleeve is in the second position
with respect to the housing and the second sleeve is in the first
position with respect to the first sleeve, the flapper valve is in
the inactivated state;
[0075] wherein, when the first sleeve is in the second position
with respect to the housing and the second sleeve is in the second
position with respect to the first sleeve, the flapper valve is in
the activated state; and
[0076] wherein, engagement of a first obturating member with the
first sleeve and the application of a pressure of at least a
threshold pressure onto the first obturating member causes the
first sleeve to transition from the first position to the second
position with respect to the housing and such that the engagement
of a second obturating member with the second sleeve and the
application of a pressure of at least a threshold pressure onto the
second obturating member causes the second sleeve to transition
from the first position to the second position with respect to the
first sleeve.
[0077] A second embodiment, which is the wellbore servicing system
of the first embodiment, wherein when the first sleeve is in the
first position, the first sleeve is releasably coupled to the
housing via a first retaining device comprising a shear pin, a snap
ring, a biased pin, or combinations thereof.
[0078] A third embodiment, which is the wellbore servicing system
of the second embodiment, wherein when the first sleeve is in the
second position, the first sleeve is coupled to the housing via a
snap ring.
[0079] A fourth embodiment, which is the wellbore servicing system
of on of the first through the third embodiments, wherein when the
second sleeve is in the first position, the second sleeve is
releasably coupled to the first sleeve via a second retaining
device comprising a shear pin, a snap ring, a biased pin, or
combinations thereof.
[0080] A fifth embodiment, which is the wellbore servicing system
of the fourth embodiment, wherein when the second sleeve is in the
second position, the second sleeve is not coupled to the first
sleeve.
[0081] A sixth embodiment, which is the wellbore servicing system
of one of the first through the fifth embodiments, wherein the
first obturating member may be sized to engage the first sleeve and
not the second sleeve.
[0082] A seventh embodiment, which is the wellbore servicing system
of the sixth embodiment, wherein the second obturating member may
be sized to engage the second sleeve and not the first sleeve.
[0083] An eighth embodiment, which is the wellbore servicing system
of one of the first through the seventh embodiments, wherein the
pressure control valve tool comprises two or more flapper valves
disposed within the axial flowbore and configurable between the
activated state and the inactivated state.
[0084] A ninth embodiment, which is a wellbore servicing method
comprising:
[0085] positioning a work string comprising a pressure control
valve tool (PCVT) in a first configuration incorporated therein
within a wellbore, wherein in the first configuration the PCVT
provides unidirectional fluid flow through the work string;
introducing of a first obturating member within the PCVT and
appyling at least a pressure threshold onto the first obturating
member thereby allowing bidirectional fluid communication through
the work string;
[0086] introducing of a second obturating member within the PCVT
and applying of at least a pressure threshold onto the second
obturating member thereby allowing unidirectional fluid
communication;
[0087] removing the working string comprising the PCVT from the
wellbore.
[0088] A tenth embodiment, which is the wellbore servicing method
of the ninth embodiment, wherein the PCVT further comprises:
[0089] a housing generally defining an axial flowbore;
[0090] a flapper valve disposed within the axial flowbore and
configurable between an activated state and an inactivated
state;
[0091] wherein, in the activated state the flapper valve is free to
move between a closed position in which the flapper valve blocks
the axial flowbore and an open position in which the flapper valve
does not block the axial flowbore; and
[0092] wherein, in the inactivated state the flapper valve is
retained in the open position;
a first sleeve slidably positioned within the housing and
transitional from a first position to a second position with
respect to the housing; and a second sleeve slidably positioned
within the first sleeve and transitional from a first position to a
second position with respect to the first sleeve;
[0093] wherein, when the first sleeve is in the first position with
respect to the housing and the second sleeve is in the first
position with respect to the first sleeve, the flapper valve is in
the activated state;
[0094] wherein, when the first sleeve is in the second position
with respect to the housing and the second sleeve is in the first
position with respect to the first sleeve, the flapper valve is in
the inactivated state;
[0095] wherein, when the first sleeve is in the second position
with respect to the housing and the second sleeve is in the second
position with respect to the first sleeve, the flapper valve is in
the activated state; and
[0096] wherein, engagement of a first obturating member with the
first sleeve and the application of a pressure of at least a
threshold pressure onto the first obturating member causes the
first sleeve to transition from the first position to the second
position with respect to the housing and such that the engagement
of a second obturating member with the second sleeve and the
application of a pressure of at least a threshold pressure onto the
second obturating member causes the second sleeve to transition
from the first position to the second position with respect to the
first sleeve.
[0097] An eleventh embodiment, which is the wellbore servicing
method of the tenth embodiment, wherein when the first sleeve is in
the first position, the first sleeve is releasably coupled to the
housing via a first retaining device comprising a shear pin, a snap
ring, a biased pin, or combinations thereof.
[0098] A twelfth embodiment, which is the wellbore servicing method
of the eleventh embodiment, wherein when the first sleeve is in the
second position, the first sleeve is coupled to the housing via a
snap ring.
[0099] A thirteenth embodiment, which is the wellbore servicing
method of one of the tenth through the eleventh embodiments,
wherein when the second sleeve is in the first position, the second
sleeve is releasably coupled to the first sleeve via second
retaining device comprising a shear pin, a snap ring, a biased pin,
or combinations thereof.
[0100] A fourteenth embodiment, which is the wellbore servicing
method of the thirteenth embodiment, wherein when the second sleeve
is in the second position, the second sleeve is not coupled to the
first sleeve.
[0101] A fifteenth embodiment, which is the wellbore servicing
method of the fourteenth embodiment, wherein the first obturating
member may be sized to engage the first sleeve and not the second
sleeve.
[0102] A sixteenth embodiment, which is the wellbore servicing
method of the fifteenth embodiment, wherein the second obturating
member may be sized to engage the second sleeve and not the first
sleeve.
[0103] A seventeenth embodiment, which is the wellbore servicing
method of one of the ninth through the sixteenth embodiments,
wherein the pressure control valve tool comprises two or more
flapper valves disposed within the axial flowbore and configurable
between the activated state and the inactivated state.
[0104] An eighteenth embodiment, which is a wellbore servicing
method comprising:
[0105] positioning a work string comprising a pressure control
valve tool (PCVT) in a first configuration incorporated therein
within a wellbore;
[0106] wherein, the PCVT is configurable from the first
configuration to a second configuration and from the second
configuration to a third configuration;
[0107] wherein, when the PCVT is in the first configuration, the
PCVT is configured to allow a route of fluid communication in a
down-hole direction and to disallow a route of fluid in an up-hole
direction via the PCVT;
[0108] wherein, when the PCVT is in the second configuration, the
PCVT is configured to allow bidirectional fluid communication via
the PCVT; and
[0109] wherein, when the PCVT is in the third configuration, the
PCVT is configured to allow a route of fluid communication in a
down-hole direction and to disallow a route of fluid in an up-hole
direction via the PCVT;
[0110] transitioning the PCVT from the first configuration to the
second configuration thereby allowing bidirectional fluid
communication through the work string;
[0111] transitioning the PCVT from the second configuration to the
third configuration thereby allowing unidirectional fluid
communication; and
removing the working string comprising the PCVT from the
wellbore.
[0112] A nineteenth embodiment, which is the wellbore servicing
method of the eighteenth embodiment, wherein the PCVT transitions
from the first configuration to the second configuration upon the
introduction of a first obturating member within the PCVT and the
application of at least a pressure threshold onto the first
obturating member.
[0113] A twentieth embodiment, which is the wellbore servicing
method of the nineteenth embodiment, wherein the PCVT transitions
from the second configuration to the third configuration upon the
introduction of a second obturating member within the PCVT and the
application of at least a pressure threshold onto the second
obturating member.
[0114] While embodiments of the invention have been shown and
described, modifications thereof can be made by one skilled in the
art without departing from the spirit and teachings of the
invention. The embodiments described herein are exemplary only, and
are not intended to be limiting. Many variations and modifications
of the invention disclosed herein are possible and are within the
scope of the invention. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a
numerical range with a lower limit, Rl, and an upper limit, Ru, is
disclosed, any number falling within the range is specifically
disclosed. In particular, the following numbers within the range
are specifically disclosed: R=Rl+k*(Ru-Rl), wherein k is a variable
ranging from 1 percent to 100 percent with a 1 percent increment,
i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, .
. . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96
percent, 97 percent, 98 percent, 99 percent, or 100 percent.
Moreover, any numerical range defined by two R numbers as defined
in the above is also specifically disclosed. Use of the term
"optionally" with respect to any element of a claim is intended to
mean that the subject element is required, or alternatively, is not
required. Both alternatives are intended to be within the scope of
the claim. Use of broader terms such as comprises, includes,
having, etc. should be understood to provide support for narrower
terms such as consisting of, consisting essentially of, comprised
substantially of, etc.
[0115] Accordingly, the scope of protection is not limited by the
description set out above but is only limited by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. Each and every claim is incorporated into the
specification as an embodiment of the present invention. Thus, the
claims are a further description and are an addition to the
embodiments of the present invention. The discussion of a reference
in the Detailed Description of the Embodiments is not an admission
that it is prior art to the present invention, especially any
reference that may have a publication date after the priority date
of this application. The disclosures of all patents, patent
applications, and publications cited herein are hereby incorporated
by reference, to the extent that they provide exemplary, procedural
or other details supplementary to those set forth herein.
* * * * *